

[Federal Register: March 15, 2007 (Volume 72, Number 50)]
[Rules and Regulations]               
[Page 12265-12531]
From the Federal Register Online via GPO Access [wais.access.gpo.gov]
[DOCID:fr15mr07-22]                         
 

[[Page 12265]]

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Part II





Department of Energy





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Federal Energy Regulatory Commission



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18 CFR Parts 35 and 37



Preventing Undue Discrimination and Preference in Transmission Service; 
Final Rule


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DEPARTMENT OF ENERGY

Federal Energy Regulatory Commission

18 CFR Parts 35 and 37

[Docket Nos. RM05-17-000 and RM05-25-000; Order No. 890]

 
Preventing Undue Discrimination and Preference in Transmission 
Service

Issued February 16, 2007.

AGENCY: Federal Energy Regulatory Commission, DOE.

ACTION: Final rule.

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SUMMARY: The Federal Energy Regulatory Commission is amending the 
regulations and the pro forma open access transmission tariff adopted 
in Order Nos. 888 and 889 to ensure that transmission services are 
provided on a basis that is just, reasonable and not unduly 
discriminatory or preferential. The final rule is designed to: 
Strengthen the pro forma open-access transmission tariff, or OATT, to 
ensure that it achieves its original purpose of remedying undue 
discrimination; provide greater specificity to reduce opportunities for 
undue discrimination and facilitate the Commission's enforcement; and 
increase transparency in the rules applicable to planning and use of 
the transmission system.

EFFECTIVE DATE: This rule will become effective May 14, 2007.

FOR FURTHER INFORMATION CONTACT: Daniel Hedberg (Technical 
Information), Office of Energy Markets and Reliability, Federal Energy 
Regulatory Commission, 888 First Street, NE., Washington, DC 20426, 
(202) 502-6243.
    W. Mason Emnett (Legal Information), Office of the General 
Counsel--Energy Markets, Federal Energy Regulatory Commission, 888 
First Street, NE., Washington, DC 20426, (202) 502-6540.
    Kathleen Barr[oacute]n (Legal Information), Office of the General 
Counsel--Energy Markets, Federal Energy Regulatory Commission, 888 
First Street, NE., Washington, DC 20426, (202) 502-6461.

SUPPLEMENTARY INFORMATION: 


                                                               Paragraph
                      Table of Contents                          Nos.

I. Introduction.............................................           1
II. Background..............................................           9
    A. Historical Antecedent................................           9
    B. Order No. 888 and Subsequent Reforms.................          14
    C. EPAct 2005 and Recent Developments...................          22
III. Need for Reform of Order No. 888.......................          26
    A. Opportunities for Undue Discrimination Continue to             26
     Exist..................................................
    B. Lack of Transparency Undermines Confidence in Open             44
     Access and Impedes Enforcement of Open Access
     Requirements...........................................
    C. Congestion and Inadequate Infrastructure Development           52
     Impede Customers' Use of the Grid......................
    D. A Consistent Method of Measuring ATC Is Needed.......          62
    E. Discriminatory Pricing of Imbalances.................          70
    F. Redispatch/Conditional Firm..........................          73
    G. EPAct 2005 Emphasized Certain Policies and Priorities          79
     for the Commission.....................................
IV. Summary, Scope and Applicability of the Final Rule......          82
    A. Summary of Reforms...................................          83
    B. Core Elements of Order No. 888 That Are Retained.....          91
        1. Federal/State Jurisdiction.......................          92
        2. Native Load Protection...........................          95
        3. The Types of Transmission Services Offered.......         110
        4. Functional Unbundling............................         117
    C. Applicability of the Final Rule......................         124
        1. Non-ISO/RTO Public Utility Transmission Providers         124
        2. ISO and RTO Public Utility Transmission Providers         143
         and Transmission Owner Members of ISOs and RTOs....
        3. Non-Public Utility Transmission Providers/                162
         Reciprocity........................................
V. Reforms of the OATT......................................         193
    A. Consistency and Transparency of ATC Calculations.....         193
    B. Coordinated, Open and Transparent Planning...........         418
    C. Transmission Pricing.................................         603
        1. General..........................................         603
        2. Energy and Generation Imbalances.................         627
        3. Credits for Network Customers....................         729
        4. Capacity Reassignment............................         778
        5. ``Operational'' Penalties........................         826
            a. Unreserved Use Penalties.....................         826
            b. Distribution of Operational Penalties........         850
            c. Applicability of Operational Penalties                866
             Proposal to RTOs and Other Independent or Non-
             Profit Entities................................
        6. ``Higher of'' Pricing Policy.....................         870
        7. Other Ancillary Services.........................         886
    D. Non-Rate Terms and Conditions........................         901
        1. Modifications to Long-Term Firm Point-to-Point            901
         Service............................................
            a. Planning Redispatch and Conditional Firm              901
             Options........................................
            b. Proposals for Transparent Redispatch.........        1095
            c. Other Requested Service Modifications........        1165
        2. Hourly Firm Service..............................        1177
        3. Rollover Rights..................................        1214
        4. Modification of Receipt or Delivery Points.......        1268
        5. Acquisition of Transmission Service..............        1296
            a. Processing of Service Requests...............        1296
            b. Reservation Priority.........................        1394
        6. Designation of Network Resources.................        1432
            a. Qualification as a Network Resource..........        1432

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            b. Documentation for Network Resources..........        1507
            c. Undesignation of Network Resources...........        1534
        7. Clarifications Related to Network Service........        1592
            a. Secondary Network Service....................        1592
            b. Behind the Meter Generation..................        1614
        8. Transmission Curtailments........................        1620
        9. Standardization of Rules and Practices...........        1633
            a. Business Practices...........................        1633
            b. Liability and Indemnification................        1662
        10. OATT Definitions................................        1678
    E. Enforcement..........................................        1714
        1. General Policy...................................        1715
        2. Civil Penalties..................................        1724
VI. Information Collection Statement........................        1752
VII. Environmental Analysis.................................        1758
VIII. Regulatory Flexibility Act Analysis...................        1759
IX. Document Availability...................................        1760
X. Effective Date and Congressional Notification............        1763
Appendix A: Summary of Compliance Filing Requirements
Appendix B: Commenting Party Acronyms
Appendix C: Pro Forma Open Access Transmission Tariff


Before Commissioners: Joseph T. Kelliher, Chairman; Suedeen G. Kelly, 
Marc Spitzer, Philip D. Moeller, and Jon Wellinghoff.

I. Introduction

    1. This Final Rule addresses and remedies opportunities for undue 
discrimination under the pro forma Open Access Transmission Tariff 
(OATT) adopted in 1996 by Order No. 888.\1\ This landmark rulemaking 
fostered greater competition in wholesale power markets by reducing 
barriers to entry in the provision of transmission service. In the ten 
years since Order No. 888, however, the Commission has found that the 
OATT contains flaws that undermine realizing its core objective of 
remedying undue discrimination. In the Notice of Proposed Rulemaking 
(NOPR) issued on May 19, 2006, the Commission proposed to remedy those 
flaws.\2\ After receiving approximately 6,500 pages of comments from 
close to 300 parties, we now take final action. We highlight below the 
most critical reforms being adopted today.
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    \1\ Promoting Wholesale Competition Through Open Access Non-
discriminatory Transmission Services by Public Utilities; Recovery 
of Stranded Costs by Public Utilities and Transmitting Utilities, 
Order No. 888, 61 FR 21540 (May 10, 1996), FERC Stats. & Regs. Sec.  
31,036 (1996), order on reh'g, Order No. 888-A, 62 FR 12274 (Mar. 
14, 1997), FERC Stats. & Regs. Sec.  31,048 (1997), order on reh'g, 
Order No. 888-B, 81 FERC Sec.  61,248 (1997), order on reh'g, Order 
No. 888-C, 82 FERC Sec.  61,046 (1998), aff'd in relevant part sub 
nom. Transmission Access Policy Study Group v. FERC, 225 F.3d 667 
(D.C. Cir. 2000) (TAPS v. FERC), aff'd sub nom. New York v. FERC, 
535 U.S. 1 (2002).
    \2\ Preventing Undue Discrimination and Preference in 
Transmission Service, Notice of Proposed Rulemaking, 71 FR 32,636 
(Jun. 6, 2006), FERC Stats. & Regs. Sec.  32,603 (2006).
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    2. First, the Final Rule will increase nondiscriminatory access to 
the grid by eliminating the wide discretion that transmission providers 
currently have in calculating available transfer capability (ATC).\3\ 
The calculation of ATC is one of the most critical functions under the 
OATT because it determines whether transmission customers can access 
alternative power supplies. Despite this, the existing OATT does not 
prescribe how ATC should be calculated because the Commission sought to 
rely on voluntary efforts by the industry to develop consistent methods 
of ATC calculation. This voluntary industry effort has not proven 
successful. The Commission therefore acts today to require public 
utilities, working through the North American Electric Reliability 
Corporation (NERC), to develop consistent methodologies for ATC 
calculation and to publish those methodologies to increase 
transparency. This important reform will eliminate the wide discretion 
that exists today in calculating ATC and ensure that customers are 
treated fairly in seeking alternative power supplies.
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    \3\ The Commission used the term ``Available Transmission 
Capability'' in Order No. 888 to describe the amount of additional 
capability available in the transmission network to accommodate 
additional requests for transmission services. To be consistent with 
the term generally accepted throughout the industry, the Commission 
revises the pro forma OATT to adopt the term ``Available Transfer 
Capability.''
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    3. Second, the Final Rule will increase the ability of customers to 
access new generating resources and promote efficient utilization of 
transmission by requiring an open, transparent, and coordinated 
transmission planning process. Transmission planning is a critical 
function under the pro forma OATT because it is the means by which 
customers consider and access new sources of energy and have an 
opportunity to explore the feasibility of non-transmission 
alternatives. Despite this, the existing pro forma OATT provides 
limited guidance regarding how transmission customers are treated in 
the planning process and provides them very little information on how 
transmission plans are developed. These deficiencies are serious, given 
the substantial need for new infrastructure in this Nation.\4\ We act 
today to remedy these deficiencies by requiring transmission providers 
to open their transmission planning process to customers, coordinate 
with customers regarding future system plans, and share necessary 
planning information with customers.
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    \4\ Congress placed special emphasis on the development of 
transmission infrastructure, including the consideration of advanced 
transmission technologies, in the Energy Policy Act of 2005 (EPAct 
2005). See Pub. L. 109-58, 119 Stat. 594 (to be codified in 
scattered titles of the U.S.C.). The Commission has taken steps to 
implement that goal in numerous contexts, including recent 
rulemaking proceedings that address the promotion of transmission 
investment through pricing reform and the siting of certain 
transmission facilities. See Promoting Transmission Investment 
through Pricing Reform, Order No. 679, 71 FR 43294 (Jul. 31, 2006), 
FERC Stats. & Regs. Sec.  31,222 (2006), order on reh'g, Order No. 
679-A, 72 FR 1152 (Jan. 10, 2007), FERC Stats. & Regs. Sec.  31,236 
(2007), reh'g pending; Regulations for Filing Applications for 
Permits to Site Interstate Electric Transmission Facilities, Order 
No. 689, 71 FR 69440 (Dec. 1, 2006), FERC Stats. & Regs. Sec.  
31,234 (2006), reh'g pending. As discussed herein, several actions 
taken in this Final Rule also relate to the need for investments in 
transmission infrastructure and are consistent with the Commission's 
responsibilities under EPAct 2005.
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    4. Third, the Final Rule will also increase the efficient 
utilization of

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transmission by eliminating artificial barriers to use of the grid. The 
existing pro forma OATT allows a transmission provider to deny a 
request for long-term point-to-point service if the request cannot be 
satisfied in only one hour of the requested term. This practice 
discourages the efficient use of the existing grid and precludes access 
to alternative power supplies. We reform this practice by requiring 
that a conditional firm option be offered to customers seeking long-
term point-to-point service, i.e., conditional firm service. We also 
modify the redispatch obligations of transmission providers to increase 
the efficient utilization of the grid, while also ensuring that 
reliability to native load customers is maintained.
    5. Fourth, by adopting these and other reforms, the Final Rule 
facilitates the use of clean energy resources such as wind power. 
Conditional firm service is particularly important to wind resources 
that can provide significant economic and environmental value even if 
curtailed under limited circumstances. Open and coordinated 
transmission planning will enhance the ability of customers to access 
clean energy resources as part of their future resource portfolio. The 
Final Rule also benefits clean energy resources by reforming energy and 
generator imbalance charges. These reforms are particularly important 
to intermittent resources such as wind power because these resources 
have limited ability to control their output and, hence, must be 
assured that imbalance charges are no more than required to provide 
appropriate incentives for prudent behavior.
    6. Fifth, the Final Rule will strengthen compliance and enforcement 
efforts. We are increasing the transparency of pro forma OATT 
administration, thereby increasing the ability of customers and our 
Office of Enforcement to detect undue discrimination. We are adopting 
operational penalties for clear violations of an OATT, thereby 
enhancing compliance while also reducing the burdens on our Office of 
Enforcement. We are also increasing the clarity of many other OATT 
requirements, thereby facilitating compliance by transmission providers 
with our regulations. This Final Rule thus reflects the close 
integration of our Office of Enforcement into policy development at the 
Commission. Several of the reforms we adopt today are informed by our 
experience with OATT administration through oversight, audits, and 
investigations performed by the Office of Enforcement.
    7. Finally, we modify and improve several provisions of the pro 
forma OATT using our experience over the past ten years and clarify 
others that have proven ambiguous. For example, we reform our rollover 
rights policy to ensure that the rights and obligations of rollover 
customers are consistent with the resulting obligations of transmission 
providers to plan and upgrade the system to accommodate rollovers. We 
remove the price cap on reassigned capacity because it is not necessary 
to remedy market power and doing so will otherwise increase the 
efficient use of existing capacity. We increase the efficient use of 
existing capacity by providing a priority to certain ``pre-confirmed'' 
requests for service. We increase certainty by providing greater 
clarity regarding the wholesale contracts that qualify as network 
resources. We also adopt numerous clarifications that should assist 
transmission providers and customers in implementing and using the pro 
forma OATT
    8. Our actions in this proceeding have been informed to a great 
extent by the comments received in response to our notices of inquiry 
in the above-captioned dockets and the subsequent NOPR.\5\ We 
appreciate the time and thoughtfulness of all sectors of the industry 
in preparing comments. We have found them very informative and useful 
in reaching our decisions in this Final Rule.
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    \5\ Preventing Undue Discrimination and Preference in 
Transmission Services, Notice of Inquiry, 112 FERC ] 61,299 (2005) 
(NOI); Information Requirements for Available Transfer Capability, 
Notice of Inquiry, 111 FERC ] 61,274 (2005) (ATC NOI).
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II. Background

A. Historical Antecedent

    9. In the NOPR, the Commission explained the historical background 
that led up to the issuance of Order No. 888, and the initiation of 
this rulemaking proceeding. We repeat that history here to place in 
context the actions we take today.
    10. In the first few decades after enactment of the Federal Power 
Act (FPA) in 1935, the industry was characterized mostly by self-
sufficient, vertically integrated electric utilities, in which 
generation, transmission, and distribution facilities were owned by a 
single entity and sold as part of a bundled service to wholesale and 
retail customers. Most electric utilities built their own power plants 
and transmission systems, entered into interconnection and coordination 
arrangements with neighboring utilities, and entered into long-term 
contracts to make wholesale requirements sales (bundled sales of 
generation and transmission) to municipal, cooperative, and investor-
owned utilities connected to each utility's transmission system. Each 
system covered a limited service area, which was defined by the retail 
franchise decisions of State regulatory agencies. This structure of 
separate systems arose naturally primarily due to cost and the 
technological limitations on the distance over which electricity could 
be transmitted.
    11. A number of statutory, economic, and technological developments 
in the 1970s led to an increase in coordinated operations and 
competition. Among those was the passage of the Public Utility 
Regulatory Policies Act of 1978 (PURPA),\6\ which was designed to 
lessen dependence on foreign fossil fuels by encouraging the 
development of alternative generation sources and imposing a mandatory 
purchase obligation on utilities for generation from such sources. 
PURPA also enabled the Commission to order wheeling of electricity 
under limited circumstances.\7\ The rapid expansion and performance of 
the independent power industry following the enactment of PURPA 
demonstrated that traditional, vertically integrated public utilities 
need not be the only sources of reliable power. During this period, the 
profile of generation investment began to change, and a market for non-
traditional power supply beyond the purchases required by PURPA began 
to emerge. The economic and technological changes in the transmission 
and generation sectors helped encourage many new entrants in the 
generating markets that could sell electric energy profitably with 
smaller scale technology at a lower price than many utilities selling 
from their existing generation facilities at rates reflecting cost. 
However, it became increasingly clear that the potential consumer 
benefits that could be derived from these technological advances could 
be realized only if more efficient generating plants could obtain 
access to the regional transmission grids. Because many traditional 
vertically integrated utilities still did not provide open access to 
third parties and favored their own generation if and when they

[[Page 12269]]

provided transmission access to third parties, access to cheaper, more 
efficient generation sources remained limited.
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    \6\ Pub. L. 95-617, 92 Stat. 3117 (1978) (codified in U.S.C. 
titles 15, 16, 26, 30, 42, and 43).
    \7\ Section 211 of the FPA, 16 U.S.C. 824j. In earlier years, a 
few customers were able to obtain access as a result of litigation, 
beginning with the U.S. Supreme Court's decision in Otter Tail Power 
Company v. United States, 410 U.S. 366 (1973). Additionally, some 
customers gained access by virtue of Nuclear Regulatory Commission 
license conditions and voluntary preference power transmission 
arrangements associated with Federal power marketing agencies. See, 
e.g., Consumers Power Co., 6 NRC 887, 1036-44 (1977); Toledo Edison 
Co., 10 NRC 265, 327-34 (1979); Florida Municipal Power Agency v. 
Florida Power and Light Co., 839 F. Supp. 1563 (M.D. Fla. 1993).
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    12. The Commission encouraged the development of independent power 
producers (IPPs), as well as emerging power marketers, by authorizing 
market-based rates for their power sales on a case-by-case basis, and 
by encouraging more widely available transmission access on a case-by-
case basis. Market-based rates helped to develop competitive bulk power 
markets by allowing generating utilities to move more quickly and 
flexibly to take advantage of short-term or even long-term market 
opportunities than those utilities operating under traditional cost-of-
service tariffs. In approving these market-based rates, the Commission 
required that the seller and its affiliates lack market power or 
mitigate any market power that they may have had.\8\ The major concern 
of the Commission was whether the seller or its affiliates could limit 
competition and thereby drive up prices. A key inquiry became whether 
the seller or its affiliates owned or controlled transmission 
facilities in the relevant service area and therefore, by denying 
access or imposing discriminatory terms or conditions on transmission 
service, could foreclose other generators from competing. Beginning in 
the late 1980s, in order to mitigate their market power to meet the 
Commission's conditions, public utilities seeking Commission 
authorization for blanket approval of market-based rates for generation 
services under section 205 of the FPA filed ``open access'' 
transmission tariffs of general applicability.\9\ The Commission also 
approved proposed mergers under section 203 of the FPA on the condition 
that the merging companies remedy anticompetitive effects potentially 
caused by the merger by filing ``open access'' tariffs. The early 
tariffs submitted in market-based rate proceedings under section 205 
and merger proceedings under section 203 did not, however, provide 
access to the transmission system that was comparable to the service 
the transmission providers used for their own purposes. Rather, they 
typically made available only point-to-point transmission service, 
i.e., service from a single point of receipt to a single point of 
delivery. As these early tariffs were offered only by transmission 
providers that volunteered to provide service to third parties, they 
resulted in a patchwork of open access that was not sufficient to 
facilitate wholesale generation markets.
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    \8\ See, e.g., Dartmouth Power Associates Limited Partnership, 
53 FERC ] 61,117 (1990); Commonwealth Atlantic Limited Partnership, 
51 FERC ] 61,368 (1990); Doswell Limited Partnership, 50 FERC ] 
61,251 (1990); Citizens Power & Light Co., 48 FERC ] 61,210 (1989); 
Ocean State Power, 44 FERC ] 61,261 (1988); and Orange and Rockland 
Utilities, Inc., 42 FERC ] 61,012 (1988).
    \9\ See Order No. 888 at 31,644 n.52.
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    13. In response to the competitive developments following PURPA, 
and the fact that limited transmission access and significant 
regulatory barriers continued to constrain the development of 
generation by independent power producers, Congress enacted Title VII 
of the Energy Policy Act of 1992 (EPAct 1992).\10\ EPAct 1992 reduced 
regulatory barriers to entry by creating a class of ``Exempt Wholesale 
Generators'' that were exempt from the requirements of the Public 
Utility Holding Company Act of 1935.\11\ EPAct 1992 also expanded the 
Commission's authority to approve applications for transmission 
services under sections 211 and 212 of the FPA.\12\ Though the 
Commission aggressively implemented expanded section 211, it ultimately 
concluded that the procedural limitations in section 211 thwarted the 
Commission's ability to effectively eliminate undue discrimination in 
the provision of transmission service.
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    \10\ Pub. L. 102-486, 106 Stat. 2776 (1992) (codified at, among 
other places, 15 U.S.C. 79z-5a and 16 U.S.C. 796 (22-25), 824j-l).
    \11\ 15 U.S.C. 79a, repealed by EPAct 2005 sec. 1263; see Repeal 
of the Public Utility Holding Company Act of 1935 and Enactment of 
the Public Utility Holding Company Act of 2005, Order No. 667, 70 FR 
75592 (Dec. 20, 2005), FERC Stats. & Regs. ] 31,197 (2005), order on 
reh'g, Order No. 667-A, 71 FR 28446 (May 16, 2006), FERC Stats. & 
Regs. ] 31,213 (2006), order on reh'g, Order No. 667-B, 71 FERC 
42750 (Jul. 28, 2006), FERC Stats. & Regs. ] 31,224 (2006), reh'g 
pending.
    \12\ 16 U.S.C. 824j (authorizing the Commission to require 
transmission utilities to provide service in certain circumstances); 
16 U.S.C. 824k (establishing rates for service provided pursuant to 
an order under section 211).
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B. Order No. 888 and Subsequent Reforms

    14. In April 1996, as part of its statutory obligation under 
sections 205 and 206 of the FPA to remedy undue discrimination, the 
Commission adopted Order No. 888 prohibiting public utilities from 
using their monopoly power over transmission to unduly discriminate 
against others. In that order, the Commission required all public 
utilities that own, control or operate facilities used for transmitting 
electric energy in interstate commerce to file open access non-
discriminatory transmission tariffs that contained minimum terms and 
conditions of non-discriminatory service. It also obligated such public 
utilities to ``functionally unbundle'' their generation and 
transmission services. This meant public utilities had to take 
transmission service (including ancillary services) for their own new 
wholesale sales and purchases of electric energy under the open access 
tariffs, and to separately state their rates for wholesale generation, 
transmission and ancillary services.\13\ Each public utility was 
required to file the pro forma OATT included in Order No. 888 without 
any deviation (except a limited number of terms and conditions that 
reflect regional practices).\14\ After the effectiveness of their 
OATTs, public utilities were allowed to file, pursuant to section 205 
of the FPA, deviations that were consistent with or superior to the pro 
forma OATT's terms and conditions. Because certain owners, controllers 
or operators of interstate transmission facilities were not subject to 
the Commission's jurisdiction under sections 205 and 206 and thus were 
not subject to Order No. 888, the Commission adopted a reciprocity 
provision in the pro forma OATT that conditions the use by a non-public 
utility of a public utility's open access services on an agreement to 
offer non-discriminatory transmission services in return.
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    \13\ This is known as ``functional unbundling'' because the 
transmission element of a wholesale sale is separated or unbundled 
from the generation element of that sale, although the public 
utility may provide both functions. See infra section IV.B.4 of this 
Final Rule.
    \14\ See Order No. 888 at 31,769-70 (noting that the pro forma 
OATT expressly identified certain non-rate terms and conditions, 
such as the time deadlines for determining available transfer 
capability in section 18.4 or scheduling changes in sections 13.8 
and 14.6, that may be modified to account for regional practices if 
such practices are reasonable, generally accepted in the region, and 
consistently adhered to by the transmission provider).
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    15. In addition to imposing the functional unbundling requirement, 
the Commission also encouraged broader reforms through the formation of 
independent system operators (ISOs). The Commission stated that ISOs 
can provide significant benefits such as enhancing regional 
efficiencies and further remedying undue discrimination.\15\ While the 
Commission declined to mandate ISOs, it set forth eleven principles for 
assessing ISO proposals submitted to the Commission.\16\
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    \15\ Order No. 888 at 31,655.
    \16\ Id. at 31,730-32.
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    16. Order No. 888 also clarified the Commission's interpretation of 
the Federal and State jurisdictional boundaries over transmission and 
local distribution. While Order No. 888 reaffirmed that the Commission 
has exclusive jurisdiction over the rates,

[[Page 12270]]

terms, and conditions of unbundled retail transmission in interstate 
commerce by public utilities, it nevertheless recognized the legitimate 
concerns of State regulatory authorities regarding the transmission 
component of bundled retail sales. The Commission therefore declined to 
extend its unbundling requirement to the transmission component of 
bundled retail sales. On appeal, the U.S. Supreme Court affirmed this 
element of Order No. 888, finding that the Commission made a 
statutorily permissible choice.\17\
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    \17\ New York v. FERC, 535 U.S. 1 (2002).
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    17. The same day it issued Order No. 888, the Commission issued a 
companion order, Order No. 889,\18\ addressing the separation of 
vertically integrated utilities' transmission and merchant functions, 
the information transmission providers were required to make public, 
and the electronic means they were required to use to do so. Order No. 
889 imposed Standards of Conduct governing the separation of, and 
communications between, the utility's transmission and wholesale power 
functions, to prevent the utility from giving its merchant arm 
preferential access to transmission information. All public utilities 
that owned, controlled or operated facilities used in the transmission 
of electric energy in interstate commerce were required to create or 
participate in an Open Access Same-Time Information System (OASIS) that 
was to provide existing and potential transmission customers the same 
access to transmission information.
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    \18\ Open Access Same-Time Information System (Formerly Real-
Time Information Networks) and Standards of Conduct, Order No. 889, 
61 FR 21737 (May 10, 1996), FERC Stats. & Regs. ] 31,035 (1996), 
order on reh'g, Order No. 889-A, FERC Stats. & Regs. ] 31,049 
(1997), order on reh'g, Order No. 889-B, 81 FERC ] 61,253 (1997).
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    18. Among the information public utilities were required to post on 
their OASIS was the transmission provider's calculation of ATC. Though 
the Commission acknowledged that before-the-fact measurement of the 
availability of transmission service is ``difficult,'' it concluded 
that it was important to give potential transmission customers ``an 
easy-to-understand indicator of service availability.'' \19\ Because 
formal methods did not then exist to calculate ATC and total transfer 
capability (TTC), the Commission encouraged industry efforts to develop 
consistent methods for calculating ATC and TTC.\20\ Order No. 889 
ultimately required transmission providers to base their calculations 
on ``current industry practices, standards and criteria'' and to 
describe their methodology in their tariffs.\21\ The Commission noted 
that the requirement that transmission providers purchase only ATC that 
is posted as available ``should create an adequate incentive for them 
to calculate ATC and TTC as accurately and as uniformly as possible.'' 
\22\
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    \19\ Order No. 889 at 31,605.
    \20\ Id. at 31,607.
    \21\ Id.
    \22\ Id.
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    19. The electric industry continued to undergo economic and 
regulatory changes in the years following the issuance of Order No. 
888. Retail access was adopted by approximately 25 states in the late 
1990s.\23\ This State restructuring activity spurred significant 
changes at the wholesale level as well by encouraging or requiring the 
divestiture of generation plants by traditional electric utilities and 
the development of ISOs that could manage short-term energy markets 
necessary to support retail access. At the same time, there was a 
significant increase in the number of mergers between traditional 
electric utilities and between electric utilities and gas pipeline 
companies, and large increases in the number of power marketers and 
independent generation facility developers entering the marketplace. 
Trade in bulk power markets increased significantly and the Nation's 
transmission grid was used more heavily and in new ways as customers 
took advantage of the pro forma OATT and purchased power from 
competitive sellers.
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    \23\ See Energy Information Administration, Retail Unbundling--
U.S. Summary (2005), http://www.eia.doe.gov/oil_gas/natural_gas/restructure/state/us.html
.

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    20. In the wake of these changes, in December 1999, the Commission 
adopted Order No. 2000.\24\ That rulemaking recognized that Order No. 
888 set the foundation upon which competitive electric markets could 
develop, but did not eliminate the potential to engage in undue 
discrimination and preference in the provision of transmission 
service.\25\ The rulemaking also recognized that Order No. 888 did not 
address the regional nature of the grid, including the treatment of 
parallel flows, pancaked rates, and congestion management. Thus, the 
Commission encouraged the creation of RTOs to address important 
operational and reliability issues and eliminate any residual 
discrimination in transmission services that can occur when the 
operation of the transmission system remains in the control of a 
vertically integrated utility. The Commission found that RTOs would 
increase the efficiency of wholesale markets by eliminating pancaked 
rates, internalizing parallel flow, managing congestion efficiently, 
and operating markets for energy, capacity and ancillary services. The 
Commission established an open, collaborative process that relied on 
voluntary regional participation to design RTOs tailored to the 
specific needs of each region. The Commission noted, however, that 
``[i]f the industry fails to form RTOs under this approach, the 
Commission will reconsider what further regulatory steps are in the 
public interest.''\26\
---------------------------------------------------------------------------

    \24\ Regional Transmission Organizations, Order No. 2000, 65 FR 
809 (Jan. 6, 2000), FERC Stats. & Regs. ] 31,089 (1999), order on 
reh'g, Order No. 2000-A, 65 FR 12088 (Mar. 8, 2000), FERC Stats. & 
Regs. ] 31,092 (2000), aff'd sub nom. Public Utility District No. 1 
of Snohomish County, Washington v. FERC, 272 F.3d 607 (D.C. Cir. 
2001).
    \25\ Order No. 2000 at 31,015.
    \26\ Id. at 30,993.
---------------------------------------------------------------------------

    21. Following Order No. 2000, RTOs were approved in several regions 
of the country including the Northeast (PJM; ISO New England),\27\ the 
Midwest (MISO) and the South (SPP). In most cases, RTOs have assumed 
responsibility for calculating ATC across the footprint of the RTO, as 
well as the planning and expansion of the transmission grid, at least 
for facilities necessary for maintaining system reliability. However, 
large areas of the Nation have not developed RTOs using the voluntary 
structure adopted by the Commission in Order No. 2000. Moreover, 
transmission customers have complained that even in RTO markets there 
are instances when comparable transmission service is not provided, 
particularly in the area of transmission planning.
---------------------------------------------------------------------------

    \27\ A list of commenter acronyms can be found in Appendix B.
---------------------------------------------------------------------------

C. EPAct 2005 and Recent Developments

    22. Enacted on August 8, 2005, EPAct added a number of new 
authorities and priorities for the Commission and emphasized certain of 
its existing obligations. Among other things, EPAct 2005 recognized the 
importance of adequate transmission infrastructure development and its 
role in facilitating the development of competitive wholesale markets. 
The Congressional directives in EPAct 2005 are intended to reverse the 
decline in transmission infrastructure investment. For example, 
Congress required the Commission to adopt a rule establishing incentive 
ratemaking for transmission infrastructure to help promote reliability 
and reduce congestion.\28\ Congress also

[[Page 12271]]

directed the Commission to encourage the deployment of advanced 
technologies.\29\ Congress further directed the Commission to 
``exercise its authority'' under EPAct 2005 ``in a manner that 
facilitates the planning and expansion of transmission facilities to 
meet the reasonable needs of load-serving entities.''\30\ Congress also 
gave the Commission certain ``backstop'' transmission siting authority, 
and authorized the creation of interstate compacts establishing 
transmission siting agencies.\31\ EPAct 2005 also authorized the 
Commission to require unregulated transmitting utilities (except for 
certain small entities) to provide access to their transmission 
facilities on a comparable basis.\32\ Congress further ordered the 
Department of Energy (DOE) to study the benefits of economic dispatch 
and required the Commission to convene regional joint boards to develop 
a report to Congress containing recommendations for the use of security 
constrained economic dispatch within each region.\33\ Congress also 
directed the Commission to facilitate price transparency in markets for 
the sale and transmission of electric energy in interstate commerce, 
having due regard for the public interest, the integrity of those 
markets, fair competition, and the protection of consumers, and it 
authorized the Commission to prescribe rules to provide for the 
dissemination of information about the availability and price of 
wholesale electric energy and transmission service.\34\ Finally, 
Congress emphasized compliance with the Commission's regulations, 
adopting and increasing the civil and criminal penalties for violations 
of Commission-administered statutes and regulations.\35\
---------------------------------------------------------------------------

    \28\ EPAct 2005 sec. 1241 (to be codified at section 219 of the 
FPA, 16 U.S.C. 824s).
    \29\ EPAct 2005 sec. 1223 (to be codified at 42 U.S.C. 16422). 
Indeed, Congress provided specific guidance as to the types of 
advanced technologies that should be encouraged in infrastructure 
improvements to include, among others, optimized transmission line 
configurations (including multiple phased transmission lines), 
controllable load, distributed generation (including PV, fuel cells, 
and microturbines), and enhanced power device monitoring. Id.
    \30\ EPAct 2005 sec. 1233(a) (to be codified at section 
217(b)(4) of the FPA, 16 U.S.C. 824q).
    \31\ EPAct 2005 sec. 1221(a) (to be codified at section 216 of 
the FPA, 16 U.S.C. 824p).
    \32\ EPAct 2005 sec. 1231 (to be codified at section 211A of the 
FPA, 16 U.S.C. 824j-1)
    \33\ EPAct 2005 sec. 1234 (to be codified at 42 U.S.C. 16432); 
EPAct 2005 sec. 1298 (to be codified at section 223 of the FPA, 16 
U.S.C. 824w). EPAct 2005 sec. 1234(b) defined economic dispatch as 
``the operation of generation facilities to produce energy at the 
lowest cost to reliably serve consumers, recognizing any operational 
limits of generation and transmission facilities.''
    \34\ EPAct 2005 sec. 1281 (to be codified at section 220 of the 
FPA, 16 U.S.C. 824t).
    \35\ EPAct 2005 sec. 1284(d) (to be codified at section 316 of 
the FPA, 16 U.S.C. 825o); EPAct 2005 sec. 1284(e) (to be codified at 
section 316A of the FPA, 16 U.S.C. 825o-1).
---------------------------------------------------------------------------

    23. Recognizing the need for reform of Order No. 888 in light of 
the Commission's continuing concern regarding whether the pro forma 
OATT adequately remedies undue discrimination, the Commission issued an 
NOI on September 16, 2005 \36\ seeking comments on appropriate reforms 
of the Order No. 888 pro forma OATT. In the NOI, the Commission 
expressed its preliminary view that reforms to the pro forma OATT and 
public utilities' OATTs are necessary to avoid undue discrimination or 
preference in the provision of transmission service. The NOI sought 
comments on how best to accomplish the Commission's goals, specifically 
with respect to enhancements that are needed to (1) Remedy any unduly 
discriminatory or preferential application of the pro forma OATT or (2) 
improve the clarity of the Order No. 888 pro forma OATT and the 
individual public utility tariffs in order to more readily identify 
violations and facilitate compliance.
---------------------------------------------------------------------------

    \36\ See supra note 5.
---------------------------------------------------------------------------

    24. The Commission received over 4,000 pages of initial and reply 
comments on the NOI. Based on these comments, the comments submitted in 
response to the ATC NOI,\37\ our experience in implementing Order No. 
888, and the changes in the industry since we adopted it, the 
Commission proposed to reform the pro forma OATT in a number of ways. 
The Commission issued the NOPR on May 19, 2006 proposing a number of 
reforms aimed at remedying undue discrimination in the provision of 
open access transmission service and improving the clarity of the pro 
forma OATT and the individual tariffs of transmission providers in 
order to more readily identify violations and facilitate compliance. 
The Commission received over 5,700 pages of initial and reply comments 
in response. In response to comments on the particular issue of 
redispatch and conditional firm service (discussed in more detail 
below), the Commission issued a Notice of Request for Supplemental 
Comments on November 15, 2006,\38\ that resulted in receipt of an 
additional 750 pages of comments.
---------------------------------------------------------------------------

    \37\ Id.
    \38\ Preventing Undue Discrimination and Preference in 
Transmission Service, 117 FERC ] 61,185 (2006).
---------------------------------------------------------------------------

    25. Based on this voluminous record, the Commission concludes that 
reform of the pro forma OATT and associated amendments to its 
regulations are necessary to reduce the potential for undue 
discrimination and provide clarity in the obligations of transmission 
providers and customers alike. We turn next to a more complete 
explanation of this need for reform.

III. Need for Reform of Order No. 888

A. Opportunities for Undue Discrimination Continue To Exist

    26. Although Order No. 888 has been successful in many important 
respects, the need for reform of the Order No. 888 pro forma OATT has 
been apparent for some time. In 1999, the Commission held, in adopting 
Order No. 2000, that the pro forma OATT could not fully remedy undue 
discrimination because transmission providers retained both the 
incentive and the ability to discriminate against third parties, 
particularly in areas where the pro forma OATT left the transmission 
provider with significant discretion.\39\ The Commission made a similar 
finding in Order No. 2003,\40\ holding that opportunities for undue 
discrimination continue to exist in areas where the pro forma OATT 
leaves transmission providers with substantial discretion.\41\ The NOPR 
reaffirmed these findings, preliminarily concluding that opportunities 
for undue discrimination continue to exist in the provision of open 
access transmission service. The Commission therefore proposed a number 
of reforms to the pro forma OATT to address the opportunities and 
incentives transmission providers have to unduly discriminate.
---------------------------------------------------------------------------

    \39\ Order No. 2000 at 31,105.
    \40\ See Standardization of Generator Interconnection Agreements 
and Procedures, Order No. 2003, 68 FR 49845 (Aug. 19, 2003), FERC 
Stats. & Regs. ] 31,146 at P 11-12 (2003), order on reh'g, Order No. 
2003-A, 69 FR 15932 (Mar. 26, 2004), FERC Stats. & Regs. ] 31,160 
(2004), order on reh'g, Order No. 2003-B, 70 FR 265 (Jan. 4, 2005), 
FERC Stats. & Regs. ] 31,171 (2004), order on reh'g, Order No. 2003-
C, 70 FR 37,661 (Jun. 30, 2005), FERC Stats. & Regs. ] 31,190 
(2005), aff'd sub nom. National Association of Regulatory Utility 
Commissioners v. FERC, No. 04-1148, 2007 U.S. App. LEXIS 626 (D.C. 
Cir. Jan. 12, 2007).
    \41\ Order No. 2003 at P 11-12.
---------------------------------------------------------------------------

Comments
    27. Many commenters agree with the Commission that reforms to the 
pro forma OATT are needed because there continue to be both the 
opportunity and incentive for transmission providers to engage in undue 
discrimination.\42\
---------------------------------------------------------------------------

    \42\ E.g., APPA, EPSA, East Texas Cooperatives, Fayetteville, 
NRG, Occidental, TAPS, TDU Systems, Williams, Entegra Reply, and 
NRECA Reply.
---------------------------------------------------------------------------

    28. Several commenters offered examples of their experiences with 
transmission providers, where they believe transmission providers have 
acted in an unduly discriminatory

[[Page 12272]]

fashion.\43\ Constellation claims that on multiple occasions it has 
been denied a transmission request when the transmission provider's 
OASIS indicates that ATC is available, but Constellation had no 
effective and timely way to challenge that determination because of the 
ATC ``black box.'' Constellation states that given that its needs for 
transmission service are often near-term or immediate--e.g., to 
facilitate a load-serving obligation or wholesale transaction that must 
be consummated quickly--seeking redress at the Commission for 
improperly denied service generally is not time- or cost-effective. 
Instead, Constellation asserts, it is often forced to accept the 
determination of the transmission provider that ATC is not available 
(even though its OASIS may indicate otherwise) and seek alternate 
transmission paths and/or products to consummate its transaction.
---------------------------------------------------------------------------

    \43\ See, e.g., Dow, Fayetteville, Occidental, and Williams.
---------------------------------------------------------------------------

    29. Powerex also describes instances where a transmission provider 
has granted short-term firm point-to-point transmission service 
requests to transmission customers who have been allowed to remain in 
the queue, even when zero ATC is posted, in the hopes that a 
transmission provider's OASIS site wrongly indicates zero ATC or will 
soon be updated. Powerex asserts that such practices clog the short-
term point-to-point transmission queue with multiple requests and 
result in duplicative requests for service that reflect customers' 
attempts to secure service, rather than the actual quantity of service 
needed. Moreover, Powerex argues, transmission provider discretion in 
this area and the lack of transparency raise customer concerns about 
preferential treatment.
    30. Occidental claims that it has first-hand experience with a 
vertically integrated transmission provider that, despite having an 
OATT, appears to have persistently used its transmission system to 
preferentially benefit its merchant function. Similarly, Williams 
alleges that its interests have been consistently and significantly 
compromised by the discretion afforded transmission providers in the 
interpretation of the OATT and the lack of transparency in requesting, 
scheduling and interrupting of transmission service.
    31. Other commenters, however, argue that the Commission's proposed 
reforms are based on unsupported allegations of undue discrimination. 
EEI maintains that any opportunities to engage in undue discrimination 
have been largely mitigated by current regulatory policies and changes 
in the industry. EEI explains that, unlike the situation that existed 
when the Commission enacted Order No. 888, much of the country's 
transmission facilities are now under the control of RTOs and ISOs. In 
addition, EEI states, other transmission providers have transferred (or 
are in the process of transferring) the administration of their OATTs 
and OASIS functions to independent transmission service coordinators. 
Even among the transmission providers who have taken neither of those 
steps, EEI argues that the open access requirements of Order No. 888 
and the Standards of Conduct of Order Nos. 889 and 2004 have largely 
eliminated the ability of transmission providers to engage in undue 
discrimination in the provision of transmission service.\44\ In 
addition, EEI states, the Commission's expanded civil penalty authority 
added to the FPA by EPAct 2005 gives the Commission a powerful tool 
that will further eliminate any remaining incentive of transmission 
providers to engage in undue discrimination in the provision of 
transmission service. Therefore, EEI asserts, any modifications to the 
OATT should be narrowly tailored to address the perceptions of residual 
undue discrimination. To the extent that such perceptions exist, 
however, Community Power Alliance states that, in the absence of 
concrete record evidence, they are just that--perceptions.
---------------------------------------------------------------------------

    \44\ See also Southern Reply.
---------------------------------------------------------------------------

    32. Although Duke strongly supports, as a policy matter, OATT 
reforms that will eliminate the perception that undue discrimination is 
possible and/or likely, Duke argues that the FPA does not provide the 
Commission the authority to remedy mere ``opportunities'' to 
discriminate. Duke states that, in some cases, the Commission is 
attempting to remedy an opportunity for undue discrimination that does 
not exist or is proposing to impose a remedy that does not actually 
remedy the perceived opportunity. Duke notes, however, that some OATT 
terms and conditions are subject to multiple interpretations and argues 
that the Commission can, and should, justify the OATT reforms proposed 
in the NOPR as reforms needed to provide clarity to existing policies.
    33. With regard to specific allegations made by commenters, several 
transmission providers respond that the examples given by transmission 
customers do not illustrate instances of undue discrimination. Rather, 
they assert, these examples demonstrate the transmission customers' 
lack of understanding of the OATT requirements, and the data available 
on OASIS.\45\
---------------------------------------------------------------------------

    \45\ See, e.g., Entergy Reply, Progress Energy Reply, and 
Southern Reply.
---------------------------------------------------------------------------

    34. New Mexico Attorney General argues that the traditional State-
regulated, vertically-integrated cost-of-service world is not in need 
of reform. Contrary to the ``conspiracy theorists'' who argue that 
utilities have an incentive to engage in undue discrimination and 
preference in transmission services, New Mexico Attorney General 
asserts that utilities have an incentive to maximize throughput and 
revenue between State-level rate cases because incremental transmission 
revenue is not deducted from the State-jurisdictional retail revenues 
between rate cases. Similarly, Southern, in its reply comments, asserts 
that broad claims of undue discrimination fail to take into 
consideration that vertically-integrated utilities have more of an 
incentive to act appropriately than do independent utilities because 
the former have more to lose (e.g., loss of market-based rates, state 
prudence reviews of costs, etc.) if they are found to have engaged in 
wrong-doing. Southern states that any OATT revisions ultimately adopted 
by the Commission must be reasonably tailored to address an identified 
problem or to provide a specific improvement.
    35. Other commenters argue that the Commission's focus should be on 
transmission providers in non-organized markets, arguing that remaining 
concerns about undue discrimination have already been addressed in the 
world of ISOs and RTOs.\46\ According to ISO/RTO Council, this 
proceeding provides an opportunity for the Commission to harmonize the 
worlds of organized and non-organized markets in a manner that 
encourages competition, promotes non-discriminatory access, and 
maximizes the flow of electricity across various ISO/RTO and non-ISO/
RTO regions. ISO/RTO Council states that, in the existing regulatory 
environment, a utility that is not a member of an ISO or RTO can sell 
into, or purchase from, an ISO or RTO market even though the non-ISO/
RTO utility operates under tariff rules that are less open and 
transparent, particularly in terms of access to generation resources 
and pricing/system information, than their competitors that belong to 
an ISO or RTO. Such asymmetry, ISO/RTO Council argues, operates as an

[[Page 12273]]

impediment to fair and non-discriminatory transmission access and 
management of grid congestion.
---------------------------------------------------------------------------

    \46\ E.g., Indicated New York Transmission Owners, ISO/RTO 
Council, and Northeast Utilities.
---------------------------------------------------------------------------

    36. ISO/RTO Council states that its members do not seek to impose 
their market designs on the rest of the nation. At the same time, ISO/
RTO Council argues that meaningful reform should ensure a level of 
transparency (of both price and the dispatch utilized by non-ISO/RTO 
vertically-integrated entities) in regions without an ISO or RTO that 
can assist the flow of electricity and enhance reliability and planning 
in both ISO/RTO and non-ISO/RTO regions.
    37. Exelon urges the Commission to hold the transmission providers 
outside ISOs or RTOs to the same standard of non-discrimination that 
exists within those organizations. Further, MISO/PJM States argue that 
in order to achieve some level of independence in non-RTO regions, non-
independent transmission providers should be encouraged to turn over 
operational control of their transmission systems to an independent 
coordinator of transmission whose functions would include security 
coordination, determination of ATC, granting of transmission service 
and oversight for transmission planning.
    38. Finally, EPSA suggests that the Commission establish a one-year 
review period for the reformed pro forma OATT. EPSA urges the 
Commission to revisit this Final Rule after one year of operation under 
the reformed pro forma OATT to ensure that the revisions adopted here 
do, in fact, protect against non-discriminatory or preferential 
behavior by transmission providers. NRECA responds that, after this 
comprehensive rulemaking process, there is simply no need for another 
major look at the OATT in one year. Moreover, NRECA states, one year is 
likely too short a period for the Commission and industry participants 
to fully appreciate all of the consequences of those elements of OATT 
reform resulting from this proceeding. At the same time, NRECA agrees 
that the Commission should carefully monitor implementation of the 
reformed OATT. This monitoring, NRECA states, must be an ongoing 
process and cannot wait a year to begin.
Commission Determination
    39. The Commission concludes that reforms are needed to address 
deficiencies in the pro forma OATT that have become apparent since 
1996, by limiting remaining opportunities for undue discrimination. As 
the Commission found in Order No. 888, it is in the economic self-
interest of transmission monopolists, particularly those with high-cost 
generation assets, to deny transmission or to offer transmission on a 
basis that is inferior to that which they provide to themselves.\47\ 
Such an incentive can lead to unduly discriminatory behavior against 
third parties, particularly if public utilities have unnecessarily 
broad discretion in the application of their tariffs. This discretion 
also can create problems for transmission providers seeking to comply 
with our regulations in good faith because so many issues are left for 
their interpretation, thereby increasing the possibility of disputes 
with transmission customers and enforcement actions by the 
Commission.\48\ Transmission customers also have found ways to use the 
tariffs to their own advantage, particularly in the scheduling and 
queuing processes.\49\
---------------------------------------------------------------------------

    \47\ Order No. 888 at 31,682.
    \48\ See, e.g., Order No. 2003 at P 11-12.
    \49\ See, e.g., Potomac Economics, Ltd., 2004 State of the 
Market Report: Midwest ISO at 30-31, 34-35 (Jun. 2005), http://www.midwestmarket.org/publish/Document/2b8a32_103ef711180_-7bf20a48324a/2004%20MISO%20SOM%20Report.pdf?action=download&_property=Attachment
 (explaining that the queuing process, by giving 

eport.pdf?action=download&_property=Attachment
 (explaining that the queuing process, by giving 

provides a low- or no-cost option that restricts other customers' 
access to congested interfaces, and the scheduling process, by 
allowing customers to leave transmission requests unconfirmed, 
provides a free option that may invite hoarding or result in 
underutilized capacity).
---------------------------------------------------------------------------

    40. As some commenters note, opportunities for undue discrimination 
persist, particularly in areas where the pro forma OATT leaves the 
transmission provider with substantial discretion. The Commission has a 
responsibility under section 206 of the FPA to remedy undue 
discrimination. Indeed, the court concluded in Associated Gas 
Distributors v. FERC,\50\ that, like the Natural Gas Act,\51\ the FPA 
``fairly bristles'' with concern over undue discrimination. Based on 
AGD, the Commission determined in Order No. 888 that:

    \50\ 824 F.2d 981 (D.C. Cir. 1987) (AGD).
    \51\ 15 U.S.C. 717.
---------------------------------------------------------------------------

    The Commission has a mandate under sections 205 and 206 of the 
FPA to ensure that, with respect to any transmission in interstate 
commerce or any sale of electric energy for resale in interstate 
commerce by a public utility, no person is subject to any undue 
prejudice or disadvantage. We must determine whether any rule, 
regulation, practice or contract affecting rates for such 
transmission or sale for resale is unduly discriminatory or 
preferential, and must prevent those contracts and practices that do 
not meet this standard. * * * AGD demonstrates that our remedial 
power is very broad and includes the ability to order industry-wide 
non-discriminatory open access as a remedy for undue discrimination.
    Order No. 888 at 31,669. Through this Final Rule, the Commission 
exercises that remedial authority again to limit further opportunities 
for undue discrimination, by minimizing areas of discretion, addressing 
ambiguities and clarifying various aspects of the pro forma OATT.
    41. We disagree with commenters who assert that the Commission is 
relying on unsubstantiated allegations of discriminatory conduct to 
justify OATT reform. The courts have made clear that the Commission 
need not make specific factual findings of discrimination in order to 
promulgate a generic rule to eliminate undue discrimination.\52\ In 
AGD, the court explained that the promulgation of generic rate criteria 
involves the determination of policy goals and the selection of the 
means to achieve them and that courts do not insist on empirical data 
for every proposition upon which the selection depends: ``[a]gencies do 
not need to conduct experiments in order to rely on the prediction that 
an unsupported stone will fall.'' \53\ During this multi-year 
proceeding, the Commission has received many comments arguing that 
commenters have either experienced or perceived that they have 
experienced unduly discriminatory conduct by transmission providers. 
Even transmission providers have acknowledged that there is a 
continuing perception that there is the opportunity for them to unduly 
discriminate against their competitors and, accordingly, they state 
their support for our reform effort.\54\ Moreover, it is undisputed 
that the existing pro forma OATT provides wide discretion in 
implementing some of its basic requirements, such as the assessment of 
whether sufficient ATC exists to grant third party access to the grid 
and the manner in which new facilities are planned to satisfy third 
party needs. This wide discretion, when coupled with a transmission 
provider's incentive to discriminate, creates opportunities for 
discrimination under the pro forma OATT. We have an obligation under 
section 206 to remedy that discrimination.
---------------------------------------------------------------------------

    \52\ TAPS v. FERC, 225 F.3d at 667, 688; National Fuel Gas 
Supply Corp. v. FERC, 468 F.3d 831 (D.C. Cir. 2006) (National Fuel).
    \53\ 824 F.2d at 1008.
    \54\ See, e.g., Duke and EEI.
---------------------------------------------------------------------------

    42. It is thus clear to us that, notwithstanding the Commission's 
efforts in Order No. 888, opportunities to engage in undue 
discrimination can and will persist unless the existing pro forma OATT 
is reformed. We therefore exercise our broad remedial authority today 
to limit these remaining

[[Page 12274]]

opportunities for undue discrimination. The Commission concludes that 
any additional costs incurred by transmission providers to implement 
the reforms required in this Final Rule are fully justified by the need 
to ensure open, transparent and non-discriminatory access to 
transmission service. We also believe it is appropriate to adopt these 
reforms by rulemaking, rather than rely on complaints filed by 
transmission customers or other parties. Case-by-case application of 
the reforms adopted in this Final Rule would be inappropriate since the 
most fundamental problems addressed here arise from deficiencies in the 
pro forma OATT itself, not simply the implementation of the pro forma 
OATT by a few transmission providers. Also, we decline to establish a 
one-year review period for the reformed pro forma OATT, as EPSA 
recommends. The Commission will continue to actively monitor compliance 
with its orders and, as necessary, institute further proceedings to 
meet its statutory obligation to remedy undue discrimination.
    43. The Commission will not catalog each and every basis for its 
reform of the pro forma OATT in this section. Rather, we identify the 
bases for some of the most fundamental reforms herein and, in addition, 
we explain in each individual section of the Final Rule the 
inadequacies of the existing pro forma OATT provisions being addressed 
there and the reasons why our reforms are necessary to remedy undue 
discrimination or otherwise provide for rates, terms and conditions of 
service under the pro forma OATT that are just and reasonable.

B. Lack of Transparency Undermines Confidence in Open Access and 
Impedes Enforcement of Open Access Requirements

    44. Following the issuance of the NOI, the Commission received a 
number of comments asserting that increased transparency would aid 
transmission customers in their participation in the wholesale market. 
A common theme in the comments was that a lack of transparency could 
lead to claims of discrimination and could make such claims more 
difficult to resolve. Commenters urged the Commission to improve 
transparency in a number of areas, particularly the evaluation of ATC 
and the planning of the transmission system, as well as the processing 
of transmission service requests and studies.
    45. In the NOPR, the Commission agreed that a lack of transparency 
both increases the potential for undue discrimination and makes it more 
difficult to detect. The Commission reasoned that this lack of 
sufficient transparency was caused in part by inadequate compliance 
with the existing OASIS regulations and in part by inadequate 
transparency requirements. The Commission stated that the proposed 
reforms were intended to address both elements of the problem in an 
effort to increase confidence in open access tariffs and to facilitate 
compliance with the Commission's regulations and its enforcement of 
them.
Comments
    46. Williams states that its interests have been consistently and 
significantly compromised by the discretion afforded transmission 
providers in the interpretation of the OATT and the lack of 
transparency in requesting, scheduling and interrupting of transmission 
service. According to Williams, simply being told that service is being 
curtailed for reliability purposes under opaque local procedures, in 
the absence of a NERC Transmission Loading Relief (TLR) event, leaves 
market participants suffering the consequences without knowing on what 
basis the decision was reached, and without assurance that the decision 
was made in a non-discriminatory manner. Ultimately, Williams adds, the 
lack of transparency and latitude taken by the transmission provider to 
determine which requests for service are confirmed or denied and which 
are curtailed or interrupted in real time frustrates the Commission's 
goal of preventing undue discrimination and preference in the provision 
of transmission service. Furthermore, Williams states, the same lack of 
transparency exists around the opaque processes utilized, assumptions 
made, and basis on which the results of transmission planning studies 
are conducted to grant or deny requests for service.
    47. APPA agrees that additional transparency in the administration 
of public utility transmission providers' OATTs will be of material 
assistance to both the Commission and transmission customers. However, 
APPA argues that the Commission must go beyond increasing transparency 
in the administration of public utility transmission providers' OATTs. 
According to APPA, more transparency will not change the basic industry 
paradigm with transmission customers depending on monopoly transmission 
providers for service. In APPA's view, customers are often reluctant to 
file complaints or bring problems to the Commission's attention because 
they depend on their transmission providers' systems for the vital 
services they need to serve their loads. APPA argues that the 
Commission not only has an obligation to act to remedy undue 
discrimination when it sees it, but also has an affirmative duty to 
look for it. According to APPA, the Commission must continue to 
actively regulate the transmission services that public utility 
transmission providers offer, even if full transparency is achieved 
through the revisions to the OATT implemented in the instant docket.
    48. EPSA agrees that greater transparency will help enable market 
participants and the Commission to monitor and audit the behavior of 
transmission providers. EPSA states that the several ``black boxes'' 
shielding discriminatory transmission service over the past ten years 
must be opened. However, EPSA argues, there must be meaningful clarity 
and obligations set out in the rules and OATT requirements--
transparency simply for the sake of knowing why transmission service 
has been denied only illuminates a ``bridge to nowhere'' and fails to 
satisfy the Federal Power Act.
    49. Entergy also supports the Commission's efforts to provide 
greater clarity in the rights and obligations of transmission providers 
and transmission customers under the OATT. According to Entergy, many 
of the improvements proposed by the Commission will reduce the 
likelihood of disputes and promote greater confidence on the part of 
customers that they are being treated fairly. Entergy states that, 
while it recognizes that the lack of clarity makes it difficult for the 
Commission to detect instances of non-compliance by transmission 
providers, Entergy also believes that this lack of clarity often makes 
it easier for transmission customers to convert every practice or 
policy into a claim of discrimination or other misconduct.
    50. Although not convinced that there is a compelling need for 
increased transparency since transmission providers are already 
required to disclose voluminous amounts of information, Southern states 
that it recognizes that some reforms in the availability of information 
may be advantageous. However, Southern asserts, providing additional 
transparency must not simply impose additional reporting requirements; 
any such transparency-related reforms should be made after taking into 
consideration the extent and type of data and information that is 
already provided.

[[Page 12275]]

Commission Determination
    51. The Commission concludes that inadequate transparency 
requirements, combined with inadequate compliance with existing OASIS 
regulations, increases the opportunities for undue discrimination under 
the pro forma OATT and makes instances of undue discrimination more 
difficult to detect. We find that the reforms we adopt in this Final 
Rule will improve transparency in the OATT, reduce opportunities for 
undue discrimination, and increase our ability to detect undue 
discrimination.

C. Congestion and Inadequate Infrastructure Development Impede 
Customers' Use of the Grid

    52. The Commission noted in the NOPR that the ability and incentive 
to discriminate increases as the transmission system becomes more 
congested. The Commission observed that the pro forma OATT contained 
only minimal requirements regarding transmission planning, which have 
proven to be inadequate as the Nation faces insufficient transmission 
investment in many areas. The Commission preliminarily concluded that 
the inadequacy of the existing obligation to conduct transmission 
system planning, coupled with the lack of transparency surrounding 
system planning generally, required reform of the pro forma OATT to 
ensure that transmission infrastructure is constructed on a 
nondiscriminatory basis and is otherwise sufficient to support reliable 
and economic service to all eligible customers. The Commission 
therefore proposed to require public utilities to engage in an open and 
transparent planning process at both the local and regional levels.
Comments
    53. APPA agrees that the lack of adequate transmission 
infrastructure is one of the core problems facing the electric utility 
industry. APPA supports revisions to the pro forma OATT to enhance and 
improve transmission planning on both an individual system and regional 
basis. Several commenters go further, arguing that the proposed reforms 
are insufficient and urging the Commission to more strongly encourage 
infrastructure development. EPSA asserts that successful implementation 
of the Congressional policy in favor of wholesale competition and State 
policies in favor of competitive procurement is frustrated by the lack 
of sufficient open access to the transmission grid. According to EPSA, 
new power plant investment is highly unlikely to occur, except by the 
transmission provider or its affiliate on a ``sole source'' or ``no 
bid'' basis (despite Federal and State policies to the contrary), if 
unaffiliated suppliers cannot effectively and efficiently obtain 
transmission service. EPSA argues that failure to boldly reform the 
Commission's open access transmission rules at this critical juncture 
would effectively hand an undeserved victory to the very transmission 
providers who, by the Commission's own findings, have the motive and 
the opportunity to discriminate. International Transmission argues that 
tariff reform is no substitute for prudent investment in the 
transmission infrastructure needed to increase the underlying physical 
capability of the transmission system.
    54. On the other hand, some commenters dispute the Commission's 
assertion in the NOPR that vertically-integrated utilities operating in 
non-RTO regions have an incentive to discriminate and, therefore, are 
not adequately expanding the transmission grid to accommodate new entry 
by more efficient competitors. New Mexico Attorney General argues that 
vertically-integrated utilities operating under the traditional rate-
base, rate-of-return model of regulation in fact have been historically 
criticized for having incentives to overbuild. New Mexico Attorney 
General asserts that most transmission projects are in reality derailed 
by strong ``NIMBY'' opposition to the actual siting of transmission 
lines. Another countervailing factor to the utility's incentive to 
overbuild, in New Mexico Attorney General's view, is the fact that 
State regulators attempt to limit capacity investment to reasonable 
levels only necessary to serve native load.
    55. Southern states that the Commission's assertion in the NOPR 
that vertically-integrated utilities do not have an incentive to expand 
the grid overlooks the fact that many such utilities are under State 
legal duties to procure generation supplies through open, non-
discriminatory requests for proposals, with the winners of those 
requests for proposals often being competitors of the vertically-
integrated utility. Southern maintains that the winning competitive 
generation is then integrated into the host utility's transmission 
system and dispatch, and the transmission system is expanded to ensure 
the deliverability of this competitive generation. Furthermore, 
Southern states, a competitive generator can also have the output of 
its generator planned into the transmission provider's system if it 
takes long-term firm service under the OATT, with the transmission 
provider then being under a legal duty to expand its transmission 
system accordingly. Southern notes that it alone has invested $3.2 
billion in transmission over the past decade and plans to invest 
another $2.8 billion over the next five years (2006-2010).
    56. Community Power Alliance also argues that the Commission's own 
June 2005 ``State of the Markets Report'' contradicts the Commission's 
assertion that vertically-integrated utilities do not have the proper 
incentives to expand the grid. Community Power Alliance contends that 
this report shows that the amount of transmission investments made in 
the non-RTO regions, where vertically-integrated utilities typically 
operate, substantially exceeds the amount of transmission investments 
made in RTO regions.
Commission Determination
    57. The Commission concludes that reforms are needed to ensure that 
transmission infrastructure is evaluated, and if needed, constructed on 
a nondiscriminatory basis and is otherwise sufficient to support 
reliable and economic service to all eligible customers. As noted 
above, vertically-integrated utilities do not have an incentive to 
expand the grid to accommodate new entries or to facilitate the 
dispatch of more efficient competitors. Despite this, the existing pro 
forma OATT contains very few requirements regarding how transmission 
planning should be conducted to ensure that undue discrimination does 
not occur.
    58. Our concern over this flaw is heightened by the critical need 
for new transmission infrastructure in this Nation. As the Commission 
explained in the NOPR, transmission capacity is being constructed at a 
much slower rate than the rate of increase in customer demand, with 
transmission capacity per MW of peak demand declining at an average 
rate of 2.1 percent per year during the period 1992 to 2002.\55\ The 
projections suggest that this trend will continue through 2012.\56\ As 
a result, there has been a significant decrease in transmission 
capacity relative to load in every NERC region.\57\ In light of this 
trend, there is a compelling need to build new transmission and respond 
to increasing demand through other

[[Page 12276]]

means. EEI estimates that capital spending must increase by 25 percent, 
from $4 billion annually to $5 billion annually, to ensure system 
reliability and to accommodate wholesale electric markets.\58\ The 
legacy systems constructed by vertically-integrated utilities prior to 
the adoption of Order No. 888 support ``only limited amounts of inter-
regional power flows and transactions. Thus, existing systems cannot 
fully support all of society's goals for a modern electric-power 
system.'' \59\
---------------------------------------------------------------------------

    \55\ Eric Hirst, U.S. Transmission Capacity: Present Status and 
Future Prospects (Aug. 2004), http://www.eei.org/industry_issues/energy_infrastructure/transmission/USTransCapacity10-18-04.pdf 

 

(Present Status and Future Prospects).
    \56\ Present Status and Future Prospects at v.
    \57\ Brendan Kirby (Oak Ridge National Laboratory, U.S. 
Department of Energy), Barriers to Transmission Investment, 
Technical Conference Presentation, (Docket No. AD05-5-000) (April 
22, 2005).
    \58\ Energy Policy Act of 2005: Hearings before the Subcommittee 
on Energy and Air Quality of the House Committee on Energy and 
Commerce, 109th Congress, First Sess. (2005) (Prepared statement of 
Thomas R. Kuhn, President of EEI).
    \59\ Present Status and Future Prospects at v.
---------------------------------------------------------------------------

    59. Expansion of the transmission system, as well as more efficient 
use of the grid, will alleviate the growth of congestion in most 
regions of the country. Transmission congestion has created fairly 
small local load pockets in primarily urban areas, e.g., New York City, 
Long Island, Boston, parts of Connecticut, and the San Francisco Bay 
Area. Other load pocket concerns have arisen in parts of northern 
Virginia, and various load centers in SPP. Still other constraints are 
more regional in scope: from the Midwest to the Mid-Atlantic, from the 
Midwest to TVA, into and within California, from TVA and Southern into 
Entergy, from Mid-America Interconnected Network into Wisconsin-Upper 
Michigan Systems, and into Florida.
    60. Transmission congestion can have significant cost impacts on 
consumers. In 2002, DOE issued a study estimating the costs of 
congestion in four U.S. regions: California, PJM, New York and New 
England.\60\ DOE found that, despite the overall savings of wholesale 
electricity markets that lowered consumers' electricity bills by nearly 
$13 billion annually, interregional transmission congestion cost 
consumers hundreds of millions of dollars annually. DOE concluded that 
relieving bottlenecks in these four regions alone could save consumers 
about $500 million annually.\61\ In 2006, DOE released another study 
identifying two areas of the country with severe existing or growing 
congestion problems: the Atlantic coastal area from metropolitan New 
York southward through Northern Virginia, and Southern California.\62\
---------------------------------------------------------------------------

    \60\ U.S. Department of Energy, National Transmission Grid Study 
at 11, 16-17 (May 2002), available at http://www.ferc.gov/industries/electric/indus-act/transmission-grid.pdf.
 To conduct this 

study, DOE estimated the benefits of interregional wholesale power 
markets using the Policy Office Electricity Modeling System (POEMS). 
POEMS is a national energy model designed specifically to examine 
the impacts of electricity restructuring. The model includes 
economic, regional, and temporal detail that is needed to analyze 
the economics of interregional trade. In the first step of the 
study, DOE used POEMS to examine the cost reductions that would 
occur if increased electricity transfers across congested paths were 
allowed in these four regions, assuming generators bid their 
marginal costs. Under this assumption, consumer costs declined by 
$157 million per year. In the second step, DOE calculated the 
increase in congestion costs under the assumption that generators 
bid above their marginal operating costs when supplies are tight and 
additional electricity cannot be imported. The price spikes were 
assumed to occur during hours when at least one transmission link 
into a sub-region was congested and demand was greater than 90 
percent of peak demand. When prices spike an additional $50 per MWh 
(above the price predicted when generators bid their marginal 
operating cost) during these periods, congestion costs nearly double 
to $300 million.
    \61\ Id. at xi and ii.
    \62\ U.S. Department of Energy, National Electric Transmission 
Congestion Study, Executive Summary at 2 (August 2006), available at 
http://www.ferc.gov/industries/electric/indus-act/doe-congestion-study-2006.pdf
.

---------------------------------------------------------------------------

    61. The decline in transmission investment and increase in 
transmission congestion underscore our concerns over inadequate 
planning provisions of the existing pro forma OATT. The existing pro 
forma OATT, as indicated above, contains very little specificity 
regarding how transmission planning should be conducted, how customers' 
needs are incorporated into that process, and what information is 
publicly available regarding the transmission providers' assumptions, 
criteria and data used in the planning process. These inadequacies are 
sufficiently severe, standing alone, to merit reform of the OATT. 
However, they are of even greater concern given the current state of 
the transmission grid. With inadequate levels of investment in the grid 
and increasing transmission congestion, customers' ability to access 
alternatives to the transmission provider's resources is limited. It is 
therefore imperative for the Commission to ensure that the planning 
process under each transmission provider's OATT is sufficient to 
prevent undue discrimination and transparent enough to detect any 
remaining instances of undue discrimination. We have done so in the 
reforms adopted and explained in section V.B.

D. A Consistent Method of Measuring ATC Is Needed

    62. Another area in which transmission providers have significant 
discretion under the pro forma OATT is the calculation of ATC. While 
Order No. 888 obligated each public utility to calculate the amount of 
transfer capability on its system available for sale to third parties, 
the Commission did not standardize the methodology for calculating ATC, 
nor did it impose any specific requirements regarding the disclosure of 
the methodologies used by each transmission provider.\63\ As a result, 
there are a variety of ATC calculation methodologies in use today and 
very few clear rules governing their use. Moreover, there is often very 
little transparency about the nature of these calculations, given that 
many transmission providers have filed only summary explanations of 
their ATC methodologies in Attachment C to their OATTs.
---------------------------------------------------------------------------

    \63\ Order No. 888 at 31,794 n.610.
---------------------------------------------------------------------------

    63. In the NOPR, the Commission noted that, although the industry 
has sought to pursue greater consistency in ATC calculations through 
existing NERC processes, these efforts to date have been largely 
unsuccessful. The Commission expressed its preliminary determination 
that the lack of a consistent, industry-wide methodology for 
calculating ATC gives transmission providers the ability and the 
opportunity to unduly discriminate against third parties. The 
Commission therefore proposed a number of reforms to the process of 
calculating ATC to provide clarity and transparency to users of the 
grid.
Comments
    64. As discussed further in section V.A below, most commenters 
support the Commission's goal of requiring greater consistency in the 
manner in which ATC is calculated and additional transparency of ATC 
calculations. Commenters generally favor the Commission's proposal to 
increase consistency in the calculation of ATC, including consistent 
definitions of its components, data inputs, modeling assumptions, and 
data exchange and coordination protocols. For example, Exelon argues 
that each ATC component should be used in the same manner for all 
purposes (e.g., granting transmission service to third parties or for 
the transmission provider's own network load). Some commenters assert 
that industry-wide standardization of ATC calculation might not be 
possible and that the Commission should consider interconnection-wide, 
regional or even sub-regional standardization. Others suggest allowing 
flexibility in order to capture differences in system operation, usage, 
market operations and topology.
    65. At the technical conference organized in this proceeding on 
October 12, 2006 (October 12 Technical Conference), the entire panel 
agreed that definitions must be consistent and a panelist representing 
Constellation

[[Page 12277]]

asserted that broad differences in the core definitions of the ATC 
calculation are neither rational nor explainable.\64\ NERC, however, 
recognized that the goal of achieving consistency may not mean that a 
single ATC methodology is required.\65\ NERC explained that consistency 
can be achieved with a limited number of methodologies if the 
requirements of those methodologies are properly coordinated and 
communicated.
---------------------------------------------------------------------------

    \64\ Transcript of October 12 Technical Conference at 149-50, 
available at Preventing Undue Discrimination and Preference in 
Transmission Service, Technical Conference (Docket No. RM05-25-000).
    \65\ Id. at 125-50.
---------------------------------------------------------------------------

    66. Numerous commenters support the Commission's proposals to 
increase transparency in the manner in which transmission providers 
derive ATC, including greater OASIS posting. Commenters opposing the 
transparency-related reforms focus on the Commission's proposal to 
require the posting of narratives on OASIS explaining reasons for 
changes in monthly and yearly ATC values on constrained paths. They 
argue that such a requirement would be too burdensome and would not 
provide customers with any significant new information.
    67. Several commenters believe that making substantial ATC 
calculation and modeling data transparent will compromise Critical 
Energy Infrastructure Information (CEII) but provide suggestions for 
resolving the issue. Others express concern that the data required for 
posting on OASIS is not CEII but commercially sensitive. Finally, 
commenters provide suggestions regarding the requirement to post 
metrics on OASIS related to the provision of transmission service under 
the pro forma OATT, including various additional metrics the Commission 
should consider. Others state that this information is already 
available on OASIS.
Commission Determination
    68. We find that the lack of a consistent and transparent 
methodology for calculating ATC gives transmission providers the 
ability and opportunity to unduly discriminate in the provision of open 
access transmission service. There are few clear rules respecting ATC 
calculation, and transmission providers retain unnecessarily broad 
discretion in this area. This resulting discretion is a significant 
problem because calculation of ATC, which varies greatly depending on 
the criteria and assumptions used, may allow the transmission provider 
to discriminate in subtle ways against its competitors. On systems 
where transmission capacity is congested, this lack of consistency, 
coupled with a lack of transparency, is of heightened importance and 
has led to recurring disputes over whether the transmission provider is 
exercising its discretion to discriminate against its competitors. This 
discretion also hampers the detection of undue discrimination and, 
thereby, undermines the Commission's ability to enforce the general 
requirement in Order No. 888 that transmission service be provided on a 
not unduly discriminatory basis.
    69. As discussed more fully below in section V.AIII.D, this Final 
Rule adopts a number of reforms that address the potential for 
remaining undue discrimination in the determination of ATC by requiring 
consistency in how ATC is evaluated, as well as providing greater 
transparency about how a transmission provider calculates and allocates 
ATC.

E. Discriminatory Pricing of Imbalances

    70. Order No. 888 focused primarily on the adoption of non-rate 
terms and conditions of service, rather than instituting broad reform 
of the Commission's transmission pricing policies. Consistent with this 
focus, the Commission did not propose broad transmission pricing reform 
in the NOPR, but rather focused on instances where current pricing 
practices under the pro forma OATT may no longer be sufficient to 
remedy undue discrimination or ensure just and reasonable rates. One 
significant reform proposed in the NOPR related to charges for 
imbalance energy. The Commission preliminarily found that the existing 
policies provide wide discretion in the development of these charges 
and hence the potential for undue discrimination. The Commission 
therefore proposed certain principles to remedy that potential and 
sought comment on whether a specific imbalance pricing method would be 
appropriate.
Comments
    71. In general, transmission customers complain about the level and 
scope of energy and generator imbalance charges that are levied under 
the pro forma OATT and under individual interconnection agreements.\66\ 
Customers complain that energy imbalance charges are excessive and not 
related to the actual costs incurred by transmission providers. They 
also argue that the inconsistency between these charges in different 
control areas is unnecessary, and that other means of compensating the 
transmission provider, such as return-in-kind, should be considered. 
Generators likewise complain that generator imbalance charges are 
excessive, that transmission providers refuse to credit generators with 
the revenues resulting from imbalance penalties that are collected, and 
that transmission providers prevent unaffiliated generators from 
purchasing or self-supplying generator imbalance services. In addition, 
owners of intermittent resources complain that generator imbalance 
charges, which are imposed to provide an incentive for generators to 
schedule accurately, are inappropriate given their lack of control and 
ability to cure deviations.
---------------------------------------------------------------------------

    \66\ Energy imbalance charges, including penalties on some 
systems, are imposed on a transmission customer when the amount of 
energy scheduled for delivery to the transmission grid does not 
equal the amount of energy withdrawn by that customer. Generator 
imbalance charges are levied on generators for deviations between 
the amount of energy they schedule and the amount they actually 
deliver to the grid.
---------------------------------------------------------------------------

Commission Determination
    72. The Commission agrees that imbalance charges should provide 
appropriate incentives to keep schedules accurate without being 
excessive. We also find that consistency in imbalance charges, both 
between and among energy and generator imbalances, is preferable to the 
wide variety of imbalance provisions in place today. All imbalances 
have the same net effect on the transmission system in that they 
require other generation to be ramped up or down to compensate for the 
imbalance. As such, the Commission adopts two pro forma OATT provisions 
(Schedule 4 for energy imbalances and Schedule 9 for generator 
imbalances) based on a tiered structure similar to the imbalance 
provision used by Bonneville, as described further below. Such an 
approach recognizes the link between escalating deviations and 
potential reliability impacts on the system while keeping imbalance 
charges closely related to incremental costs. The Commission finds, 
however, that intermittent resources should be exempt from the highest-
tier deviation band. We also require transmission providers to credit 
to all non-offending transmission customers the revenues they collect 
in excess of incremental costs.

F. Redispatch/Conditional Firm

    73. In the NOPR, the Commission examined whether existing methods 
for evaluating requests for long-term firm point-to-point service 
continue to be just and reasonable. When a transmission provider 
considers a new resource to serve native load, the transmission 
provider does not eliminate an otherwise economic option because the 
resource may not be

[[Page 12278]]

deliverable during a few hours of the year. For transmission customers, 
however, the transmission provider evaluates whether service can be 
granted in every hour of the year that is modeled and, if not, it 
informs the customer that service cannot be provided out of existing 
transfer capability. Only if the transmission customer agrees to pay 
for facilities studies does the transmission provider evaluate 
redispatch options, including whether they are less expensive than the 
upgrade costs. The Commission therefore proposed to reform the existing 
pro forma OATT planning redispatch \67\ obligation, or, in the 
alternative, to add a conditional firm service to the pro forma OATT. 
As proposed by the Commission, conditional firm would have been a long-
term service allowing the transmission provider to give a lower 
curtailment priority than firm to the transmission customer during a 
pre-specified number of hours.
---------------------------------------------------------------------------

    \67\ Although pro forma OATT section 13.5 refers to 
``redispatch,'' we refer to it here as ``planning redispatch'' to 
distinguish it from the reliability redispatch provisions in the 
network integration transmission service sections of the pro forma 
OATT. See infra notes 552 and 557.
---------------------------------------------------------------------------

Comments
    74. Some commenters support the inclusion of both a modified 
planning redispatch obligation and a conditional firm service in the 
pro forma OATT, stating that both are required to remedy undue 
discrimination and provide for comparable transmission service. These 
commenters urge the Commission to require transmission providers to 
offer planning redispatch and conditional firm service and allow 
customers to choose the option that best suits their physical, 
commercial and economic circumstances.
    75. Others opine that conditional firm service may be simpler and 
less costly to implement. These commenters prefer the development of 
conditional firm service over the modifications to the planning 
redispatch service because of the complexities surrounding redispatch 
costs and protocols. For example, Entergy believes conditional firm 
service can provide benefits to transmission customers without unfairly 
socializing costs to native load and network customers of the 
transmission provider.
    76. On the other hand, many commenters argue that the Commission 
should not require either option because the services are unnecessary, 
operationally unworkable, and legally unjustified, or because they 
would harm reliability and the quality of existing network service and 
provide disincentives for transmission investment. Several commenters 
state that these services would make curtailments of existing firm 
service more likely and limit opportunities for use of secondary 
network service, thereby harming native load protections and reducing 
reliability, contrary to FPA sections 215 and 217 respectively. While 
it recognizes that conditional firm service has been successful in 
parts of the Western Interconnection, NRECA contends that a mandate 
would undermine responsible planning and expansion of the transmission 
grid by harnessing the transmission provider's planning and dispatch 
functions to frame elaborate service conditions for conditional firm 
service.
    77. Several commenters argue that, if the services are required, 
the Commission should ensure that reliability is not adversely 
affected. Others urge the Commission to make the new services an 
interim option until transmission upgrades are in place to provide firm 
service. Some commenters believe planning redispatch and conditional 
firm customers should bear the actual costs of the services received, 
including costs associated with system operational changes needed to 
accommodate the services. A few commenters believe that the Commission 
should allow for regional differences in development of the new 
services.
Commission Determination
    78. The Commission believes it is necessary to modify the manner in 
which transmission providers assess point-to-point service requests to 
eliminate the potential for undue discrimination in transmission 
service. We find that both techniques--planning redispatch and 
conditional firm service--are currently used under certain 
circumstances by transmission providers to serve native load and, 
therefore, that transmission customers should have comparable services 
in order to avoid undue discrimination, facilitate the provision of 
long-term transmission service and provide customers with greater 
flexibility in choosing resources to meet their needs. We expect that 
both options will help integrate new generation more quickly. This can 
be particularly beneficial to renewable generation resources, such as 
wind, that can be constructed more quickly than the transmission 
upgrades necessary to deliver their power on a firm basis over the 
long-run.

G. EPAct 2005 Emphasized Certain Policies and Priorities for the 
Commission

    79. Finally, we note that the reforms adopted in this proceeding 
are consistent with the policies and priorities embodied in EPAct 2005, 
in which Congress emphasized many of the same principles reflected in 
this Final Rule. First, in EPAct 2005, Congress placed special emphasis 
on the development of transmission infrastructure. Congress required 
the Commission to adopt a rule establishing incentive-based rates for 
new transmission infrastructure investment. The stated purpose of new 
FPA section 219 is to benefit ``consumers by ensuring reliability and 
reducing the cost of delivered power by reducing transmission 
congestion.'' \68\ Among other steps, FPA section 219 requires the 
Commission to ``(1) Promote reliable and economically efficient 
transmission and generation of electricity by promoting capital 
investment in the enlargement, improvement, maintenance, and operation 
of all facilities for the transmission of electric energy in interstate 
commerce, regardless of the ownership of the facilities; (2) provide a 
return on equity that attracts new investment in transmission 
facilities (including related transmission technologies); [and] (3) 
encourage deployment of transmission technologies and other measures to 
increase the capacity and efficiency of existing transmission 
facilities and improve the operation of the facilities.'' \69\ In 
addition, Congress directed the Commission to encourage the deployment 
of advanced transmission technologies.\70\ Congress also gave the 
Commission certain ``backstop'' transmission siting authority, and 
authorized the creation of interstate compacts establishing 
transmission siting agencies.\71\ Finally, the Commission was directed 
to exercise its authority under EPAct 2005 ``in a manner that 
facilitates the planning and expansion of transmission facilities to 
meet the reasonable needs of load-serving entities to satisfy the

[[Page 12279]]

service obligations of the load-serving entities, and enables load-
serving entities to secure firm transmission rights * * * on a long-
term basis for long-term power supply arrangements made, or planned, to 
meet such needs.'' \72\ Although these provisions have been, or will 
be, addressed primarily in other proceedings, we conclude that the 
Final Rule is consistent with these provisions because it supports 
improvements in infrastructure by reforming the transmission planning 
process to ensure that it is open, transparent and nondiscriminatory.
---------------------------------------------------------------------------

    \68\ EPAct 2005 sec. 1241 (to be codified at section 219 of the 
FPA, 16 U.S.C. 824s). The Commission has issued a Final Rule 
implementing such an incentive rate program. See Order Nos. 679 and 
679-A.
    \69\ FPA Sec. 219(b)(1).
    \70\ EPAct 2005 sec. 1223 (to be codified at 42 U.S.C. 16442).
    \71\ EPAct 2005 sec. 1221(a) (to be codified at section 216 of 
the FPA, 16 U.S.C. 824p). The Commission implemented new regulations 
in accordance with this section to establish filing requirements and 
procedures for entities seeking to construct electric transmission 
facilities in Order No. 689.
    \72\ EPAct 2005 sec. 1233(a) (to be codified at section 
217(b)(4) of the FPA, 16 U.S.C. 824q). The Commission implemented 
FPA section 217(b)(4) in Long-Term Firm Transmission Rights in 
Organized Electricity Markets, Order No. 681, 71 FR 43564 (Aug. 1, 
2006), FERC Stats. & Regs. ] 31,226 (2006), order on reh'g, Order 
No. 681-A, 117 FERC ] 61,201 (2006), reh'g pending.
---------------------------------------------------------------------------

    80. Second, Congress emphasized the need for greater transparency 
in electricity markets, including transmission service. EPAct 2005 
added section 220 to the FPA, which requires the Commission to 
facilitate ``price transparency in markets for the sale and 
transmission of electric energy in interstate commerce, having due 
regard for the public interest, the integrity of [that market], fair 
competition, and the protection of consumers.'' \73\ The Commission was 
authorized to ``prescribe such rules as the Commission determines 
necessary and appropriate to carry out the purposes of'' FPA section 
220. Those rules ``shall provide for the dissemination, on a timely 
basis, of information about the availability and prices of wholesale 
electric energy and transmission service to the Commission, State 
commissions, buyers and sellers of wholesale electric energy, users of 
transmission services, and the public.'' This Final Rule similarly will 
promote greater transparency in the provision of transmission service 
in many important areas, including ATC calculation and transmission 
planning.
---------------------------------------------------------------------------

    \73\ EPAct 2005 sec. 1281 (to be codified at 16 U.S.C. 824t).
---------------------------------------------------------------------------

    81. Finally, Congress emphasized compliance with the Commission's 
regulations, increasing the civil and criminal penalties for violations 
of Commission-administered statutes and regulations.\74\ This new 
authority buttresses the Commission's efforts to enforce public utility 
OATTs and the regulations requiring transmission information to be 
posted on OASIS. As we explained in the Policy Statement on 
Enforcement, however, this new authority carries with it the 
responsibility to ensure that enforcement is firm but fair and that our 
rules are as clear as practicable to facilitate compliance.\75\ We 
conclude that this Final Rule is fully consistent with these principles 
because it clarifies our rules, in many areas, which will facilitate 
compliance by transmission providers.
---------------------------------------------------------------------------

    \74\ EPAct 2005 sec. 1284(e)(1) (to be codified at section 
316(A) of the FPA, 16 U.S.C. 825o-1).
    \75\ Enforcement of Statutes, Orders, Rules and Regulations, 
Policy Statement on Enforcement, 113 FERC ] 61,068 (2005) (Policy 
Statement on Enforcement).
---------------------------------------------------------------------------

IV. Summary, Scope and Applicability of the Final Rule

    82. This section provides a summary of the major components of the 
Final Rule, a description of the core elements of Order No. 888 that we 
retain, and a discussion of the applicability of the proposed rule to 
various entities.

A. Summary of Reforms

    83. Consistency and transparency of ATC calculations. The 
Commission affirms the finding in the NOPR that the lack of a 
consistent, industry-wide methodology for calculating ATC, and the lack 
of adequate transparency in ATC calculations, increases the potential 
for undue discrimination and also makes undue discrimination more 
difficult to detect. The lack of consistent standards can facilitate 
undue discrimination by giving a transmission provider the discretion, 
and hence the ability and opportunity, to favor itself and its 
affiliates over third parties in how it calculates and allocates ATC. 
In this Final Rule, we give the industry specific guidance regarding 
the calculation of ATC and establish a firm deadline to develop certain 
requirements to make more consistent the ATC calculation process and 
the process of exchanging data between transmission providers about 
ATC. In addition, we amend pro forma OATT requirements as well as our 
OASIS regulations to increase the transparency in how ATC is 
calculated.
    84. Requirement for coordinated, open and transparent transmission 
planning. The Commission also affirms the finding in the NOPR that 
Order No. 888 does not contain sufficient protections to guard against 
undue discrimination in transmission system planning. Without adequate 
coordination and open participation, market participants have minimal 
input or insight into whether a particular transmission plan treats all 
loads and generators comparably. To ensure that truly comparable 
transmission service is provided by all public utility transmission 
providers, including RTOs and ISOs, we amend the pro forma OATT to 
require coordinated, open, and transparent transmission planning on 
both a sub-regional and regional level. To implement this remedy, we 
adopt the eight planning principles proposed in the NOPR, as well as 
one additional principle, that each public utility transmission 
provider will be required to follow. We recognize that many regions 
have made significant progress in recent years in creating greater 
openness and transparency in transmission planning and believe our 
proposed reforms will build upon, strengthen, and improve this progress 
to reform transmission planning.
    85. Transmission Pricing Reforms. Consistent with the focus of 
Order No. 888 on the non-rate terms and conditions of open access, the 
Commission does not initiate broad reform of transmission pricing 
policy through this Final Rule. However, we have identified several 
pricing rules that are part and parcel of OATT service that merit 
reform.
     Energy and Generator Imbalance Charges. We find that 
energy and generator imbalance charges we have previously accepted are 
excessive, too varied, and otherwise unrelated to the cost of providing 
the service and, therefore, we reform energy and generator imbalance 
pricing. We adopt tiered pro forma OATT energy and generator imbalance 
provisions similar to those in use by Bonneville and exempt 
intermittent resources from the highest deviation band. In these new 
provisions, imbalance charges are based on incremental cost and 
escalate as the imbalance increases. Any deviations from these 
provisions must be consistent with or superior to the pro forma OATT as 
modified by this Final Rule and must meet the following criteria: the 
charges must (1) Be related to the cost of correcting the imbalance, 
(2) be tailored to encourage accurate scheduling behavior, such as by 
increasing the percentage of the adder as the deviations become larger, 
and (3) account for the special circumstances presented by intermittent 
generators, such as by waiving the higher ends of the deviation 
penalties.
     Capacity Reassignment Pricing. We find that the existing 
cap on the reassignment of point-to-point service is no longer just and 
reasonable and, therefore, we eliminate the cap. We believe that 
removing the cap will eliminate an unnecessary impediment to the resale 
of capacity, which in turn should increase utilization of the grid and 
otherwise ensure that point-to-point service is just, reasonable, and 
not unduly discriminatory.

[[Page 12280]]

     Crediting of Customer-Owned Facilities. We retain most 
elements of our existing policy respecting the crediting of customer-
owned facilities, including the requirement that such facilities meet 
the integration standard. However, we eliminate the requirement that 
new facilities can receive credits only if they are ``jointly planned'' 
because this requirement provides a disincentive to coordinated 
planning. Rather, we provide that such new facilities are eligible for 
credits if such facilities are integrated into the operations of the 
transmission provider's facilities. Customer-owned facilities shall be 
presumed to be integrated if those facilities, if owned by the 
transmission provider, would be eligible for inclusion in the 
transmission provider's annual transmission revenue requirement.
    86. Improvements to Point-to-Point Service. The Commission 
concludes that the existing methods for evaluating requests for long-
term firm point-to-point service are no longer just, reasonable, and 
not unduly discriminatory. The existing pro forma OATT allows the 
transmission provider to deny a request for long-term point-to-point 
service if that service is not available in a single hour of the period 
studied. We find that this approach is not comparable because, when a 
transmission provider considers a new resource to serve native load, 
the transmission provider does not eliminate an otherwise economic 
option because the resource may not be deliverable in a few hours of 
the year. To remedy this problem, the Commission adopts a ``conditional 
firm'' component to long-term point-to-point service that addresses the 
situation where firm service can be provided for most, but not all, 
hours of the period requested. We also reform the existing requirements 
for the provision of redispatch service to ensure that they are of 
greater use to transmission customers and more consistent with 
reliability planning and operation of the system.
    87. Reform of rollover rights. The Commission concludes that 
section 2.2 of the pro forma OATT, which grants an ongoing right to 
transmission customers to renew or ``roll over'' their contracts, 
should be reformed. The current rollover rights do not provide 
consistency between the rights of rollover customers and the resulting 
obligations of transmission providers to plan and upgrade the system to 
accommodate rollovers. The Commission therefore amends section 2.2 to 
ensure greater consistency with transmission planning and construction 
timelines and modifies the minimum term of the rollover rights to five 
years, rather than the current minimum term of one year. The Commission 
also requires that a transmission customer eligible for rollover rights 
provide notice of whether or not it will exercise its right of first 
refusal to renew the contract no less than one year before the 
expiration date of the transmission service agreement, rather than 
within the current 60-day period.
    88. Increases in transparency to lessen the opportunities to 
discriminate and reduce transaction costs. In addition to the increased 
transparency we require regarding the calculation of ATC and 
transmission planning, we increase the transparency of transmission 
service provided under the pro forma OATT in several other respects. 
For example, we require transmission providers and their network 
customers to use the transmission providers' OASIS to request 
designation of a new network resource and to terminate the designation 
of an existing network resource. In addition, we require transmission 
providers to modify their OASIS so that requests to designate and 
terminate a network resource can be queried, allowing all parties 
access to such information. We also require transmission providers to 
post a list of their current designated network resources and all 
network customers' current designated network resources on their OASIS. 
Finally, we require transmission providers to post on OASIS all their 
business rules, practices and standards that relate to transmission 
services provided under the pro forma OATT.
    89. Strengthening enforcement of the pro forma OATT. The reforms 
adopted in this Final Rule provide greater clarity in the terms and 
conditions of the pro forma OATT, resolving ambiguities in the existing 
pro forma OATT that have made undue discrimination easier to accomplish 
and more difficult to detect. Our new civil penalty authority under 
EPAct 2005 gives us ample power to remedy tariff violations, but it 
also places upon us an increased responsibility to make the rules as 
clear as possible. We fulfill that responsibility in the Final Rule by 
providing greater clarity where appropriate to several critical OATT 
provisions. We also adopt a number of posting and reporting 
requirements that will provide the Commission and market participants 
with information about each transmission provider's performance of pro 
forma OATT obligations. For example, we require transmission providers 
to post specific performance metrics related to their completion of 
studies required under the pro forma OATT. We note that the Commission 
will continue to audit compliance with the pro forma OATT, and toward 
that end require transmission information kept on OASIS to be retained 
for audit purposes for five years. Finally, we adopt a number of 
reforms to operational penalties assessed under the pro forma OATT, 
including so-called ``over-use'' penalties and the treatment of 
operational penalty revenues collected from transmission providers and 
their affiliates.
    90. Miscellaneous OATT improvements. Finally, we implement a number 
of improvements to the terms and conditions of the pro forma OATT to 
incorporate the lessons learned over the past ten years. We briefly 
note these below:
     Designation of network resources. We provide clarification 
regarding the types of agreements that may be designated as network 
resources, the process for verifying whether agreements meet the 
requirements in the pro forma OATT, and the requirement for 
transmission providers to designate and undesignate network resources. 
We also require customers to submit an attestation with each 
application to designate a new network resource.
     Reservation priorities. We change the priority rules to 
give certain priority to pre-confirmed transmission service requests 
submitted in the same time period. We also add price as a tie-breaker 
in determining reservation queue priority when the transmission 
provider is willing to discount transmission service.
     Clarifications related to network service. We provide 
clarification related to use of network service on an ``as available 
basis'' and to ``redirects'' of network service.

B. Core Elements of Order No. 888 That Are Retained

    91. Although we are adopting many important reforms to Order No. 
888 and the pro forma OATT in this Final Rule, we emphasize that many 
of the core elements of Order No. 888 are retained. As the Commission 
noted in the NOPR, many of these core elements enjoy broad support from 
many sectors of the industry. A variety of commenters--in response to 
the NOI issued earlier in this proceeding and again in response to the 
NOPR--have urged the Commission to focus on meaningful incremental 
reforms to the pro forma OATT, rather than on industry restructuring. 
We share the view that Order No. 888 can be strengthened without 
discarding its fundamental structure. We discuss

[[Page 12281]]

below the core elements that are being retained and the comments 
received on these points.
1. Federal/State Jurisdiction
    92. In Order No. 888, the Commission stated that it has exclusive 
jurisdiction over the rates, terms, and conditions of unbundled retail 
transmission in interstate commerce.\76\ Though the Commission adopted 
a test for determining what constitute Commission-jurisdictional 
transmission facilities and what constitute State-jurisdictional local 
distribution facilities in situations involving unbundled wholesale 
wheeling and unbundled retail wheeling,\77\ the Commission stated that 
it generally would defer to determinations by State regulatory 
authorities concerning where to draw the jurisdictional line under that 
test.\78\ The Commission declined to assert jurisdiction over bundled 
retail transmission, reasoning that ``when transmission is sold at 
retail as part and parcel of the delivered product called electric 
energy, the transaction is a sale of electric energy at retail.'' \79\ 
The U.S. Supreme Court affirmed the Commission's decision to assert 
jurisdiction over unbundled but not bundled retail transmission, 
finding that the Commission made a statutorily permissible choice.\80\ 
In the NOPR, the Commission proposed to retain the jurisdictional 
divide established in Order No. 888.
---------------------------------------------------------------------------

    \76\ Order No. 888 at 31,781.
    \77\ Id. at 31,771 (setting forth the seven-factor test).
    \78\ Id. at 31,781.
    \79\ Id.
    \80\ See New York v. FERC, 535 U.S. at 28.
---------------------------------------------------------------------------

Comments
    93. Several commenters support the Commission's proposal to retain 
the existing jurisdictional divide.\81\ Though APPA concludes that the 
most politic course at this juncture is to leave the current 
jurisdictional boundaries in place and develop cooperative mechanisms 
in each region to coordinate Federal policy implementation with the 
relevant State regulators, APPA notes that there is disagreement among 
its members about whether the current jurisdictional lines are properly 
drawn. APPA explains that a substantial number of its members believe 
that all interstate transmission services (both retail and wholesale) 
should be provided under one consistent set of tariff terms and 
conditions. Other APPA members, however, believe that the Commission 
made the proper jurisdictional call in Order No. 888. NARUC urges the 
Commission to clarify that its planning proposals will not reopen or 
attempt to change the jurisdictional split over transmission facilities 
delineated in Order No. 888.
---------------------------------------------------------------------------

    \81\ E.g., Ameren, APPA, North Carolina Commission Reply, PNM-
TNMP, and Southern.
---------------------------------------------------------------------------

Commission Determination
    94. The Commission will retain the existing jurisdictional divide 
that was established in Order No. 888, which has been affirmed by the 
U.S. Supreme Court and accepted by the industry and State regulatory 
authorities.\82\ We also reiterate our recognition of the need for 
heightened cooperation between Federal and State regulators in areas 
where there are overlapping Federal and State policy concerns. As 
explained in greater detail in the planning section below, and in 
response to NARUC's concern, the planning reforms adopted in the Final 
Rule contemplate coordinated and open transmission planning, but do not 
reopen or otherwise change the existing jurisdictional divide for 
transmission facilities.
---------------------------------------------------------------------------

    \82\ See New York v. FERC, 535 U.S. at 28.
---------------------------------------------------------------------------

2. Native Load Protection
    95. In Order No. 888, the Commission did not require transmission 
providers to unbundle transmission service to their retail native load. 
The Commission also did not require that bundled retail service be 
taken under the terms of the pro forma OATT.\83\ Moreover, the 
Commission allowed a transmission provider to reserve, in its 
calculation of ATC, transmission capacity necessary to accommodate 
native load growth reasonably forecasted in its planning horizon.\84\ 
Order No. 888 also granted a rollover right to existing firm service 
customers,\85\ but allowed transmission providers to restrict that 
rollover right if the capacity was reasonably forecasted as needed to 
serve native load customers, as long as that restriction was set forth 
in the customer's initial service contract.\86\
---------------------------------------------------------------------------

    \83\ Order No. 888 at 31,745.
    \84\ Id. at 31,694.
    \85\ Id.; see pro forma OATT section 2.2.
    \86\ Order No. 888-A at 30,198.
---------------------------------------------------------------------------

    96. Congress, in section 1233 of EPAct 2005, added section 217 to 
the FPA, entitled ``Native Load Service Obligation,'' which addresses 
transmission rights held by load-serving entities (LSEs). FPA section 
217 allows LSEs to use their own and contracted-for transmission 
capacity to deliver energy as required to meet their service 
obligations, without being subject to charges of unlawful 
discrimination. The provision makes clear, however, that this 
requirement does not abrogate any contract or service agreement for 
firm transmission service or rights in effect as of the date of 
enactment of EPAct 2005.\87\ In the NOPR, the Commission concluded that 
the protection of native load embodied in Order No. 888 is consistent 
with FPA section 217, and reaffirmed its commitment to the protection 
of native load.
---------------------------------------------------------------------------

    \87\ 16 U.S.C. 217(f).
---------------------------------------------------------------------------

Comments
    97. Several commenters agree with the Commission's preliminary 
conclusion that the protection of native load embodied in Order No. 888 
is consistent with FPA section 217 and support the Commission's 
continued commitment to the protection of native load.\88\ While APPA 
\89\ and TAPS generally agree with the Commission that the overall OATT 
regime is consistent with section 217, they urge the Commission to 
maintain and reinforce the comparability requirement. APPA urges the 
Commission to broaden its preliminary conclusion in the NOPR and 
conclude instead that the protection of native load and the provision 
of fully comparable transmission service to other LSEs with long-term 
service obligations, as embodied in Order No. 888, are consistent with 
FPA section 217. TAPS also supports the Commission's reading of FPA 
section 217 as consistent with the Order No. 888 pro forma OATT's 
``native load'' priority, recognizing that FPA section 217 reinforces 
the OATT's commitment to comparable treatment of all LSEs--e.g., 
transmission providers and network customers.
---------------------------------------------------------------------------

    \88\ E.g., Ameren, E.ON, Tacoma, Arkansas Commission, EPSA, 
Southern, and TAPS.
    \89\ APPA argues that the proposed definition of native load 
customers in section 1.21 is not technically consistent with FPA 
section 217 because FPA section 217 does not distinguish among the 
types of power supply arrangements that an LSE must have to enjoy 
the protection of FPA section 217. Nevertheless, APPA states that it 
would not be fruitful to reopen the entire OATT framework to address 
this technical (but very important) definitional difference.
---------------------------------------------------------------------------

    98. Other commenters dispute the Commission's preliminary 
conclusion that the native load protection embodied in Order No. 888 is 
consistent with FPA section 217.\90\ Many commenters argue that FPA 
section 217 protects all load, not just native load.\91\ Constellation 
states that the Commission must recognize that there are other market 
participants besides the transmission providers themselves that are 
LSEs under FPA section 217. Under the definition of LSEs in FPA section

[[Page 12282]]

217, EPSA argues that many entities other than traditional, vertically-
integrated utilities are in the business of serving load. The statute, 
EPSA asserts, applies to any native load service obligation, whether 
that obligation is served by a competitive supplier, an affiliate of 
the transmission provider, or by the transmission provider itself. Salt 
River contends that FPA section 217 is self-implementing, though it 
urges the Commission to act to remove impediments to the full exercise 
of rights granted to LSEs.
---------------------------------------------------------------------------

    \90\ E.g., Arkansas Municipal, Constellation, Duke, Salt River, 
and South Carolina E&G.
    \91\ E.g., Constellation, EPSA, and South Carolina E&G.
---------------------------------------------------------------------------

    99. Constellation argues that the Commission should require native 
load and OATT customers to take service under the same terms and 
conditions because experience has proven that discrimination has 
occurred as a result of having two different sets of rules applicable 
to transmission customers. EPSA urges the Commission to further clarify 
that the transmission provider has an affirmative obligation to serve 
native load in a non-discriminatory manner. According to EPSA, section 
217 supports the Commission's paramount statutory mission of ensuring 
non-discrimination and makes clear that a transmission provider, when 
utilizing transmission capacity or rights reserved to serve native 
load, must ``put its blinders on'' to ensure that the load's needs are 
being met in the most economical way available, whether that decision 
means the deployment of its own affiliated generation, or the 
deployment of available non-utility alternatives.
    100. Arkansas Municipal asserts that FPA section 217 recognizes the 
need to give priority to LSEs in certain situations, such as when the 
transmission grid may be constrained and one group of customers may be 
denied service at the expense of other customers. Arkansas Municipal 
states that a priority list could be instituted in this reform 
proceeding that places LSEs at the top of the list in competing 
requests for transmission service when not all requests could be 
granted or honored by the transmission provider.
    101. New Mexico Attorney General argues that native load is 
fundamentally different than merchant load and therefore, in the 
planning process, the needs of merchants should not be treated 
comparably with the needs of New Mexico utilities' native loads. New 
Mexico Attorney General asserts that New Mexico utilities have a 
statutory obligation to serve retail load while merchants are free to 
come and go with cycles inherent in wholesale markets. According to New 
Mexico Attorney General, the transmission requirements of the 
utilities' native loads amount to an ongoing long-term firm contract, 
while the transmission needs of merchants are, by comparison, short-
term and speculative.
    102. Several commenters urge the Commission to revisit various 
aspects of the reforms proposed in the NOPR in order to enhance the 
protection of native load. For example, some commenters urge the 
Commission to modify the rollover proposal in the NOPR. Salt River 
argues that the Commission's regulations must include a clear provision 
for a transmission owner anticipating, or unexpectedly facing, load 
growth to recapture capacity temporarily made available to the 
wholesale market. Arkansas Commission disagrees with the Commission's 
proposal to require a transmission provider to compete for transmission 
capacity rather than reclaim it through its rights to reserve capacity 
for future load growth. The proposal is inequitable, Arkansas 
Commission argues, because native load customers have historically paid 
for most of the transmission providers' assets and will continue to do 
so in the future. Because of this, Arkansas Commission asserts, native 
load customers should be given preference in the reservation of 
transmission capacity. In response to Arkansas Commission's position, 
MDEA urges the Commission to make clear, consistent with the 
comparability principle adopted in Order No. 888 and reaffirmed in the 
NOPR, and with FPA section 217, that any reservation of rights or 
preference available to a transmission provider's native load customers 
must be available to network customer loads as well. South Carolina E&G 
argues that the Commission's interpretation of ``reasonably 
forecasted'' capacity under section 2.2 of the pro forma OATT has been 
effectively impossible to meet and, therefore, the Commission should 
now provide clear standards for evaluation of native load protecting 
rollover restrictions. A clear standard, South Carolina E&G states, 
would have the Commission consider rollover restrictions in light of a 
utility's transmission planning process. On reply, Progress Energy 
supports South Carolina E&G's comments. Progress Energy urges the 
Commission to revisit the rollover rights policy to develop a policy by 
which an LSE may be assured of future transmission service for 
reasonably forecasted native load growth.
    103. South Carolina E&G also asks the Commission to revise section 
13.6 of the pro forma OATT, regarding curtailment of firm point-to-
point transmission service. South Carolina E&G urges the Commission to 
comply with the mandate of Northern States Power Co. v. FERC,\92\ which 
South Carolina E&G asserts held that the Commission had exceeded its 
authority in rejecting a vertically-integrated transmission provider's 
proposal to modify section 13.6 of the OATT to give a higher 
curtailment priority to native load. According to South Carolina E&G, 
the Commission has responded by applying the court's decision narrowly, 
but FPA section 217 requires the Commission to change that position and 
recognize the primacy of service to native load in section 13.6 of the 
OATT. In its reply comments, Progress Energy supports the comments of 
South Carolina E&G and states that the Commission must affirmatively 
recognize the priority of service to LSEs in the application of the 
curtailment priorities in section 13.6 of the OATT.
---------------------------------------------------------------------------

    \92\ 176 F.3d 1090, 1096 (8th Cir. 1999), cert. denied sub nom. 
Enron Power Marketing, Inc. v. Northern States Power Co., 528 U.S. 
1182 (2000).
---------------------------------------------------------------------------

    104. Duke argues that several of the Commission's proposed 
reforms--such as hourly firm service, redispatch, and conditional firm 
service--actually reduce the protection afforded native/network load. 
Salt River suggests that the Commission should modify its ATC proposal 
to bring the Commission's native load priority policies in line with 
FPA section 217. Salt River asserts that, in calculating ATC, the 
transmission provider must be able to exercise reasonable professional 
judgment as to the amount of transmission that must be reserved to meet 
native load service obligations; the Commission should not get into the 
business of dictating forecasting methodology. Salt River proposes that 
a native load forecast that is used by an LSE as the basis for 
committing capital for generation expansion or procurement should be 
presumed to be valid for purposes of establishing available capacity. 
EPSA, however, argues that, unless and until the Commission mandates a 
hard and enforceable definition of ATC, transmission-owning utilities 
that also own affiliated generation will continue to hide behind the 
native load service obligation as an excuse for being unable to find 
ATC for any but self-serving purposes.
    105. EPSA also argues that the Commission must ensure that 
transmission owners' planning accommodates all supply options. EPSA 
urges the Commission to clarify that transmission capacity reserved for 
native load is to be made available (including for study and other 
purposes) to competitive suppliers who wish to

[[Page 12283]]

serve native load as allowed by State law. According to EPSA, all 
generation assets ultimately serve load and the pro forma OATT should 
be clarified to ensure that the transmission system is available on a 
non-discriminatory basis now and in the future to ensure that load is 
optimally served--regardless of which generation resources are serving 
that load. In its reply comments, EPSA also challenges the initial 
comments of New Mexico Attorney General, which EPSA argues incorrectly 
interpret FPA section 217 as drawing a distinction between the types of 
generation that serve load. EPSA argues that the statute protects the 
customer load that all suppliers would seek to serve regardless of the 
source.
    106. APPA agrees with the Commission's response in the NOPR to 
Metropolitan Water District that the specific issues related to an 
RTO's provision of long-term transmission rights are better left to the 
rulemaking in Docket Nos. RM06-8-000 and AD05-7-000, and the 
proceedings in each RTO region to implement the Final Rule issued in 
those dockets on July 20, 2006. APPA notes, however, that the 
Commission has not proposed in this docket to exempt RTOs from the 
provisions of the NOPR. Rather, APPA notes, departures from the pro 
forma OATT, including departures in RTO OATTs, must be justified under 
the ``consistent with or superior to'' standard. APPA argues that the 
Commission should apply this standard to long-term transmission rights, 
as well as to the other terms and conditions of OATT transmission 
service that RTOs provide.
Commission Determination
    107. In Order No. 888, the Commission gave public utilities the 
right to reserve existing transmission capacity needed for native load 
growth reasonably forecasted within the utility's current planning 
horizon. The Commission also allowed transmission providers to restrict 
rollover rights based on reasonably forecasted need at the time the 
contract is executed. We continue to believe these protections for 
native load are appropriate and do not eliminate them in this Final 
Rule, as suggested by some commenters. We also believe that the 
protection of native load embodied in Order No. 888, as enhanced by the 
reforms adopted in this Final Rule, is consistent with FPA section 217, 
which protects the transmission rights of entities with service 
obligations to end-users or a distribution utility, to the extent 
required to meet their service obligations. The additional reforms 
proposed by commenters are not necessary at this time to remedy undue 
discrimination. We conclude that the native load priority established 
in Order No. 888 continues to strike the appropriate balance between 
the transmission provider's need to meet its native load obligations 
and the need of other entities to obtain service from the transmission 
provider to meet their own obligations.
    108. In response to comments regarding reforms needed to ATC 
calculation and transmission planning to bring the native load priority 
policies in line with FPA section 217, we believe that the Commission's 
reforms in this Final Rule appropriately reflect the transmission 
provider's obligation to serve native load. As discussed more fully in 
the ATC and planning sections below, the processes we adopt herein are 
open, transparent and non-discriminatory and assume that the 
transmission provider is meeting its obligations, including its native 
load service obligation. We disagree with Duke's assertion that the 
reforms proposed in the NOPR will result in a reduction of the 
protection afforded native or network load. Not only have we reaffirmed 
the fundamental protections for native load contained in Order No. 888, 
but we have modified, where appropriate, the pro forma OATT to ensure 
that a transmission provider's obligations can be met consistent with 
maintaining the reliability to existing customers, including native 
load. For example, we are eliminating the current requirement to 
provide planning redispatch over long periods of time (e.g., 10-30 
years) because it is unnecessary to remedy undue discrimination and can 
create problems in forecasting system conditions consistent with 
maintaining reliability to native load customers.\93\
---------------------------------------------------------------------------

    \93\ Proposals related to other reforms, such as curtailments 
and rollovers, are discussed in the sections below dealing with each 
of those issues.
---------------------------------------------------------------------------

    109. With regard to APPA's comments regarding long-term 
transmission rights in organized markets, we note that the Commission 
has issued its Final Rule in Docket Nos. RM06-8-000 and AD05-7-000.\94\ 
As discussed more fully in the applicability section of this 
rulemaking, and in response to APPA's comments, we reiterate that any 
departures from the pro forma OATT proposed by an ISO or an RTO must be 
``consistent with or superior to'' the pro forma OATT in this Final 
Rule.
---------------------------------------------------------------------------

    \94\ See supra note 72.
---------------------------------------------------------------------------

3. The Types of Transmission Services Offered
    110. In Order No. 888, the Commission required all public utilities 
to offer, on a non-discriminatory, open-access basis, firm network 
service and firm and non-firm point-to-point service. In the NOPR, the 
Commission proposed to retain these services and did not propose to 
require transmission providers to adopt a network contract demand 
service, either as a replacement for network or point-to-point service 
or as a third category of service under the OATT.
Comments
    111. Several commenters support the Commission's proposal to retain 
the current services in the pro forma OATT and to not adopt contract 
demand service.\95\ While APPA supports the Commission's proposal, it 
states that the Commission should remain open to individual public 
utility transmission provider's proposals to add ``hybrid'' service to 
the base network and point-to-point services.
---------------------------------------------------------------------------

    \95\ E.g., MISO/PJM States, TVA, and Southern.
---------------------------------------------------------------------------

    112. Other commenters, such as AMP-Ohio and Nevada Companies, argue 
that the Commission should require all transmission providers to offer 
network contract demand service. Nevada Companies argue that the 
Commission's network designation process can substantially interfere 
with State jurisdiction over resource acquisition, especially for 
transmission providers that are required to purchase substantial 
amounts of power to serve their retail customers instead of relying 
primarily on their own generation. Nevada Companies reason that 
allowing transmission providers to move to a contract demand-based 
network service would remove them from the dilemma of being forced to 
make resource procurement decisions that are inconsistent with State 
requirements. On reply, MidAmerican, Newmont Mining, and Utah 
Municipals oppose the suggestion that the contract demand service 
should be made a mandatory service offering in the pro forma OATT. In 
its reply comments, Newmont Mining states that, if the Commission is 
inclined to provide some relief to allow Nevada Companies to comply 
with both the pro forma OATT and their State-approved resource plans, 
that relief should come only after an investigation of how similar 
problems are handled on other systems and should be a narrowly and 
carefully monitored exception to the resource designation requirements.

[[Page 12284]]

    113. Alberta Intervenors argue that undue discrimination is most 
likely to occur in situations where there is a single or dominant 
network customer and that customer either has a dual mandate for 
serving the network customers or that customer has a ``free option'' 
for procuring transmission.\96\ Alberta Intervenors recommend that the 
Commission implement standardized rules with respect to the ``free 
option'' concept while offering regional flexibility to ensure the 
objectives of open access and the absence of undue discrimination 
continue to be advanced. Alberta Intervenors also argue that, despite 
the Commission's proposal to address undue discrimination against 
transmission customers in attempting to redirect to new receipt and 
delivery points, undue discrimination remains a concern since network 
customers retain a flexibility of receipt and delivery points that is 
not granted to third party point-to-point customers. This flexibility 
provided to the network customer allows the use of the system for 
activities known as ``parking'' \97\ and ``hubbing.'' \98\ Alberta 
Intervenors urge the Commission to eliminate this unfair competitive 
advantage under the OATT by making a common service available to all 
participants rather than differing service for network customers, or 
alternatively, by restricting the use of point-to-point services by the 
network customer to exclude its use for ``parking'' and ``hubbing.''
---------------------------------------------------------------------------

    \96\ Alberta Intervenors assert that the purchase of point-to-
point service by dominant network customers results in an equal and 
offsetting reduction to the network customer's network charges, 
resulting in a net cost of zero. They state that point-to-point 
service is a net cost to all competitors except the dominant network 
customer. Thus, they argue, a dominant network customer can buy 
point-to-point service for an extended period and use this service 
for a limited number of hours at little (or no) net cost compared to 
not purchasing point-to-point service for an extended period. In 
Alberta Intervenors' view, this ``free option'' provides network 
customers with a competitive advantage when reserving point-to-point 
service because it enables the network customers to over-consume or 
buy excess point-to-point service than they would if the true net 
cost were reflected. Alberta Intervenors contend that such over-
consumption reduces access to point-to-point service for other 
customers.
    \97\ Alberta Intervenors define ``parking'' as a network 
customer reserving point-to-point service using a network load point 
of delivery to purchase energy that it intends to sell but where no 
buyer has been identified at the time of the reservation. The energy 
notionally reduces network load. Once a buyer is found, the network 
customer completes the sale by delivering the energy from freed-up 
generation at a generation point of receipt to a buyer's point of 
delivery.
    \98\ Alberta Intervenors define ``hubbing'' as a practice very 
similar to ``parking,'' but involving multiple buyers and sellers. 
The network customer can reserve point-to-point transmission to 
purchase energy from multiple sellers and to sell energy to multiple 
buyers by creating a hub within its network load. Alberta 
Intervenors explain that this allows the network customer to 
organize purchases and sales by physically matching the requirements 
of multiple buyers and sellers.
---------------------------------------------------------------------------

    114. MidAmerican states that in the Western Interconnection, a 
utility's loads are not necessarily located within a confined 
geographical boundary served by a single transmission owner. In these 
cases, MidAmerican argues, neither network nor point-to-point service 
under the current pro forma OATT is suitable to serve those loads. To 
remedy these shortcomings in standard OATT service, MidAmerican states 
that the Commission should require the incorporation of dynamic 
scheduling and long-term, seasonally-shaped, firm point-to-point as new 
service offerings under the pro forma OATT.
Commission Determination
    115. The Commission will not alter the types of services that we 
required in Order No. 888. We continue to believe that network and 
point-to-point services are the appropriate base-line service offerings 
in the OATT, and we will not mandate that transmission providers adopt 
new service offerings such as network contract demand service. Although 
the Commission has accepted forms of network contract demand service 
proposed by individual transmission providers, and the service may 
provide benefits to certain customers, we do not believe the service is 
necessary to remedy undue discrimination. For example, the service 
would require a departure from full load-ratio pricing for network 
customers, which may not be warranted to the extent the transmission 
provider plans its system to serve all native load. However, while the 
Commission concludes that it will not require all transmission 
providers to offer this service, in response to the arguments raised by 
commenters such as AMP-Ohio and Nevada Companies, we reiterate that the 
Commission already has accepted forms of network contract demand 
service and will continue to entertain such proposals on a voluntary 
basis from transmission providers.
    116. The Commission also is not persuaded by Alberta Intervenors' 
and MidAmerican's arguments in support of further alternative services 
under the pro forma OATT. As with network contract demand service, 
transmission providers may propose such services if appropriate for 
their region. We do not believe mandating that such services be 
provided by all transmission providers is necessary at this time to 
prevent undue discrimination.
4. Functional Unbundling
    117. In Order No. 888, the Commission chose to mandate functional, 
rather than corporate (in which a public utility's transmission and 
generation assets would be placed in separate corporate entities), 
unbundling of transmission and generation services. The Commission 
explained that functional unbundling has three components:
    1. A public utility must take transmission services (including 
ancillary services) for all of its new wholesale sales and purchases of 
energy under the same tariff of general applicability as do others;
    2. A public utility must state separate rates for wholesale 
generation, transmission, and ancillary services;
    3. A public utility must rely on the same electronic information 
network that its transmission customers rely on to obtain information 
about its transmission system when buying or selling power.\99\
---------------------------------------------------------------------------

    \99\ Order No. 888 at 31,654.
---------------------------------------------------------------------------

    118. In the years following Order No. 888, a number of public 
utilities nonetheless underwent corporate unbundling. Many of these 
entities did so as a result of State-mandated restructuring laws. 
Others did so for corporate or tax reasons. Some entities divested all 
of their generation assets to a non-affiliate, while others simply 
restructured internally to place the generation assets in a different 
corporate subsidiary than the transmission assets. There remain, 
however, a significant number of vertically-integrated public utilities 
that operate under the functional unbundling approach.
    119. In the NOPR, we proposed to preserve the functional unbundling 
approach adopted in Order No. 888, rather than impose a corporate or 
structural unbundling requirement. While the Commission expressed its 
continued support for voluntary efforts to adopt structural changes 
(such as transmission-only companies, RTOs, or other reforms), the 
Commission found that the more intrusive and costly corporate 
unbundling was not necessary at this time. The Commission also declined 
to mandate an independent transmission coordinator for all transmission 
providers. Though the Commission has previously found that such 
entities may be appropriate in certain circumstances and we support 
voluntary efforts to rely on them,\100\ the

[[Page 12285]]

Commission concluded that there was not a sufficient basis for 
requiring them as a generic remedy for undue discrimination.
---------------------------------------------------------------------------

    \100\ See Duke Power, 113 FERC ] 61,288 (2005); MidAmerican 
Energy Co., 113 FERC ] 61,274 (2005); see also Entergy Services, 
Inc., 110 FERC 61,295 (2005), order on clarification, 111 FERC ] 
61,222 (2005), order conditionally approving filing, 115 FERC ] 
61,095 (2006).
---------------------------------------------------------------------------

Comments
    120. Commenters generally support the Commission's proposal to 
retain functional unbundling.\101\ APPA also supports the Commission's 
decision not to mandate an independent transmission coordinator for all 
public utility transmission providers. Similarly, Tacoma supports the 
Commission's decision to continue to view participation in an RTO or 
ISO as voluntary actions. While PJM and EPSA would prefer a structural 
remedy, they generally support the Commission's proposal to retain 
functional unbundling. However, EPSA states that given the Commission's 
proposal to continue to rely on functional unbundling, it is critical, 
particularly in those areas without organized markets, that OATT rules 
regarding unbundled transmission service be clear, transparent, 
consistent, and rigorously enforced. APPA states that it will be vital 
to obtain the cooperation of State regulators in each region where the 
OATT reforms will be implemented to ensure that the current functional 
unbundling regime in fact is sufficient to do the job.
---------------------------------------------------------------------------

    \101\ E.g., Santee Cooper, LPPC, TVA, Tacoma, Southern, MISO 
Transmission Owners, and E.ON.
---------------------------------------------------------------------------

    121. E.ON and TVA express concern that the Commission may yet 
choose a structural remedy. E.ON urges the Commission to look at the 
full depth and breadth of its existing powers to monitor and fully 
redress any abuses in the allocation of transmission services before 
considering structural unbundling. Similarly, TVA notes that the 
Commission already has the option to impose a structural remedy on a 
case-by-case basis.\102\
---------------------------------------------------------------------------

    \102\ Some commenters argue that adoption of the ``open 
dispatch'' proposals raised by commenters such as Chandley-Hogan and 
PJM would constitute a departure from functional unbundling. We 
discuss the ``open dispatch'' and similar proposals in section V.C 
below.
---------------------------------------------------------------------------

Commission Determination
    122. The Commission will, as proposed in the NOPR, continue to 
require functional--rather than corporate or structural--unbundling. As 
explained in the NOPR, for public utilities that keep transmission and 
generation assets in the same corporate entity, the Commission has 
strict Standards of Conduct that require the separation of the 
utilities' transmission system operations and wholesale marketing 
functions.\103\ These rules require that employees engaged in 
transmission functions operate separately from employees of energy 
affiliates and marketing affiliates. A number of information sharing 
restrictions also apply, which prohibit transmission providers from 
allowing employees of their energy and marketing affiliates to obtain 
access to transmission or customer information, except via OASIS.
---------------------------------------------------------------------------

    \103\ The rules were first established in Order No. 889. See 
Order No. 889 at 31,595. The Standards of Conduct rules were later 
replaced by a broader set of rules adopted in Order No. 2004, which 
were subsequently vacated in part by the United States Court of 
Appeals pending remand proceedings before the Commission. See 
Standards of Conduct for Transmission Providers, Order No. 2004, 68 
FR 69134 (Dec. 11, 2003), FERC Stats. & Regs. ] 31,155 (2003), order 
on reh'g, Order No. 2004-A, 69 FR 23562 (Apr. 29, 2004), FERC Stats. 
& Regs. ] 31,161 (2004), order on reh'g, Order No. 2004-B, 69 FR 
48371 (Aug. 10, 2004), FERC Stats. & Regs. ] 31,166 (2004), order on 
reh'g, Order No. 2004-C, 70 FR 284 (Jan. 4, 2005), FERC Stats. & 
Regs. ] 31,172 (2005), order on reh'g, Order No. 2004-D, 110 FERC ] 
61,320 (2005), vacated, National Fuel, 468 F.3d 831. The Commission 
has issued an interim rule promulgating temporary regulations 
consistent with the Court's decision and initiated a further 
rulemaking to propose permanent regulations. See Standards of 
Conduct for Transmission Providers, Order No. 690, 72 FR 2427 (Jan. 
19, 2007), FERC Stats. & Regs. ] 31,327 (2007); Standards of Conduct 
for Transmission Providers, Notice of Proposed Rulemaking, 72 FR 
3958 (Jan. 29, 2007), FERC Stats. & Regs. ] 32,611 (2007) (Standards 
of Conduct NOPR).
---------------------------------------------------------------------------

    123. The Commission aggressively enforces the Standards of Conduct 
and, as referenced by APPA, cooperates with State regulators to ensure 
that the functional unbundling regime is sufficient to prevent undue 
discrimination. The Commission's Office of Enforcement is well-suited 
to investigate potential violations of the Standards of Conduct and to 
propose remedies, including structural remedies if necessary, to ensure 
that the separation of functions and information restrictions are fully 
implemented. We believe that the increased clarity and transparency 
adopted in other parts of this Final Rule, when coupled with the 
Standards of Conduct rules and our rigorous enforcement program, will 
ensure that the functional unbundling requirement will serve its 
original purpose.

C. Applicability of the Final Rule

1. Non-ISO/RTO Public Utility Transmission Providers
    124. In the NOPR, the Commission proposed to apply the Final Rule 
to all public utility transmission providers, including those that are 
approved ISOs and RTOs. With respect to non-ISO/RTO transmission 
providers, the Commission proposed to require all such transmission 
providers to submit FPA section 206 compliance filings, within 60 days 
after the publication of the Final Rule in the Federal Register, that 
contain the non-rate terms and conditions set forth in the Final Rule. 
The Commission also acknowledged that certain non-rate terms and 
conditions, such as Attachment C (relating to the transmission 
provider's ATC calculation methodology) and Attachment K (relating to 
the transmission provider's transmission planning process), may require 
more than 60 days to prepare and sought comment on an appropriate time 
period in which to require the submission of these attachments.
    125. Following their FPA section 206 compliance filings, the 
Commission proposed that transmission providers could submit filings 
under FPA section 205 proposing rates for the services provided for in 
the tariff, as well as non-rate terms and conditions that differ from 
those set forth in the Final Rule if those provisions are ``consistent 
with or superior to'' the pro forma OATT.
Comments
    126. Several commenters ask the Commission to clarify and/or revise 
the proposal for dealing with previously-approved provisions that 
depart from the existing (Order No. 888) pro forma OATT. APPA contends 
that after this multi-phase rulemaking (NOI/NOPR/Final Rule) to revise 
the OATT, the Commission should hold those public utility transmission 
providers that propose non-rate terms and conditions differing from the 
new pro forma OATT to a high standard of proof under the ``consistent 
with or superior to'' standard. According to APPA, any non-rate term 
and condition that differs from the revised pro forma OATT should be 
``additive'' in nature (for example, a new service offering, such as 
network contract demand service) or should propose substantive 
improvements in transmission service to customers. APPA argues that a 
public utility transmission provider should not be able to make an FPA 
section 206 compliance filing to implement the pro forma OATT and then 
``water down'' its new OATT through an FPA section 205 filing that 
degrades its transmission service offerings or diminishes the quality 
of that service.
    127. In its reply comments, APPA recommends that the Commission 
require non-ISO/RTO transmission providers to file the new pro forma 
OATT set out in the Final Rule and add in redline--either in that 
filing, or a companion one--all previously approved transmission 
provider-specific

[[Page 12286]]

provisions. APPA states that transmission providers should then explain 
whether they propose to include these provisions in their revised 
OATTs, why they propose to retain or delete these provisions, and 
whether they believe these provisions are ``affected by the revisions 
adopted in the Final Rule.''
    128. In contrast, Duke and EEI ask the Commission to clarify that 
transmission providers with previously-approved departures from the 
OATT that are not related to the reforms adopted in this Final Rule 
will not be required to rejustify these provisions in their FPA section 
206 compliance filings. They also ask that transmission providers not 
be required first to adopt all of the provisions of the revised pro 
forma OATT and then make an FPA section 205 filing to refile a 
departure previously approved by the Commission. They recommend that 
existing, approved departures from the pro forma OATT that are not 
affected in a substantive way by the changes to the pro forma OATT 
should be included in the initial FPA section 206 filing.\104\ On 
reply, Indianapolis Power agrees with Duke and EEI and urges the 
Commission to consider the unwieldy and cost prohibitive nature of a 
process that would require transmission providers to demonstrate that 
previously-accepted elements of their OATTs are acceptable.
---------------------------------------------------------------------------

    \104\ Duke and EEI propose that a utility would redline its 
compliance filing OATT against the revised pro forma OATT so that 
the Commission can readily identify the ``already-approved'' 
differences.
---------------------------------------------------------------------------

    129. Duke and EEI, in their reply comments, argue that APPA's 
approach would be inefficient and would cause a substantial disruption 
to transmission service because both transmission providers and 
transmission customers would be required to abandon tariff provisions 
that the Commission has previously found to be consistent with or 
superior to the pro forma OATT and that are regularly being used. For 
example, Duke notes, Duke Carolina has an Attachment K that covers the 
Independent Entity that will oversee the provision of transmission 
service by Duke. Duke asserts that a literal interpretation of the NOPR 
proposal would mean that it would have to delete this attachment and 
replace its entire OATT with the revised pro forma OATT and then refile 
its entire Independent Entity proposal with its FPA section 205 filing. 
Similarly, Entergy states that it currently has a pro forma Generator 
Imbalance Agreement in place that was agreed to by the IPPs on its 
system and accepted by the Commission. Entergy urges the Commission to 
permit transmission providers to propose their own imbalance pricing 
methodology as long as the proposed generator imbalance charges are 
consistent with or superior to the generator imbalance provisions 
ultimately adopted in the OATT.
    130. On reply, NRECA opposes EEI's compliance proposal. NRECA 
states that the Commission should retain the two-phased compliance 
procedure proposed in the NOPR because it strikes a fair balance by 
providing transmission providers the opportunity to suggest changes to 
their pro forma OATTs under FPA section 205, while allowing 
transmission customers and others the opportunity to argue that the 
deviations from the new pro forma OATT are neither consistent with nor 
superior to the pro forma OATT.
    131. NRECA acknowledges that there will be a burden on the 
transmission provider to prepare a compliance filing; however, it urges 
the Commission to retain its proposal and require transmission 
providers to identify those terms and conditions that differ from the 
pro forma OATT. NRECA agrees that, if a term or condition unrelated to 
any modification of the pro forma OATT in the instant rulemaking has 
already been found to be consistent with or superior to the existing 
Order No. 888 pro forma OATT, it likely continues to be consistent with 
or superior to the revised pro forma OATT term or condition. NRECA 
argues, however, that a public utility transmission provider should 
still be required in a compliance filing to identify these deviations 
from the revised pro forma OATT and, ultimately, to justify them in the 
event that they are fairly contested. Otherwise, NRECA contends, the 
Commission and industry lose the consistency and related advantages the 
pro forma OATT seeks to provide.
    132. Several commenters addressed the deadlines proposed in the 
NOPR. APPA suggests that the Commission set a 60 or 90-day deadline for 
those provisions the transmission provider can complete itself and a 
120 or 180-day deadline for those provisions and attachments that will 
require the transmission provider to incorporate regional practices and 
protocols, such as Attachments C and K. Tacoma proposes 180 days for 
transmission providers to submit Attachments C and K. PGP recommends 
that transmission providers be given one year to file Attachment K.
    133. EEI and National Grid urge the Commission to align the 
compliance filing deadlines for ISOs and RTOs and their transmission-
owning members in order to eliminate any potential confusion and to 
enhance coordination within the ISOs and RTOs. To the extent that 
public utility transmission owners whose transmission facilities are 
under the control of RTOs and ISOs have filing rights under the RTO or 
ISO tariffs, EEI asks that such public utility transmission owners be 
required to submit any necessary tariff filings within 90 days after 
the effective date of the Final Rule, rather than the currently-
proposed 60 days. National Grid suggests that the Commission establish 
a single deadline for ISOs/RTOs and their transmission-owning members, 
set at six months from the date of publication of the Final Rule.
    134. TDU Systems recommend that the Commission adopt a staggered 
filing approach for the compliance filings (i.e., have transmission 
providers come in at different times based on criteria chosen by the 
Commission, such as alphabetically or by size). TDU Systems argue that 
this would ensure that transmission customers are not forced to review 
all of their transmission providers' filings at the same time.

Commission Determination

    135. The Commission adopts the two-tiered implementation process 
proposed in the NOPR, with certain clarifications and modifications, as 
discussed below. As the Commission proposed in the NOPR, all 
transmission providers that have not been approved as ISOs or RTOs, and 
whose transmission facilities are not under the control of an ISO or 
RTO, are required to submit FPA section 206 compliance filings that 
contain the revised non-rate terms and conditions set forth in the 
Final Rule, within 60 days after the publication of the Final Rule in 
the Federal Register.\105\ However, this filing only need to contain 
the revised provisions adopted in the Final Rule, rather than the 
transmission provider's entire pro forma OATT.\106\ After the 
submission of their

[[Page 12287]]

FPA section 206 compliance filings, these transmission providers may 
submit FPA section 205 filings proposing rates for the services 
provided for in the tariff, as well as non-rate terms and conditions 
that differ from those set forth in the Final Rule if those provisions 
are ``consistent with or superior to'' the pro forma OATT.
---------------------------------------------------------------------------

    \105\ The Commission clarifies that existing waivers of the 
obligation to file an OATT or otherwise offer open access 
transmission service in accordance with Order No. 888 shall remain 
in place. The reforms to the pro forma OATT adopted in this Final 
Rule therefore do not apply to transmission providers with such 
waivers, although we expect those transmission providers to 
participate in the regional planning processes in place in their 
regions, as discussed in more detail in section V.B. Whether an 
existing waiver of OATT requirements should be revoked will be 
considered on a case-by-case basis in light of the circumstances 
surrounding the particular transmission provider.
    \106\ As explained below, the Commission is not requiring 
transmission providers to submit in their compliance filing tariff 
sheets associated with provisions of the pro forma OATT that have 
not been modified in this proceeding. To the extent, however, a 
transmission provider desires to refile its entire OATT in order to 
simplify pagination or other tariff designation issues associated 
with implementing the modifications required under the Final Rule, 
it may do so. We note that such a filing is a compliance filing and, 
therefore, the only deviations in this filing should be the revised 
provisions in this Final Rule. If a transmission provider wishes to 
propose different terms and conditions, it must make a separate FPA 
section 205 filing.
---------------------------------------------------------------------------

    136. The Commission recognizes that, since the issuance of Order 
No. 888, some non-ISO/RTO transmission providers have received approval 
from the Commission to adopt variations from the non-rate terms and 
conditions of the pro forma OATT that are consistent with or superior 
to the Order No. 888 pro forma OATT. Under the compliance procedure 
adopted above, those variations that are not affected in a substantive 
manner by the reforms to the pro forma OATT adopted in this Final Rule 
may remain in place. We disagree with the implementation procedures 
proposed by APPA, which would require non-ISO/RTO transmission 
providers with provisions in their OATTs that depart from the pro forma 
OATT, but which are not substantively affected by the reforms in this 
NOPR, to make a filing that explains whether and why they would retain 
or delete these provisions. We see no need to require non-ISO/RTO 
transmission providers to ``rejustify'' such provisions if they are not 
substantively affected by the reforms in this Final Rule, given that 
the Commission has already found these provisions to be consistent with 
or superior to terms and conditions set forth in the pro forma OATT 
that remain unchanged, and the Commission has not otherwise found these 
provisions to be unjust and unreasonable.
    137. In other circumstances, however, non-ISO/RTO transmission 
providers may have provisions in their existing OATTs that the 
Commission deemed to be consistent with or superior to terms and 
conditions of the Order No. 888 pro forma OATT that are being modified 
by the Final Rule. Such transmission providers must demonstrate that 
these previously-approved variations continue to be consistent with or 
superior to the pro forma OATT as modified by the Final Rule. We 
continue to believe that use of the ``consistent with or superior to'' 
standard is appropriate when reviewing variations from the pro forma 
OATT and reject APPA's proposal to adopt a higher burden of proof.
    138. The two-tiered compliance process adopted above will allow 
transmission providers with previously-approved variations an 
opportunity to show that their existing deviations continue to be 
consistent with or superior to the pro forma OATT as modified in the 
Final Rule. However, the Commission recognizes that it may cause 
disruption for some transmission providers that wish to continue to 
rely on previously-approved variations during the compliance process. 
The Commission therefore offers an optional implementation process for 
non-ISO/RTO transmission providers seeking approval of previously-
approved variations.
    139. Transmission providers that have not been approved as ISOs or 
RTOs and whose transmission facilities are not under the control of an 
ISO or RTO may submit an FPA section 205 filing, within 30 days after 
the publication of the Final Rule in the Federal Register, seeking a 
determination that a previously-approved variation from the Order No. 
888 pro forma OATT that has been substantively affected by the reforms 
adopted in this Final Rule continues to be consistent with or superior 
to the revised pro forma OATT adopted here.\107\ Each applicant should 
request that the proposed tariff provisions be made effective as of the 
date of the transmission provider's section 206 compliance filing, to 
be submitted within 60 days after the publication of the Final Rule in 
the Federal Register (as provided above). As a condition of that 
request, however, the transmission provider should state that the 
Commission has 90 days following the date of submission of the filing 
to act under section 205. In other words, the Commission is offering 
this optional implementation process to applicants that allow the 
Commission 90 days to act on the filing. This procedure will streamline 
the compliance process by allowing existing variations from terms and 
conditions of the pro forma OATT that have been modified by the Final 
Rule to remain in effect until further Commission action, while also 
providing the Commission with adequate time to act on the filings. The 
subsequent section 206 compliance filing would then contain tariff 
sheets necessary to implement the remaining modifications required 
under the Final Rule, i.e., modifications related to tariff provisions 
that did not implicate previously-approved variations.
---------------------------------------------------------------------------

    \107\ Transmission providers must provide citations to the 
Commission orders where the variation was accepted by the Commission 
as consistent with or superior to the pro forma OATT.
---------------------------------------------------------------------------

    140. As the Commission acknowledged in the NOPR, certain non-rate 
terms and conditions, such as Attachment C (relating to the 
transmission provider's ATC calculation methodology) and Attachment K 
(relating to the transmission provider's transmission planning process) 
may require more than 60 days to prepare. Accordingly, we will require 
non-ISO/RTO transmission providers to file their Attachment C within 
180 days after the publication of the Final Rule in the Federal 
Register and their -Attachment K (or the transmission providers' 
equivalent thereof) within 210 days after the publication of the Final 
Rule in the Federal Register. A summary of the more significant filing 
requirements established in this Final Rule is provided in Appendix 
A.\108\
---------------------------------------------------------------------------

    \108\ For further information related to the Final Rule, such as 
electronic versions of the pro forma OATT showing tariff changes 
adopted in the Final Rule in redline/strikeout format, and further 
information regarding docketing of compliance filings and specific 
filing instructions, please visit our Web site at the following 
location http://www.ferc.gov/industries/electric/indus-act/oatt-reform.asp
.

---------------------------------------------------------------------------

    141. Other reforms adopted in the Final Rule will involve 
coordination with the North American Energy Standards Board (NAESB) to 
establish OASIS functionality or uniform business practices. The 
Commission requests that NAESB file a status report within 90 days of 
publication of the Final Rule in the Federal Register that contains a 
work plan for development of such OASIS functionality and business 
practices. This work plan should indicate, for each reform, what 
actions are necessary and an estimate of the timeframe for completing 
those actions. Pending resolution of these issues with NAESB, the 
Commission requires that each transmission provider develop its own 
OASIS functionality or business practice necessary to implement each 
such reform within 90 days of publication of the Final Rule in the 
Federal Register, unless a different compliance requirement is 
otherwise specified in this Final Rule. Upon review of this work plan, 
the Commission will issue an order establishing further compliance 
deadlines as necessary.
    142. We are not persuaded to adopt a staggered compliance filing 
approach in this proceeding as TDU Systems suggest. However, we will 
align the compliance filing deadlines for ISOs and RTOs and their 
transmission-

[[Page 12288]]

owning members in order to eliminate any potential confusion and to 
enhance coordination within the ISOs and RTOs. Thus, we will require 
public utility transmission owners whose transmission facilities are 
under the control of RTOs and ISOs to make any necessary tariff filings 
required to comply with the Final Rule within 210 days after the 
publication of the Final Rule in the Federal Register.
2. ISO and RTO Public Utility Transmission Providers and Transmission 
Owner Members of ISOs and RTOs
    143. With respect to an ISO or RTO public utility transmission 
provider, the Commission recognized in the NOPR that such an entity may 
already have tariff terms and conditions that are superior to the pro 
forma OATT. The Commission also noted that the purpose of this 
rulemaking is not to redesign approved, fully-functioning RTO or ISO 
markets. Thus, the Commission proposed to require ISO and RTO 
transmission providers to submit FPA section 206 compliance filings, 
within 90 days after the publication of the Final Rule in the Federal 
Register, that contain the non-rate terms and conditions set forth in 
the Final Rule or that demonstrate that their existing tariff 
provisions are consistent with or superior to the revised provisions to 
the pro forma OATT. The Commission also proposed to allow ISO and RTO 
transmission providers, after making their FPA section 206 compliance 
filings, to submit filings under FPA section 205 proposing rates for 
the services provided for in their tariffs, as well as non-rate terms 
and conditions that differ from their existing tariffs and those set 
forth in the Final Rule if those provisions are consistent with or 
superior to the pro forma OATT. The Commission did not address the 
specific obligations of transmission owning members of ISOs and RTOs.
Comments
    144. Several commenters support applying the revised pro forma OATT 
to ISOs and RTOs and requiring ISOs and RTOs to justify any variations 
therefrom. MidAmerican argues that universal application of the revised 
pro forma OATT is important because not every ISO or RTO transmission 
provider has existing tariff terms and conditions that are consistent 
with or superior to the OATT. Old Dominion also supports the 
Commission's compliance proposals for ISOs and RTOs. NRECA similarly 
states that RTOs, ISOs and ITCs should not be automatically exempt from 
any aspect of the rules governing open access transmission service, 
including the planning requirements. APPA asserts that in their 
filings, RTOs should be required to show how their transmission service 
packages, including features such as long term transmission rights, 
ancillary services, and treatment of losses, are consistent with or 
superior to the newly revised pro forma OATT. Moreover, APPA argues, 
the Commission should not allow RTOs to use their avowed independence 
as a justification for transmission services that in fact do not meet 
the consistent with or superior to standard.\109\
---------------------------------------------------------------------------

    \109\ See also CMUA Reply.
---------------------------------------------------------------------------

    145. On the other hand, numerous commenters argue that the proposed 
compliance process is burdensome and could require ISOs and RTOs to 
have to relitigate already-approved OATT provisions. The ISOs and RTOs 
generally argue that, given the nature of the services they offer, many 
of the proposed revisions do not apply to their OATTs. Many commenters 
urge the Commission to adopt a more limited compliance filing process. 
Some commenters, for example, argue that the Commission should only 
require ISOs and RTOs to submit compliance filings that are limited to 
the specific pro forma tariff revisions set forth in the Final Rule. 
Duke argues that ISOs and RTOs should only be required to make a single 
filing that revises their OATTs in a manner that takes into account the 
nature of the OATT service provided by that ISO or RTO and whether a 
reform adopted in the Final Rule is relevant to the ISO's or RTO's 
OATT. EEI urges the Commission to require ISOs and RTOs to adopt only 
those OATT reforms that are necessary to improve the quality of 
transmission service that is provided by an ISO or RTO. EEI adds that 
those who protest an ISO's or RTO's assertion that an existing 
provision is consistent with or superior to the revised pro forma OATT 
should have the burden to demonstrate otherwise. The ISOs and RTOs 
similarly argue that, absent a specific demonstration that an ISO's or 
RTO's OATT provisions are unjust and unreasonable, the compliance 
filing requirements should not apply to ISOs and RTOs.
    146. EEI urges the Commission to clarify that the 90-day filing 
should include the following materials: Revisions of tariff provisions 
that conform to the revisions in the pro forma OATT that are 
appropriate, given the ISO or RTO's market structure; statements 
supporting the provisions of the tariff that the ISO or RTO believes 
are consistent with or superior to the revised pro forma OATT; and 
justifications that support excluding revisions of the provisions that 
the ISO or RTO believes are not consistent with or superior to the 
revised pro forma OATT. EEI also interprets the NOPR proposal to mean 
that an ISO or RTO immediately may make a separate filing proposing 
further modifications, including revisions to the newly-effective 
provisions of the pro forma OATT, that are consistent with or superior 
to the just-filed modifications.
    147. SPP urges the Commission to affirm that ISOs and RTOs will not 
be required to rejustify their previously-approved non-pro forma tariff 
provisions, but rather only the new or revised tariff provisions 
expressly prescribed in the Final Rule. In its reply comments, SPP 
notes that the terms and conditions of its OATT are interrelated and 
work together to achieve a system of administration that fosters open 
and transparent transmission service and function as an integrated 
whole. Therefore, SPP asserts, the modification of one provision of its 
OATT will impact several other provisions and the process of 
rejustifying one aspect of the tariff likewise will implicate other 
terms and conditions.
    148. Indianapolis Power argues that tariff changes resulting from 
this rulemaking should be included only with the support of the ISO and 
RTO members who bear the costs and are in the best position to judge 
the benefits.
    149. On reply, ISO/RTO Council generally argues that there is no 
factual or legal support for the ISO/RTO compliance procedures 
advocated by commenters such as APPA. ISO/RTO Council states that the 
OATTs of ISOs and RTOs were developed through extensive stakeholder 
procedures and subject to the Commission's filing, notice, comment, and 
approval processes under FPA section 205. ISO/RTO Council asserts that 
to adopt the post-hoc, open-ended review advocated by these parties 
would give disgruntled participants a ``second bite'' at legally 
effective OATT terms and would undermine the very stakeholder and 
regulatory processes by which ISOs and RTOs were established. MISO in 
particular argues that APPA's proposal ignores that ISO and RTO tariffs 
have already been determined to be just and reasonable and consistent 
with or superior to the Order No. 888 pro forma OATT, is profoundly 
inconsistent with the Commission's policy of encouraging RTOs as an 
option to ensure non-discriminatory open access transmission service, 
and is impracticable unless the intent is to grind RTO markets to a 
halt. MISO states that each RTO tariff has

[[Page 12289]]

dozens, or perhaps hundreds, of Commission-approved deviations and, in 
its view, reopening these issues would not be in the public interest 
and would consume enormous resources of both the RTOs and the 
Commission.
    150. Southern, in its reply comments, argues that ISOs and RTOs are 
essentially requesting to be exempted from the requirements of this 
proceeding. Southern states that all transmission service revisions/
reforms adopted in this proceeding should apply uniformly to all 
transmission providers, including ISOs and RTOs. Southern contends that 
ISOs and RTOs are increasingly subject to complaints alleging 
discriminatory treatment and asserts that the highly partisan attacks 
made by several RTOs against vertically-integrated utilities further 
calls into question whether ISOs and RTOs are not susceptible to taking 
discriminatory actions. In addition, Southern argues, such exemptions 
would likely result in seams issues.
    151. Some commenters state that the Commission should identify the 
specific reforms it will apply to RTOs and ISOs and provide more 
general guidance as to how it intends to apply the consistent with or 
superior to standard to ISO/RTO tariff provisions. National Grid 
asserts that the Commission properly identified these provisions in the 
NOPR when the Commission concluded that there may be elements of the 
proposed reforms that are superior to what currently exist in some RTOs 
or ISOs, e.g., transparency, data exchange, or planning. MISO/PJM 
States identify six areas as potentially applicable to RTOs: Hourly 
firm transmission service; obligation to expand capacity; joint 
ownership; reservation priority; ancillary services; and pro forma OATT 
definitions. MISO/PJM States also identify eleven areas as not 
applicable to RTOs: Undue discrimination generally; transmission 
pricing; remedies, penalties and enforcement; changes in receipt and 
delivery points (redirects); rollover rights; rules, standards and 
practices governing the provision of transmission service; joint 
transmission planning; tariff compliance review; hoarding of 
transmission capacity; curtailments; and ancillary services. APPA, in 
its reply comments, opposes granting a blanket exemption for ISOs and 
RTOs from any portion of the compliance filing requirement.
    152. CAISO urges the Commission to clarify how it should provide 
for changes in the Final Rule to transmission services that it does not 
provide or which are clearly incompatible with the transmission service 
model it employs. In their reply comments, CMUA and APPA oppose this 
request for clarification. CMUA argues that CAISO's failure to provide 
any long-term transmission service renders its transmission service 
markedly inferior to the firm transmission service under the pro forma 
OATT. CMUA maintains that, instead of affirmatively embracing its 
obligation to show that its transmission service offering, once 
supplemented with long-term transmission rights that fully comply with 
all seven guidelines set out in Order No. 681, will meet the 
``consistent with or superior to'' standard of Order No. 888, CAISO 
instead asks to be exempted from any such requirement.
    153. Xcel and Indicated New York Transmission Owners assert that 
the Commission should allow regional variations to the extent that 
ISOs/RTOs can demonstrate that their OATT provisions meet the 
objectives of the Final Rule. Xcel argues that the consistent with or 
superior to standard may be too narrow because some changes to the OATT 
made by ISOs/RTOs are not as much ``superior'' or ``consistent with,'' 
as they are simply necessary because the tariff is regional. Indicated 
New York Transmission Owners argue that the Commission should not 
impose a consistent with or superior to standard generally reserved for 
transmission providers that are not members of an ISO/RTO. Indicated 
New York Transmission Owners assert that, to the extent that certain 
improvements could or should be made to the ISO/RTO OATTs, the Final 
Rule should permit the necessary flexibility for each ISO/RTO to 
propose and adopt such changes through their stakeholder governance 
processes, in order to address the unique market features and 
circumstances of each region.
    154. PJM urges the Commission to include an ``independent entity 
variation'' standard similar to that used in Order No. 2003, which 
permitted an RTO to adopt interconnection procedures that are 
responsive to specific regional needs. NRECA responds that the 
Commission should not entertain PJM's request. While PJM's requested 
standard may have made sense in the context of generator 
interconnections, NRECA contends that it is inapposite to reform of the 
OATT. NRECA states that ISOs and RTOs should not be allowed to keep on 
file tariff provisions that possess the potential to allow for undue 
discrimination, even if the entity publishing the tariff is ostensibly 
independent of market participants and even if the proposed reforms do 
not directly improve the ``quality of'' transmission service, since the 
purpose of this rulemaking is to prevent undue discrimination in the 
provision of transmission service.
    155. To whatever extent the Commission elects to exempt RTOs and 
ISOs from certain aspects of the pro forma OATT, E.ON asserts that the 
same consideration should be given to utilities that have entered into 
arrangements with alternative, Commission-approved, independent 
transmission organizations. In their reply comments, TDU Systems oppose 
this proposal arguing that these alternative constructs may not meet 
the independence criteria of Order Nos. 888 and 2000.
    156. Several commenters urge the Commission to extend the proposed 
90-day deadline for ISOs and RTOs to submit their compliance filings. 
EEI recommends that the Commission clarify that it will grant an 
extension of time if the stakeholder process prevents an ISO or RTO 
from obtaining stakeholder approval of tariff changes within the 90-day 
deadline. SPP requests a minimum of 120 days for compliance. National 
Grid and MISO (in its reply comments) propose that the Commission 
establish a single deadline for ISOs/RTOs and their transmission-owning 
members set at six months from the date of publication of the Final 
Rule.
Commission Determination
    157. The Commission adopts the compliance procedures proposed in 
the NOPR, with certain revisions and clarifications. We will require 
ISO and RTO transmission providers to submit FPA section 206 compliance 
filings, within 210 days after the publication of the Final Rule in the 
Federal Register, that contain the non-rate terms and conditions set 
forth in the Final Rule or that demonstrate that their existing tariff 
provisions are consistent with or superior to the revised provisions of 
the pro forma OATT. As with non-ISO/RTO transmission providers, 
however, we will not require ISO and RTO transmission providers to 
``rejustify'' existing provisions in their OATTs that are not affected 
in a substantive manner by the revisions to the pro forma OATT in the 
Final Rule. As we explained above, we find that such a process is 
unnecessary, given that we have already found these provisions to be 
consistent with or superior to the Order No. 888 pro forma OATT and 
these provisions are not substantively affected by the reforms we adopt 
today.
    158. We also recognize, as we did in the NOPR, that some of the 
changes adopted in the Final Rule may not be as relevant to ISO/RTO 
transmission

[[Page 12290]]

providers as they are to non-independent transmission providers. For 
example, many ISOs and RTOs use bid-based locational markets and 
financial rights to address transmission congestion, rather than the 
first-come, first-served physical rights model set forth in the pro 
forma OATT. As we indicated in the NOPR, nothing in this rulemaking is 
intended to upset the market designs used by existing ISOs and RTOs. We 
also recognize that ISOs and RTOs may well have adopted practices that 
are already consistent with or superior to the reforms adopted here. 
For example, ISOs and RTOs tend to have transmission planning processes 
that are significantly more open and transparent than the processes 
used by non-independent transmission providers. We encourage ISOs and 
RTOs to meet with their stakeholders to discuss whether any 
improvements are necessary to comply with the Final Rule.
    159. We reject Indianapolis Power's proposal to require tariff 
changes resulting from this rulemaking only with the support of the ISO 
and RTO members who may bear the costs associated with the revision. 
Indianapolis Power effectively asks that we allow ISO and RTO members 
to veto our decisions here, which is contrary to our duty to prevent 
undue discrimination in the provision of transmission service.
    160. Regarding CAISO's request for clarification of how it should 
address changes in the Final Rule to transmission services that it does 
not provide or which are incompatible with its service model, we 
reiterate that CAISO--like any other ISO or RTO--has the opportunity to 
demonstrate that a variation from the tariff revisions adopted in the 
Final Rule satisfies the consistent with or superior to standard. We do 
not believe that the adoption of an ``independent entity variation,'' 
proposed by PJM, or a regional variation standard, proposed by Xcel and 
Indicated New York Transmission Owners, would be appropriate. Again, 
the Commission finds that the reforms adopted in this Final Rule are 
necessary to prevent undue discrimination in the provision of 
transmission service and any transmission provider, including an ISO or 
RTO, must demonstrate that variations from the tariff modifications 
required here satisfy the consistent with or superior to standard.
    161. As discussed above, however, we will align the compliance 
filing deadlines for ISOs and RTOs and their transmission-owning 
members and require public utility transmission owners whose 
transmission facilities are under the control of RTOs or ISOs to make 
any necessary tariff filings required to comply with the Final Rule 
within 210 days after the publication of the Final Rule in the Federal 
Register. A summary of the more significant filing requirements 
established in this Final Rule is provided in Appendix A.\110\
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    \110\ For further information related to the Final Rule, such as 
electronic versions of the pro forma OATT showing tariff changes 
adopted in the Final Rule in redline/strikeout format, and further 
information regarding docketing of compliance filings and specific 
filing instructions, please visit our Web site at the following 
location http://www.ferc.gov/industries/electric/indus-act/oatt-reform.asp
.

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3. Non-Public Utility Transmission Providers/Reciprocity
    162. In Order No. 888, the Commission conditioned non-public 
utilities' use of public utility open access services on an agreement 
to offer comparable transmission services in return.\111\ The 
Commission found that, while it did not have the authority to require 
non-public utilities to make their systems generally available, it did 
have the ability and the obligation to ensure that open access 
transmission is as widely available as possible and that Order No. 888 
did not result in a competitive disadvantage to public utilities.
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    \111\ These entities are not FPA public utilities and therefore 
are not subject to the Commission's jurisdiction under sections 205 
and 206 of the FPA.
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    163. Under the reciprocity provision in section 6 of the pro forma 
OATT, if a public utility seeks transmission service from a non-public 
utility to which it provides open access transmission service, the non-
public utility that owns, controls, or operates transmission facilities 
must provide comparable transmission service that it is capable of 
providing on its own system. Under the pro forma OATT, a public utility 
may refuse to provide open access transmission service to a non-public 
utility if the non-public utility refuses to reciprocate. A non-public 
utility may satisfy the reciprocity condition in one of three ways. 
First, it may provide service under a tariff that has been approved by 
the Commission under the voluntary ``safe harbor'' provision. A non-
public utility using this alternative submits a reciprocity tariff to 
the Commission seeking a declaratory order that the proposed 
reciprocity tariff substantially conforms to, or is superior to, the 
pro forma OATT. The non-public utility then must offer service under 
its reciprocity tariff to any public utility whose transmission service 
the non-public utility seeks to use. Second, the non-public utility may 
provide service to a public utility under a bilateral agreement that 
satisfies its reciprocity obligation. Finally, the non-public utility 
may seek a waiver of the reciprocity condition from the public 
utility.\112\
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    \112\ See Order No. 888-A at 30,285-86.
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    164. In EPAct 2005, Congress authorized, but did not require, the 
Commission to order non-public utilities (or ``unregulated transmitting 
utilities'') to provide transmission services under a new section 211A 
in Part II of the FPA. This section states in part that the Commission 
``may, by rule or order, require an unregulated transmitting utility to 
provide transmission services'' at rates that are comparable to those 
it charges itself and under terms and conditions (unrelated to rates) 
that are comparable to those it applies to itself, and that are not 
unduly discriminatory or preferential. The language does not limit the 
Commission to ordering transmission services only to the public utility 
from whom the non-public utility takes transmission services, but 
rather permits the Commission to order the non-public utility to 
provide ``open access'' transmission service, i.e., service to all 
eligible customers.
    165. In the NOPR, the Commission proposed to retain the current 
reciprocity language in the pro forma OATT, as well as Order No. 888's 
three alternative provisions for satisfying the reciprocity condition, 
i.e.: A non-public utility that owns, controls, or operates 
transmission and seeks transmission service from a public utility must 
either satisfy its reciprocity obligation under a bilateral agreement, 
seek a waiver of the OATT reciprocity condition from the public 
utility, or file a safe harbor tariff with the Commission.\113\
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    \113\ For non-public utilities that choose to use the safe 
harbor tariff, the Commission noted in the NOPR that the existing 
safe harbor provisions would need to be substantially conforming or 
superior to the new pro forma OATT. A non-public utility that 
already has a safe harbor tariff would therefore be required to 
amend its tariff so that its provisions substantially conform or are 
superior to the new pro forma OATT if it wishes to continue to 
qualify for safe harbor treatment. As the Commission stated in Order 
No. 888-A, a non-public utility may limit the use of its voluntarily 
offered safe harbor reciprocity tariff only to those transmission 
providers from whom the non-public utility obtains open access 
service, as long as the tariff otherwise substantially conforms to 
the pro forma OATT. See Order No. 888-A at 30,289.
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    166. The Commission did not propose a generic rule to implement the 
new FPA section 211A.\114\ Rather, the Commission proposed to apply its 
provisions on a case-by-case basis, such as when a public utility seeks 
service

[[Page 12291]]

from an unregulated transmitting utility that has not requested service 
under the public utility's OATT and the reciprocity obligation 
therefore does not apply. The Commission stated that such a customer 
may file an application with the Commission seeking an order compelling 
the unregulated transmitting utility to provide transmission service 
that meets the standards of FPA section 211A. The Commission further 
proposed to amend its regulations to make clear that an applicant in an 
FPA section 211A proceeding against a non-public utility that has 
submitted an acceptable safe harbor tariff has the burden of proof to 
show why service under the safe harbor tariff is not sufficient and why 
an FPA section 211A order should be granted. In addition, the 
Commission stated in the NOPR its expectation that unregulated 
transmission providers would participate in the proposed open and 
transparent regional planning processes and noted that, if there were 
complaints about such participation, they would also be addressed on a 
case-by-case basis.
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    \114\ The Commission noted in the NOPR that LPPC has committed 
to voluntary compliance with a set of guidelines for the provision 
of comparable service under FPA section 211A.
---------------------------------------------------------------------------

    167. The NOPR proposed to retain the existing reciprocity policy as 
applied to foreign utilities doing business in the United States, which 
we adopted pursuant to sections 205 and 206 of the FPA. By maintaining 
the same reciprocity requirement for these foreign utilities as for 
domestic, non-public utilities, the Commission stated that it would 
ensure that foreign entities will continue to be treated no less 
favorably than domestic, non-public utilities.
Comments
    168. The majority of the commenters support the Commission's 
decisions to retain the reciprocity provision and to adopt a case-by-
case approach to FPA section 211A.\115\ These commenters reason that 
there is no evidence of a general problem of non-public utilities 
failing to provide transmission service and that, for the most part, 
non-public utilities already provide transmission on an as-available 
basis under comparable terms, regardless of whether a tariff is on file 
with the Commission. In addition, Santa Clara and TANC state that the 
Commission's proposal apparently respects the nonjurisdictional status 
of public power.
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    \115\ E.g., APPA, Bonneville, LPPC, Newfoundland, NRECA, PGP, 
Sacramento, Salt River, Santa Clara, Santee Cooper, Seattle, TANC, 
TAPS, TVA, Tacoma, WAPA, CMUA Reply, East Texas Cooperatives Reply, 
Lassen Reply, and Public Power Council Reply.
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    169. LPPC reiterates its prior offer of voluntary compliance with a 
set of guidelines for the provision of comparable open access service, 
which it contends will provide a significant degree of standardization 
for such service. Thus, LPPC believes that generic action under section 
211A is not necessary. In addition, LPPC asserts that there is no 
evidence on record of undue discrimination by a nonjurisdictional 
entity that would justify the Commission reversing the NOPR decision to 
act on a case-by-case basis under FPA section 211A.\116\
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    \116\ See also Public Power Council Reply and Sacramento Reply.
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    170. On the other hand, several commenters urge the Commission to 
implement FPA section 211A on a generic basis.\117\ AWEA argues that 
reciprocity tariffs do not subject the nonpublic utilities to 
Commission enforcement as would an OATT established under FPA section 
211A. AWEA urges the Commission to proceed on a generic basis to ensure 
that nonjurisdictional utilities comply with the reformed OATT under 
exactly the same terms and conditions as jurisdictional utilities. On 
reply, however, APPA argues that the comparability standard does not 
mean that unregulated transmitting utilities must comply with the 
reformed OATT under exactly the same terms and conditions as 
jurisdictional entities.
---------------------------------------------------------------------------

    \117\ E.g., AWEA, California Commission, Calpine, EEI, 
MidAmerican, San Diego G&E, and Xcel.
---------------------------------------------------------------------------

    171. In its reply comments, EEI states that, while LPPC's voluntary 
proposal is a step in the right direction, LPPC's proposal does not go 
far enough to assure that reciprocal transmission service is provided 
in a non-discriminatory manner. EEI asserts that LPPC's proposal still 
gives the individual non-public utility transmission provider the 
discretion to decide what is or is not comparable and not unduly 
discriminatory. Moreover, EEI notes, LPPC does not represent the 
universe of non-public utility transmission providers, rather only 24 
of the largest governmentally-owned transmission providers.
    172. Some commenters argue that the case-by-case approach proposed 
in the NOPR does not satisfy the Commission's stated goal of remedying 
undue discrimination and its intent to provide transparent, consistent 
and clear rules for use of the nation's transmission grid.\118\ Calpine 
contends that the administrative burden of monitoring and administering 
customer complaints or processing applications that seek to compel 
unregulated transmitting utilities in different parts of the country to 
provide comparable service would create a ``patchwork of open and 
closed'' unregulated transmitting utilities, just like the patchwork of 
open and closed jurisdictional transmission systems the Commission 
sought to eliminate when it issued Order No. 888. Calpine also states 
that its comments on the NOI in this proceeding provide several 
examples of the kinds of problems it has experienced in seeking 
transmission service from unregulated transmitting utilities in a 
variety of regions and across multiple transmission systems.
---------------------------------------------------------------------------

    \118\ E.g., Calpine, MidAmerican, and Xcel.
---------------------------------------------------------------------------

    173. California Commission argues that FPA section 211A gives the 
Commission the authority to require previously nonjurisdictional 
entities to file tariffs with the Commission that would be subject to 
the due process and the ``just and reasonable'' requirements of the 
FPA. California Commission urges the Commission to actively explore a 
set of mandatory actions that the Commission may impose on 
nonjurisdictional entities and states that, if the Commission is 
reluctant to do so in this proceeding, it should initiate a new 
rulemaking to consider such rules. California Commission asserts that 
there are a number of sound policy reasons for taking generic action to 
address the mandate of FPA section 211A. First, it argues that 
Commission action would prevent the balkanization of the grid that can 
result if a nonjurisdictional transmission owner refuses to participate 
in an RTO or ISO whose service area surrounds, encompasses, or overlaps 
it. Second, California Commission argues that Congress has given the 
Commission explicit authority to require previously nonjurisdictional 
entities to provide transmission service on a non-preferential and non-
discriminatory basis. Finally, California Commission asserts, the 
Commission would be able to squarely address generic seams issues 
created by the existence of control areas operated by previously 
unregulated transmission owners and the ability of such entities to 
``free ride'' on the systems and open access requirements of the 
jurisdictional entities.
    174. In its reply comments, CMUA contests California Commission's 
assertion that those outside CAISO operations are ``free riders.'' CMUA 
notes that its members post their excess transmission capacity on 
wesTTrans (an OASIS site serving the Western Interconnection) thus 
making it available to third parties, and that its members outside the 
CAISO also pay a

[[Page 12292]]

host of CAISO fees.\119\ CMUA states that it does not contest that 
there are ``seams'' between organized markets and neighbors, but it 
asserts that this docket is not the place for this discussion and FPA 
section 211A is not the remedy. In its reply comments, APPA also urges 
the Commission to reject California Commission's proposal. APPA argues 
that section 211A was not intended, nor could the Commission use it, to 
require nonjurisdictional transmission providers to participate in an 
RTO and, therefore, California Commission's proposal exceeds the 
Commission's authority under section 211A.\120\
---------------------------------------------------------------------------

    \119\ See also APPA Reply.
    \120\ See also CMUA Reply and Santa Clara Reply.
---------------------------------------------------------------------------

    175. EPSA, in its reply comments, disagrees with commenters who 
appear to believe that nonjurisdictional transmitting utilities will 
not have to take any steps to comply with a final order in this 
rulemaking. EPSA states that its understanding is that the Commission's 
principle of reciprocity would apply to any changes in the pro forma 
OATT adopted in the Final Rule. Accordingly, both jurisdictional and 
nonjurisdictional transmitting utilities that adopted the Order No. 888 
pro forma OATT would have to make compliance filings. In addition, EPSA 
argues that nonjurisdictional transmitting utilities that previously 
received an Order No. 888 waiver or that wish to request such a waiver 
should have an affirmative duty to file a request for a waiver. In the 
event that a nonjurisdictional entity wishes to file a bilateral 
contract, EPSA contends that it should be required to file a 
``reciprocity'' contract pursuant to FPA section 205. If a 
nonjurisdictional transmitting utility does not adopt a revised pro 
forma OATT as a ``safe harbor,'' EPSA argues the Commission's standard 
of review should be whether the nonjurisdictional transmitting 
utility's alternative tariff is ``equal or superior to'' a revised pro 
forma OATT.
    176. EPSA, in its reply comments, supports implementing the rate 
provisions of FPA section 211A in a proceeding separate from this 
particular proceeding. EPSA states that such a proceeding could take a 
generic approach, in that nonjurisdictional transmitting utilities 
could be required to set transmission rates for third-party 
transmission services that are computed using rate determinants that 
are comparable to the determinants that the non-public utility uses to 
calculate transmission rates for its native load.
    177. With regard to specific reciprocity obligations, LPPC argues 
that the Commission should revise section 6 of the pro forma OATT to 
reflect the comparability standards now contained in FPA section 211A. 
LPPC states that, with the implementation of FPA section 211A, it is 
appropriate to revise the pro forma OATT language in order to reflect 
the unregulated utility's obligation ``to provide transmission service 
comparable to the service the customer provides itself'' as the ``quid 
pro quo'' for receiving reciprocal service. LPPC also argues that, with 
respect to the existing safe harbor option, the Commission should 
revise its test for evaluating a safe harbor OATT from one which asks 
whether the proposal is equivalent or superior to the pro forma OATT, 
to one which asks whether the service provided under the proposed OATT 
is comparable to the service that the unregulated utility provides 
itself.
    178. EPSA replies that LPPC's suggestion to revise the language of 
section 6 ironically would require nonjurisdictional transmitting 
utilities to offer third party customers transmission services that are 
comparable to network transmission service, which is a higher quality 
of transmission service than the revised OATT and which is unlikely to 
be supported by nonjurisdictional transmitting utilities. EPSA states 
that it believes that FPA section 211A requires a nonjurisdictional 
transmitting utility to provide transmission service (at its interfaces 
with jurisdictional public utilities and internal sources) that is 
comparable to the service it is taking at interfaces or internal 
sources. EPSA therefore argues that the appropriate standard for 
determining whether a nonjurisdictional transmitting utility's tariff 
is comparable is whether the nonjurisdictional utility's tariff is 
``equal or superior'' to the revised pro forma OATT.
    179. LPPC also argues that the two categorical exemptions from FPA 
section 211A articulated in FPA section 211A(c)(3) (based on size and 
the value of the unregulated system to the integrated grid) should not 
be exclusive. Rather, LPPC contends that the two exemptions should 
guide the Commission in considering similar requests for exemption. For 
example, LPPC argues that relatively small utilities, which 
nevertheless exceed an express threshold, should be permitted to 
demonstrate that their systems are simply too small, and that their 
facilities are not sufficiently strategic, to call for full inclusion 
in the FPA section 211A regime. Similarly, LPPC states that, in certain 
public systems, only some discrete portions of the system would fairly 
be considered part of the integrated system. In these cases as well, 
LPPC argues, it would make sense for the Commission to entertain 
requests for partial waiver.
    180. If the Commission does not reconsider its proposal not to act 
generically under FPA section 211A, EEI contends that there are other 
actions the Commission should take. In order to facilitate full 
compliance with the reciprocity obligation, EEI urges the Commission at 
least to clarify and strengthen the obligations of non-public utility 
transmission providers under the reciprocity provision,\121\ exercise 
oversight and monitor their compliance with the reciprocity obligation, 
and require them to provide greater transparency of the transmission 
services and the terms and conditions of service they offer so that 
those seeking transmission service under the reciprocity provision are 
able to determine whether they are complying with their reciprocity 
obligation.
---------------------------------------------------------------------------

    \121\ Xcel and MidAmerican support EEI's proposal on this issue.
---------------------------------------------------------------------------

    181. With respect to the reciprocity provision in the pro forma 
OATT, EEI requests that the Commission update it by including reference 
to transmission service by ISOs and RTOs. EEI asks that the reciprocity 
provision be modified to provide that, if an ISO or RTO is the 
transmission provider, the reciprocity obligation is owed to all 
members of the ISO or RTO. EEI notes, however, that even this action 
would not require non-public utility transmission providers to provide 
transmission services to other entities who are eligible customers 
under the ISO or RTO OATT and who are not transmission providers, such 
as independent generators. EEI asserts that non-public utility 
transmission providers may discriminate against certain transmission 
customers unless the reciprocity obligation is expanded. Sempra Global 
also asks the Commission to clarify that the right to seek transmission 
service from an unregulated transmitting utility pursuant to FPA 
section 211A is available to any entity that qualifies as an eligible 
customer under the Commission's pro forma OATT.
    182. EEI acknowledges that the Commission declined in Order No. 
888-A to expand the reciprocity provision beyond the specific 
transmission provider from which the transmission customer takes 
service on the ground that requiring ``non-public utilities to offer 
transmission service to entities other than public utility transmission 
providers increases the chances that they could lose tax-exempt 
status.'' \122\ However, EEI states, in 2002, the

[[Page 12293]]

Department of the Treasury adopted final regulations that in effect 
provide that providing open access transmission does not constitute 
private use.\123\ Therefore, EEI argues, this reason for limiting the 
services provided under the reciprocity obligation is no longer 
applicable.\124\
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    \122\ Citing Order No. 888-A at 30,287.
    \123\ Treas. Reg. Sec.  1.141-7(g).
    \124\ EEI asserts that the Commission also has the authority to 
make this change under FPA section 211A, which provides that the 
Commission may not require a State or municipality to take action 
under that section that would violate a private utility bond rule. 
If a non-public utility transmission provider is concerned about the 
impact on the tax-exempt status of its bonds, EEI suggests that it 
could seek a waiver from the Commission.
---------------------------------------------------------------------------

    183. Moreover, EEI argues, as originally established in Order Nos. 
888 and 888-A, the Commission stated that it was ``conditioning the use 
of public utility open access tariffs, by all customers including non-
public utilities, on an agreement to offer comparable (not unduly 
discriminatory services) in return.'' \125\ However, EEI states, the 
reciprocity provision of the pro forma OATT refers to ``similar terms 
and conditions'' but does not make clear what they should be 
``similar'' to. EEI argues that the term ``similar'' does not 
necessarily encompass the requirement that is part of comparability 
that the services provided be ``not unduly discriminatory'' as Order 
Nos. 888 and 888-A require. EEI proposes that the pro forma OATT be 
amended to refer to ``comparable terms and conditions'' rather than 
``similar'' to align it with Order Nos. 888 and 888-A. Finally, EEI 
also states that the Commission should also reaffirm that the 
reciprocity obligation is binding on Canadian utilities.
---------------------------------------------------------------------------

    \125\ Citing Order No. 888-A at 30,285.
---------------------------------------------------------------------------

    184. On reply, APPA urges the Commission to reject EEI's proposed 
expansion of the reciprocity provision. APPA notes that EEI's proposed 
application of the reforms to all non-public utility transmission 
providers would potentially include a broader universe of public power 
entities than those subject to FPA section 211A. Moreover, APPA argues, 
many of the goals that EEI claims it wishes to accomplish would be 
accomplished even if the Commission takes no action.
    185. In its reply comments, the Canadian Electricity Association 
urges the Commission to reject EEI's proposal to strengthen the 
reciprocity obligation so as to require the offering of transmission 
service to all eligible customers. The Canadian Electricity Association 
argues that the effect of EEI's proposal would be to enable a generator 
generating power in Canada to obtain access on a Canadian utility's 
transmission system, which is not the situation under the current 
reciprocity requirement. Consequently, the Canadian Electricity 
Association asserts, EEI's proposal would allow the Commission to fully 
impose open access requirements in Canada and would violate the 
principles of comity and undermine Canadian jurisdictional sovereignty.
    186. The Canadian Electricity Association also repeats its earlier 
arguments made in response to the NOI that, to the extent the 
Commission adopts the comparability standard in FPA section 211A for 
non-public utilities, the Commission must apply the same changes to 
Canadian utilities.
    187. EEI also urges the Commission to take certain steps to 
increase transparency and accountability in complying with the 
reciprocity requirement.\126\ For example, EEI states, the Commission 
could include on its Web site a list of all non-public utility 
transmission providers that have Commission-approved safe harbor 
reciprocity tariffs. According to EEI, such a list of entities would 
facilitate use of their transmission systems, provide transparency, and 
provide recognition to these entities for their voluntary efforts in 
accomplishing these goals.\127\
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    \126\ According to EEI, the new authority granted to the 
Commission under EPAct 2005 section 1281 (new FPA section 220) 
(Electricity Market Transparency Rules), which applies to all 
``market participants,'' provides another basis for requiring 
greater transparency under the pro forma OATT by non-public utility 
transmission providers. EEI argues that the Commission could rely on 
this new authority to require greater transparency in transmission 
service provided under the reciprocity obligation.
    \127\ EEI notes that, in the NOPR, the Commission referenced 
voluntary guidelines being developed by members of the LPPC. EEI 
believes this is a step in the right direction and looks forward to 
the opportunity to provide input on the proposed guidelines. In 
EEI's view, however, if any LPPC member wishes to use these 
guidelines as a safe harbor tariff, it must meet the safe harbor 
standard that the terms of service must be ``substantially 
conforming or superior to'' the revised OATT. The reciprocity 
obligation requires that the terms and conditions of service be 
comparable to those that the non-public utility transmission 
provider applies to itself and not be unduly discriminatory.
---------------------------------------------------------------------------

    188. EEI requests that the Commission also establish minimal 
transparency requirements for non-public utility transmission 
providers.\128\ EEI asserts that the Commission has ample authority 
under FPA section 211A and under the reciprocity provision of the pro 
forma tariff to apply this information reporting requirement to those 
large non-public utility transmission providers that are not exempted 
by section 211A(c).\129\
---------------------------------------------------------------------------

    \128\ EEI states that this informational filing should include 
information such as: whether or not they have a reciprocity or other 
tariff and how it can be obtained, whether they have an OASIS and 
location URL, whether they have standards of conduct and where they 
are posted, whether they have posted business practices, their 
contact for regional transmission planning, and their ATC 
methodology.
    \129\ Section 211A authorizes the Commission to require certain 
unregulated transmitting utilities to provide transmission services 
at rates that are comparable to those that the unregulated 
transmitting utilities charges itself and on terms and conditions 
(not related to rates) that are comparable to those under which the 
unregulated transmitting utility provides transmission services to 
itself and that are not unduly discriminatory or preferential.
---------------------------------------------------------------------------

    189. On reply, several commenters oppose EEI's transparency 
proposal. Among other things, they argue that EEI's proposal is 
unnecessary and duplicative of information that is already publicly 
available--e.g., the non-public utility's Web site, the Commission's 
Web site, or in some instances a regional entity's Web site (such as 
the wesTTrans OASIS).\130\ APPA further notes that LPPC has proposed 
that the terms and conditions in non-public utility transmission 
provider's tariffs would be publicly available on the individual 
utility's or a regional entity's Web site. In addition, NRECA asserts 
that, absent waivers, any non-public utility transmission provider that 
has adopted a ``safe-harbor'' tariff has adopted all of the OATT, 
OASIS, and Standards of Conduct requirements that apply to public 
utilities. NRECA and TANC both assert that the Commission does not have 
similar informational filing requirements for public utilities. 
Furthermore, TANC argues that it would be a waste of Commission 
resources to compile a list of all non-public utility transmission 
providers that have Commission-approved safe harbor tariffs. TANC also 
argues that to provide such an information filing would be unduly 
burdensome and a waste of nonjurisdictional utility transmission 
provider time and limited resources.
---------------------------------------------------------------------------

    \130\ E.g., APPA Reply, CMUA Reply, LPPC Reply, Lassen Reply, 
NRECA Reply, Sacramento Reply, and TANC Reply.
---------------------------------------------------------------------------

Commission Determination
    190. The Commission retains the reciprocity language in the Order 
No. 888 pro forma OATT, but updates it to include references to ISOs 
and RTOs, as suggested by EEI. We also modify the reciprocity provision 
to provide that, if an ISO or RTO is the transmission provider, the 
reciprocity obligation is owed to all members of that ISO or RTO. We 
concur with EEI's assessment that such modifications will more 
accurately reflect the current state of the industry. However, we will 
not adopt EEI's proposal to extend the reciprocity obligation to all 
eligible customers or

[[Page 12294]]

LPPC's proposal to revise the pro forma OATT language regarding 
comparability. We are not persuaded that either proposal is necessary 
at this time to prevent undue discrimination absent a complaint.
    191. We will also retain Order No. 888's three alternative 
provisions for satisfying the reciprocity condition, i.e.: A non-public 
utility that owns, controls, or operates transmission and seeks 
transmission service from a public utility must either satisfy its 
reciprocity obligation under a bilateral agreement, seek a waiver of 
the OATT reciprocity condition from the public utility, or file a safe 
harbor tariff with the Commission. Thus, for non-public utilities that 
choose to use the safe harbor tariff, its provisions must be 
substantially conforming or superior to the revised pro forma OATT in 
this Final Rule. A non-public utility that already has a safe harbor 
tariff must amend its tariff so that its provisions substantially 
conform or are superior to the revised pro forma OATT if it wishes to 
continue to qualify for safe harbor treatment. As the Commission stated 
in Order No. 888-A, a non-public utility may limit the use of its 
voluntarily offered safe harbor reciprocity tariff only to those 
transmission providers from whom the non-public utility obtains open 
access service, as long as the tariff otherwise substantially conforms 
to the pro forma OATT.\131\ We reiterate that these reciprocity 
requirements apply equally to all non-public utility transmission 
providers, including those located in foreign countries.
---------------------------------------------------------------------------

    \131\ See Order No. 888-A at 30,289.
---------------------------------------------------------------------------

    192. As the Commission proposed in the NOPR, we will not adopt a 
generic rule to implement the new FPA section 211A. Rather, we will 
apply its provisions on a case-by-case basis, such as when a public 
utility seeks service from an unregulated transmitting utility that has 
not requested service under the public utility's OATT and the 
reciprocity obligation therefore does not apply. A potential customer 
may file an application with the Commission seeking an order compelling 
the unregulated transmitting utility to provide transmission service 
that meets the standards of FPA section 211A. We adopt the NOPR 
proposal to amend our regulations to make clear that an applicant in an 
FPA section 211A proceeding against a non-public utility that has 
submitted an acceptable safe harbor tariff shall have the burden of 
proof to show why service under the safe harbor tariff is not 
sufficient and why an FPA section 211A order should be granted.\132\ 
Further, as we indicate below, we restate our expectation that 
unregulated transmission providers will participate in the open and 
transparent regional planning processes ordered below and note that, if 
there are complaints about such participation or the lack thereof, we 
will address them on a case-by-case basis.
---------------------------------------------------------------------------

    \132\ See revised 18 CFR 35.28(e)(1)(ii).
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V. Reforms of the OATT

A. Consistency and Transparency of ATC Calculations

    193. In the NOPR, the Commission proposed to take action under FPA 
section 206 to remedy undue discrimination in the provision of 
transmission service. The Commission recognized that while Order Nos. 
888 and 889 require transmission providers to offer and post any 
available transfer capability (ATC) on their OASIS, and file the 
methodology they use to calculate ATC as Attachment C to their OATTs, 
the industry has not developed a consistent methodology for evaluating 
ATC nor have transmission providers adequately made their ATC 
calculation methodology transparent. This inconsistency and lack of 
transparency creates the potential for undue discrimination in the 
provision of open access transmission service.
    194. In the NOPR, the Commission proposed to address this potential 
for undue discrimination by requiring industry-wide consistency and 
transparency of all components of the ATC calculation methodology and 
certain definitions, data, and modeling assumptions. The Commission 
proposed to provide guidance regarding aspects of ATC calculations that 
should be more consistent and proposed to direct public utilities, 
working through NERC \133\ and NAESB, to revise reliability standards 
and business practices that are relevant to ATC calculations. The 
Commission also proposed to require increased detail in Attachment C of 
each transmission provider's OATT and proposed amending the OASIS 
regulations to require increased transparency. Although commenters 
challenged aspects of this proposed remedy, no commenters challenged 
the underlying finding that ATC reform is necessary to remedy undue 
discrimination in the provision of transmission service.
---------------------------------------------------------------------------

    \133\ All references to NERC in the context of developing 
reliability standards are to NERC as the Electric Reliability 
Organization (ERO).
---------------------------------------------------------------------------

    195. The Commission also indicated that the lack of consistent, 
industry-wide ATC calculation standards poses a threat to the reliable 
operation of the bulk-power system, particularly because a transmission 
provider may not know of its neighbors' system conditions affecting its 
own ATC values. As a result of this reliability impact, the Commission 
observed that the proposed ATC reforms are also supported by FPA 
section 215(d)(5), through which the Commission has the authority to 
direct the ERO to submit a reliability standard that the Commission 
considers appropriate to implement FPA section 215.
    196. In light of these concerns, we direct public utilities, 
working through NERC reliability standards and NAESB business practices 
development processes, to produce workable solutions to complex and 
contentious issues surrounding improving the consistency and 
transparency of ATC calculations. We are directing our guidance to 
public utilities and require that they implement our direction by 
working with NERC to develop reliability standards that accomplish the 
ATC reforms required in this rulemaking. We will coordinate our 
directives here with the ATC-related reliability standards that are 
pending in Docket No. RM06-16-000.\134\ The specifics of our findings 
with respect to ATC reform are discussed below.
---------------------------------------------------------------------------

    \134\ We note that many of the ATC-related reliability standards 
filed in Docket No. RM06-16-000 were not addressed by the NOPR in 
that proceeding, pending the submittal of additional information. 
See Mandatory Reliability Standards for the Bulk-Power System, 71 FR 
64770 (Nov. 3, 2006), FERC Stats. & Regs. ] 32,608 at Appendix A 
(2006) (Reliability Standards NOPR).
---------------------------------------------------------------------------

1. Consistency
    197. In order to address the potential for remaining undue 
discrimination in the determination of ATC, the Commission proposed to 
require industry-wide consistency of certain definitions, data, and 
modeling assumptions of the ATC calculation.
a. Necessary Degree of Consistency
NOPR Proposal
    198. In the NOPR, the Commission recognized that transmission 
providers use several basic types of ATC calculation methodologies 
(with various permutations), and did not propose to require a single 
ATC calculation methodology to be applied by all transmission 
providers. However, the Commission proposed to achieve greater 
consistency in ATC calculations by directing the development of 
consistent definitions of the ATC components,\135\ as well as 
consistent data inputs, modeling assumptions, and data

[[Page 12295]]

exchange and coordination protocols. The Commission also required each 
transmission provider using an Available Flowgate Capacity (AFC) 
methodology to explain its definition of AFC, its calculation 
methodology and assumptions, and its process for converting AFC into 
ATC.
---------------------------------------------------------------------------

    \135\ The ATC components are total transfer capability (TTC), 
existing transmission commitments (ETC), capacity benefit margin 
(CBM), and transmission reserve margin (TRM).
---------------------------------------------------------------------------

Comments
    199. While the majority of commenters \136\ support the NOPR's 
proposal to increase consistency in the calculation of ATC, several 
caution the Commission to allow flexibility \137\ in order to capture 
differences in system operations,\138\ usage, market operations,\139\ 
and topology. Many assert that industry-wide standardization of the ATC 
calculation might not be possible and suggest that the Commission 
consider interconnection-wide,\140\ regional,\141\ or even sub-regional 
standardization. NARUC urges the Commission to facilitate State 
commission participation in efforts to reform ATC methodologies and 
calculations on a regional or sub-regional basis. Conversely, several 
commenters suggest that, if the Commission considers allowing use of 
different ATC calculations, it must impose a heavy burden on any entity 
seeking to justify a departure from the interconnection-wide or 
regional ATC standard.\142\
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    \136\ E.g., Alcoa, Alliance, Ameren, Arkansas Commission, 
Arkansas Municipal, AWEA, Duke, E.ON, EEI, ELCON, EPSA, Exelon, 
LDWP, MidAmerican, NRECA, NPPD, NERC, Occidental, Powerex, PJM, PPL, 
Progress Energy, Project for Sustainable FERC Energy Policy, Santee 
Cooper, Southern, Suez Energy NA, SPP, TAPS, TVA, TDU Systems, 
TranServ, Tacoma, TANC, WECC, WestConnect, and Xcel.
    \137\ E.g. Allegheny, Entergy, Indianapolis Power, North 
Carolina Agencies, and NARUC.
    \138\ E.g. Bonneville, Northwest IOUs, and NorthWestern.
    \139\ E.g. CAISO.
    \140\ E.g. Ameren and Tacoma.
    \141\ E.g. APPA, Barrick Reply, Duke, EEI, Imperial, 
International Transmission, LDWP, NARUC, Nevada Companies, New York 
Commission, NRECA, MidAmerican, Occidental Reply, Pinnacle, PNM-
TNMP, Public Power Council, CREPC, Salt River, Seattle, South 
Carolina E&G Reply, SPP Reply, Utah Municipals, and WPS Companies 
Reply.
    \142\ E.g. TDU Systems and East Texas Cooperatives Reply.
---------------------------------------------------------------------------

    200. Constellation proposes that the Final Rule establish a 
rebuttable presumption that the basic ATC calculation formula \143\ set 
forth in NERC's current ATC definition be identical within a region and 
that each element of the calculation have the same meaning for all 
transmission providers. Williams requests on reply that the Commission 
establish an industry-wide standard for the calculation of ATC and 
emphasizes that a consistent and transparent approach to evaluating ATC 
and ATC/AFC modeling assumptions is a prerequisite to the elimination 
of the broad discretion afforded transmission providers and, with it, 
the subtle discrimination practiced against customers.
---------------------------------------------------------------------------

    \143\ E.g., ATC = TTC - (ETC + CBM + TRM).
---------------------------------------------------------------------------

    201. Southern suggests that the basic ATC calculation should be 
defined for both firm and non-firm ATC calculations and also proposes 
that the following basic formulas be used: ATC (firm) = TTC - Firm 
Commitments or ETC - TRM - CBM; and ATC (non-firm) = TTC - Firm and 
Nonfirm Commitments + Postbacks of Redirected and Unscheduled Service - 
TRM - CBM. In addition, TDU Systems requests that the Commission 
require standardization of methods for calculating AFC and require NERC 
to create a formal definition of AFC.
    202. PNM-TNMP and Bonneville express concerns with imposing an 
industry-wide standardized ATC methodology, arguing that there are too 
many variables in the way systems are operated. In its reply comments, 
PNM-TNMP adds that NERC's ATC calculation method should take into 
consideration the need for regional variation, and focus on consistency 
in definitions and data inputs. WestConnect participants caution that 
the replacement of the contract path ATC approach used in the Western 
Electricity Coordinating Council (WECC) with a flowgate methodology 
could seriously disrupt transmission service in the Western 
Interconnection.
    203. PGP states that, although regional and sub-regional 
consistency is a good idea, there is no need for the Commission to 
require ``consistent'' ATC methodologies; rather, the emphasis should 
be on transparency of the methodologies, inputs, calculations and 
outputs. Other commenters agree that the Commission should not require 
overall standardization of ATC calculations, but instead permit 
regional differences with respect to certain aspects of the calculation 
of ATC.\144\ EEI argues that standardization of ATC methodologies would 
require transmission systems to adopt a ``lowest common denominator'' 
standard in order to ensure that system reliability is not compromised, 
which would result in a reduction in ATC. EEI suggests that the 
Commission should direct NERC to develop ATC calculation standards that 
incorporate regional variations in order to maximize confidence in 
standards and system use, and maintain reliability. In its reply 
comments, Exelon disagrees with EEI and states that there are no 
regional differences within the individual interconnections that would 
justify differences in the application of ATC calculations.
---------------------------------------------------------------------------

    \144\ E.g., EEI Reply, NARUC Reply, and Powerex Reply.
---------------------------------------------------------------------------

    204. Exelon states that ATC definitions must be consistent so that 
the various ATC components such as TRM have the identical meaning for 
all industry participants. In addition, Exelon argues that each ATC 
component (ETC, TRM, and CBM) must be used in the same manner for all 
purposes (e.g., granting transmission service to third parties or for 
the transmission provider's own network load).
    205. At the October 12 Technical Conference, NERC recognized that 
the goal of achieving consistency may not mean that a single ATC 
methodology is required.\145\ NERC explained that consistency can be 
achieved with a limited number of methodologies if the requirements of 
those methodologies are properly coordinated and communicated. NERC 
stated that the Standard Drafting Team modifying the modeling, data, 
and analysis (MOD) standards\146\ relevant to ATC is developing a 
standard applicable to three ATC calculation methodologies: the rated 
system path methodology (contract path), the network response 
methodology (network ATC), and the network response flowgate 
methodology (network AFC). NERC and the other panelists agreed that the 
two network methodologies are very similar in technique. NERC argued 
that the ultimate goal of ATC-related reforms should be to standardize 
definitions. The entire panel agreed that definitions must be 
consistent and a panelist representing Constellation asserted that 
broad differences in the core definitions of the ATC calculation are 
neither rational nor explainable.\147\
---------------------------------------------------------------------------

    \145\ Transcript of October 12 Technical Conference at 125-150.
    \146\ MOD standards refers to Modeling, Data, and Analysis 
Reliability Standards.
    \147\ Transcript of October 12 Technical Conference at 149-160.
---------------------------------------------------------------------------

    206. New Mexico Attorney General recommends that the Commission 
allow a utility to waive the requirement to make certain elements of 
ATC more consistent if the utility can show that it is making adequate 
progress towards developing consistent and transparent ATC calculations 
at the sub-regional level.
Commission Determination
    207. The Commission adopts the NOPR proposal to require industry-
wide

[[Page 12296]]

consistency of all ATC components and certain definitions, data, and 
modeling assumptions. The Commission also will require each 
transmission provider to include in Attachment C to its OATT detailed 
descriptions for calculating both firm and non-firm ATC, consistent 
with the requirements of this Final Rule. The purpose of increasing the 
consistency and transparency of ATC calculations is to reduce the 
potential for undue discrimination in the provision of transmission 
service, specifically by reducing the opportunity for transmission 
providers to exercise excessive discretion. We find that the amount of 
discretion in the existing ATC calculation methodologies gives 
transmission providers the ability and opportunity to unduly 
discriminate against third parties. In order to minimize this 
discretion, the Final Rule requires that all ATC components (i.e., TTC, 
ETC, CBM, and TRM) and certain data inputs, data exchange, and 
assumptions be consistent and that the number of industry-wide ATC 
calculation formulas be few in number, transparent and produce 
equivalent results. The Commission finds that these reforms will 
facilitate development of a more coherent and uniform determination of 
ATC.
    208. We reject requests to establish a single methodology for 
calculating ATC, however, for several reasons. It is not our intent to 
require transmission providers to incur the expense of developing and 
adopting a new one-size-fits-all software package to calculate ATC. We 
also see little benefit in requiring a ``lowest common denominator'' 
ATC calculator. While a uniform methodology may result in all 
transmission providers calculating ATC in an identical manner, it would 
also likely lead to software implementation costs in excess of the 
resulting benefits. More importantly, we find that the potential for 
discrimination does not lie primarily in the choice of an ATC 
calculation methodology, but rather in the consistent application of 
its components.
    209. All ATC calculation methodologies derive ATC by modeling the 
system to establish TTC, expressed in terms of contract paths or 
flowgates, and reducing that figure by existing transmission 
commitments (i.e., ETC), a margin that recognizes uncertainties with 
transfer capability (i.e., TRM), and a margin that allows for meeting 
generation reliability criteria (i.e., CBM). These calculation 
methodologies are developed based on physical characteristics of the 
transmission provider's transmission system, historical modeling 
practices, and processes developed for collection of input data related 
to transmission provider's own system conditions as well as relevant 
data that model neighboring systems' conditions. We therefore find that 
it is not the methodologies for calculating ATC themselves that create 
the opportunity for undue discrimination. Instead, we find that the 
potential for undue discrimination stems from two main sources:
    (1) Variability in the calculation of the components that are used 
to determine ATC and (2) the lack of a detailed description of the ATC 
calculation methodology and the underlying assumptions used by the 
transmission provider.\148\ The combination of a lack of consistency of 
the components of the ATC calculation coupled with the lack of 
transparency leaves customers and regulators unable to verify ATC 
calculations and may allow transmission providers to calculate ATC in 
different ways for different customers.
    210. Accordingly, we conclude that industry-wide consistency of all 
ATC components (TTC, ETC, CBM, and TRM) and certain data inputs and 
exchange, modeling assumptions, calculation frequency, and coordination 
of data relevant for the calculation of ATC will reduce the 
opportunities for the exercise of discretion that may lead to undue 
discrimination against unaffiliated transmission customers. The 
Commission understands that NERC currently is developing standards for 
three ATC calculation methodologies (contract or rating path ATC, 
network ATC, and network AFC).\149\ If all of the ATC components and 
certain data inputs and assumptions are consistent, the three ATC 
calculation methodologies being finalized by NERC through the 
reliability standards development process will produce predictable and 
sufficiently accurate, consistent, equivalent, and replicable results. 
It is therefore not necessary to require a single industry-wide ATC 
calculation methodology. The Commission instead concludes that use of 
the ATC calculation methodologies included in reliability standards 
currently being developed by NERC is acceptable.
---------------------------------------------------------------------------

    \148\ For example, utilities A and B would agree that ATC is 
derived by reducing TTC by the sum of ETC, CBM and TRM, but utility 
A may define ETC to include set-asides for contingencies while 
utility B may not.
    \149\ See Transcript of October 12, 2006 Technical conference at 
125. Thee three methodologies are different computational processes 
to determine a transmission system's ATC. The first, contract path, 
examines TTC for every A-to-B path on the system in concert with all 
others, reduces ATC by path for ETC, TRM, and CBM, as appropriate, 
and produces ATC for each path. The second method, net work ATC, 
uses a simulator to look not at each path, but each transmission 
element (line, substation, etc.,), and rule first contingency 
simulations to establish ATC on a network basis. The third method, 
network AFC, uses a simulator to examine critical flowgates over a 
wider area, then requires a second step to convert AFC values to 
particular path ATC values.
---------------------------------------------------------------------------

    211. As TDU Systems note, there is neither a definition of AFC in 
NERC's Glossary nor an existing reliability standard that discusses the 
AFC method. In order to achieve consistency in each component of the 
ATC calculation (discussed below), we direct public utilities, working 
through NERC, to develop an AFC definition and requirements used to 
identify a particular set of transmission facilities as a flowgate. 
However, we remind transmission providers that our regulations require 
the posting of ATC values associated with a particular path, not AFC 
values associated with a flowgate. Transmission providers using an AFC 
methodology must therefore convert flowgate (AFC) values into path 
(ATC) values for OASIS posting. In order to have consistent posting of 
the ATC, TTC, CBM, and TRM values on OASIS, we direct public utilities, 
working through NERC, to develop in the MOD-001 standard a rule to 
convert AFC into ATC values to be used by transmission providers that 
currently use the flowgate methodology.
    212. The Commission also believes that further clarification is 
necessary regarding the calculation algorithms for firm and non-firm 
ATC.\150\ Currently, NERC has no standards for calculating non-firm 
ATC. We find that the same potential for discrimination exists for non-
firm transmission service as for firm service and that greater 
uniformity in both firm and non-firm ATC calculations will 
substantially reduce the remaining potential for undue discrimination. 
Therefore, we direct public utilities, working through NERC, to modify 
related ATC standards by implementing the following principles for firm 
and non-firm ATC calculations: (1) For firm ATC calculations, the 
transmission provider shall account only for firm commitments; and (2) 
for non-firm ATC calculations, the

[[Page 12297]]

transmission provider shall account for both firm and non-firm 
commitments, postbacks of redirected services, unscheduled service, and 
counterflows. We understand that these principles are currently 
followed by most transmission providers and believe they should be 
clearly set forth in the ATC-related reliability standards. As 
described below, each transmission provider's Attachment C must include 
a detailed formula for both firm and non-firm ATC, consistent with the 
modified ATC-related reliability standards.
---------------------------------------------------------------------------

    \150\ The NERC ATC definition does not differentiate firm and 
non-firm ATC from a high level generic ATC definition: ``A measure 
of the transfer capability remaining in the physical transmission 
network for further commercial activity over and above already 
committed uses. It is defined as Total Transfer Capability less 
existing transmission commitments (including retail customer 
service), less a Capacity Benefit Margin, less a Transmission 
Reliability Margin.'' See North American Electric Reliability 
Corporation, Glossary of Terms Used in Reliability Standards 
(February 7, 2006).
---------------------------------------------------------------------------

    213. We deny New Mexico Attorney General's request to grant waiver 
of the ATC consistency requirements to utilities that can show that 
they are making adequate progress toward developing consistent and 
transparent ATC calculations at the sub-regional level. While we 
certainly encourage regional consistency with respect to the ATC 
calculation methodology, we are not requiring consistency; therefore a 
waiver is not necessary. As discussed in more detail below, any request 
for waiver from these ATC calculation requirements must take place 
through the NERC reliability standards development process as a request 
for a regional difference, since the ATC requirements will be 
determined through the NERC reliability standards.
b. Process To Achieve Consistency
NOPR Proposal
    214. In the NOPR, the Commission expressed confidence that the 
existing NERC and NAESB processes were well-suited to achieving greater 
consistency in ATC calculations. The Commission therefore proposed to 
require public utilities, working through NERC and NAESB, to revise the 
reliability standards and business practices relating to ATC, 
consistent with the guidance provided in the Final Rule, within 180 
days after the publication of the Final Rule in the Federal Register.
Comments
    215. Many commenters support the Commission's proposal directing 
NERC and NAESB to develop reliability standards and business practices 
addressing ATC.\151\ In addition, several commenters urge the 
Commission to be more precise in differentiating between policy and 
business standards, and urge the Commission to provide more guidance to 
NERC and/or NAESB.\152\ NRECA suggests that the Commission require NERC 
and NAESB to file the results of their processes with the Commission, 
give all interested parties an opportunity to comment on the proposals, 
and exercise its independent authority to review, and if necessary, 
remand the issues or proposals back to NERC and NAESB.
---------------------------------------------------------------------------

    \151\ E.g., Allegheny, APPA, Arkansas Commission, Bonneville, 
CAISO, Constellation, E.ON, EEI, ELCON, Entergy, Exelon, 
FirstEnergy, LPPC, MidAmerican, New York Commission, NERC, Northeast 
Utilities, Project for Sustainable FERC Energy Policy, PNM-TNMP, 
Santa Clara, Southern, Tacoma, TransServ, and Utah Municipals.
    \152\ E.g., EPSA and Williams.
---------------------------------------------------------------------------

    216. Occidental states on reply that it does not oppose NERC having 
a role in developing the basic requirements and standards for ATC. 
However, Occidental also urges the Commission to adopt a process 
similar to that employed in developing the Standards for Business 
Practices and Communication Protocols for Public Utilities, which were 
incorporated by reference into the pro forma OATT.\153\ There, the 
Commission allowed NAESB's Wholesale Electric Quadrant to develop, with 
widespread industry input, business practice standards that the 
Commission then reviewed, adopted and required public utilities to 
include in their OATTs by reference.\154\ Occidental claims that this 
process would ensure industry input in the development of the 
methodology for ATC calculations, as well as Commission review and 
approval of the methodology.
---------------------------------------------------------------------------

    \153\ Citing Standards for Business Practices and Communication 
Protocols for Pub. Utils., Order No. 676, 71 FR 26199 (May 4, 2006), 
FERC Stats. & Regs. ] 31,216 (2006), order on reh'g, Order No. 676-
A, 116 FERC ] 61,255 (2006).
    \154\ Citing id. at P 20.
---------------------------------------------------------------------------

    217. Several commenters raise concerns that six months may not be 
sufficient time to develop ATC-related reliability standards and 
business practices.\155\ Exelon, MidAmerican and NARUC propose that the 
Commission grant NERC one year from the date of the Final Rule to 
develop the necessary reliability standards. NARUC agrees with one 
year, but requests flexibility to assure that the NERC and NAESB 
processes can be adequately completed. NERC also states that it expects 
the standards development process, already underway, to be finalized 
with standards submitted to the Commission prior to the summer of 2007. 
LPPC recommends that, within six months of the issuance of the Final 
Rule, NERC be required to submit a progress report addressing the 
status and a work plan for conclusion within the ensuing six months. 
NRECA proposes that the Commission closely monitor the NERC and NAESB 
process. Some commenters strongly oppose a flexible deadline, and urge 
the Commission to establish a firm deadline that must be met.\156\
---------------------------------------------------------------------------

    \155\ E.g., Constellation, Duke, EEI, Exelon, LPPC, MidAmerican, 
NARUC, Northwest IOUs, Public Power Council, CREPC, Southern, TDU 
Systems, and WestConnect.
    \156\ E.g., Utah Municipals and Entegra.
---------------------------------------------------------------------------

    218. At the October 12 Technical Conference, NERC informed 
participants that a great deal of progress has been made since the 
proposed standards developed by the NERC Standard Committee in February 
2006 were generated to address the recommendations made by the Long-
Term AFC/ATC Task Force.\157\ However, NERC indicates that a 
significant amount of work remains before the standard revisions are 
considered complete. Since NERC would like to finalize its revised 
standards for submittal to the Commission for the summer of 2007, NERC 
has established an aggressive schedule of meetings for drafting which 
will be coordinated with NAESB.
---------------------------------------------------------------------------

    \157\ Citing Long-Term AFC/ATC Task Force Final Report (Revised 
April 14, 2005), available at http://www.nerc.com/~filez/ltatf.html.

---------------------------------------------------------------------------

    219. PJM outlines several guidelines it suggests the Commission 
should give to NERC and NAESB regarding the standards development 
process and recommends that Commission staff participate in the 
standards development process. Williams and EPSA likewise request that 
the Commission provide clear guidance to NAESB to assure efficiency and 
timeliness of the process.
    220. Some commenters prefer engagement of a fully independent 
organization to develop standards and practices related to ATC.\158\ 
EPSA strongly urges the Commission to require all transmission 
providers outside of RTO areas to contract with an independent entity 
to develop and/or monitor ATC calculations. Although TDU Systems agree 
with EPSA that vertically-integrated transmission providers that are 
not subject to the independent oversight of an ISO/RTO retain inherent 
incentives to discriminate against competitors, they contend that the 
benefit of independent oversight of ATC calculations must be weighed 
against the cost of that oversight. Alcoa suggests engaging the 
Institute of Electrical and Electronics Engineers (IEEE) instead of the 
Commission's proposal to use NERC and NAESB. APPA opposes that 
position. New York Commission proposes that regional reliability 
organizations, rather than NERC, complete this task and that the ATC 
calculators be closely coordinated by

[[Page 12298]]

ISOs and RTOs.\159\ PJM contends on reply that New York Commission's 
proposal for coordination of ATC between ISOs and RTOs has been 
fulfilled at least between PJM and its neighbors, arguing that New York 
Commission's proposal is unnecessary and would add a layer of 
bureaucracy and cost. TAPS expresses concern with the Commission 
proposal to use NERC and encourages the Commission to be precise in its 
direction to NERC to accomplish the needed objective.
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    \158\ E.g., Alcoa, Fayetteville, and MISO.
    \159\ If ISOs and RTOs cannot perform the coordination function, 
New York Commission suggests the establishment of a Transmission 
Oversight Center to oversee the calculation of ATC within and 
between ISOs and RTOs.
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Commission Determination
    221. The Commission directs public utilities, working through NERC 
and NAESB, to modify the ATC-related reliability standards and business 
practices in accordance with specific direction provided in this Final 
Rule. As we explain above, the development of a more coherent and 
uniform determination of ATC across a region will help limit the 
potential for undue discrimination in the calculation of ATC. The 
Commission concludes that the NERC reliability standards development 
process and the NAESB business practices development process are the 
appropriate forums for developing this consistency.
    222. NERC has been certified as the ERO and, as such, has been 
found to have the ability to develop reliability standards through 
processes with reasonable notice and opportunity for public comment. 
NERC's processes are open and provide due process as well as a balance 
of interests, while assuring independence from users and owners and 
operators of the bulk-power system. Moreover, NAESB has a long history 
of developing standard business practices for the electric industry, on 
which the Commission has relied in various contexts. While other 
entities may bring certain benefits, commenters have not demonstrated 
the superiority of IEEE, a regional reliability organization, or a 
particular RTO over NERC and NAESB. Once components of ATC are made 
consistent and ATC calculation methodologies are made transparent, 
opportunities for discretion that may lead to undue discrimination in 
the calculation of ATC will be sufficiently eliminated to invalidate 
the need for the creation of independent entities to oversee that 
calculation. To the extent that, even following the adoption of these 
reforms, customers have complaints regarding the calculations performed 
by individual transmission owners, they can be addressed on a case-by-
case basis.
    223. With respect to a timeline for completion, the Commission 
concurs with NERC that a significant amount of work remains to be done 
on ATC-related reliability standards development. We also agree with 
the many commenters who state that the NOPR's proposed six-month 
timeline is too short for such a complex assignment. Although NERC 
projects that it may be able to complete the process by the summer of 
2007 (which is approximately six months from the date of the Final 
Rule), we believe NERC should have additional flexibility with respect 
to its timeline. Accordingly, we direct public utilities, working 
through NERC, to modify the ATC-related reliability standards within 
270 days after the publication of the Final Rule in the Federal 
Register. We also direct public utilities to work through NAESB to 
develop business practices that complement NERC's new reliability 
standards within 360 days after the publication of the Final Rule in 
the Federal Register. Finally, we direct NERC and NAESB to file, within 
90 days of publication of the Final Rule in the Federal Register, a 
joint status report on standards and business practices development and 
a work plan for completion of this task within the timeframe 
established above.\160\
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    \160\ NAESB's work plan for developing business practices 
related to other reforms adopted in this Final Rule should be filed 
separately, as requested in Section IV.C.1.
---------------------------------------------------------------------------

c. Applicability to ISOs, RTOs, and Non-Public Utility Transmission 
Providers
NOPR Proposal
    224. The Commission did not specifically address the application of 
the ATC-related reforms proposed in the NOPR to ISOs and RTOs or non-
public utility transmission providers.
Comments
    225. ISOs and RTOs believe that the Commission should not require 
wholesale revisions of RTO and ISO tariffs, even on such issues as ATC 
standards.\161\ They caution that many regional grid operators' tariffs 
contain nonconforming provisions that were the product of extensive 
debate, litigation and settlements. In addition, some commenters point 
out that concern about ATC calculations is a non-issue in many ISO/RTO 
regions because transmission services in those regions are not based on 
physical transmission reservations.\162\
---------------------------------------------------------------------------

    \161\ E.g., PJM and MISO Transmission Owners, SPP Reply.
    \162\ E.g., ISO/RTO Council, ISO New England, and Pennsylvania 
Commission.
---------------------------------------------------------------------------

    226. MISO argues that AFC calculation methodologies should be 
established via the RTO stakeholder process, not NERC. In its reply 
comments, Exelon expresses disagreement with MISO and states that there 
must be one standard for ATC calculations, not several methods based on 
the desires of different sets of stakeholders. Several commenters also 
believe that ISOs/RTOs should not be exempt from the requirements for 
consistent and transparent ATC calculations.\163\
---------------------------------------------------------------------------

    \163\ E.g., NRECA and TDU Systems.
---------------------------------------------------------------------------

    227. EEI asks the Commission to require all municipal and other 
non-public utility transmission providers to adhere to any requirement 
for consistent and transparent ATC/AFC calculation. In its view, 
applying the ATC-related reforms to these nonjurisdictional entities 
would recognize the interconnected nature of the transmission grid. EEI 
argues that greater transparency and consistency in the provision of 
transmission service would be frustrated if all transmission providers 
do not have to comply. Other commenters reply that EEI's concerns are 
unfounded and describe an example in the WECC region, where the 
methodologies and practices regarding ATC calculations are developed by 
representatives from all affected transmission providers, utilities, 
and market participants, including nonjurisdictional entities.\164\
---------------------------------------------------------------------------

    \164\ E.g., Lassen and Public Power Council.
---------------------------------------------------------------------------

    228. LPPC contends that the NERC reliability standards related to 
ATC calculation will already be applicable to both public and non-
public utilities. LPPC argues that NERC standards, when final, will be 
filed with the Commission, become part of the ERO's mandatory 
reliability standards and will be fully applicable to otherwise 
nonjurisdictional entities. As a result, the ATC standards will be 
applicable to and enforceable upon all transmission owners, whether or 
not the transmission owner has an OATT.
Commission Determination
    229. We discuss the applicability of the Final Rule to ISOs and 
RTOs in section IV.C.2 above. With respect to the application of the 
ATC requirements of this Final Rule to municipal and other non-public 
utility transmission providers, we likewise note that the applicability 
of the rule generally to such entities is addressed in section

[[Page 12299]]

IV.C.3. We note here, however, that such entities will be required to 
comply with reliability standards developed under FPA section 215. As 
LPPC acknowledges, once these reliability standards are approved they 
will become part of the ERO's mandatory reliability standards and, 
thus, will be applicable to and enforceable upon all transmission 
owners, whether or not the transmission owner has adopted the OATT.
d. Alternatives to ATC Consistency
Comments
    230. Some commenters contend that the NOPR is focused too narrowly 
on simply improving the consistency and transparency of ATC 
determinations and suggest that a focus on balancing (or dispatch) 
services and how those are priced would allow the Commission to avoid 
the pitfalls inherent in the ATC approach.\165\ In their view, such an 
approach would eliminate much of the difference between how third 
parties are treated in RTO versus non-RTO systems. Constellation 
encourages the Commission to consider requiring transmission providers 
to implement all-inclusive, security constrained economic dispatch 
processes. In reply comments, Chandley-Hogan argue that the 
Commission's ATC-related proposals in the NOPR confuse how transmission 
service is actually provided in most of the United States and, as a 
result, the Commission's analysis of perceived problems in the 
calculation of ATC is flawed, inconsistent with network realities and 
the laws of physics, and incompatible with reliable operations.
---------------------------------------------------------------------------

    \165\ E.g., Chandley-Hogan, EPSA, PJM, San Diego G&E, and 
Transparent Dispatch Advocates Reply.
---------------------------------------------------------------------------

    231. Contrary to the above claims, some commenters find that ATC 
provides a functionally useful measure of available capacity and has 
certain advantages over alternative models.\166\ These commenters argue 
that the factual record does not support conclusions that bid-based, 
marginal cost dispatch by a third party is inherently more efficient or 
inherently more likely to remedy undue-discrimination than the OATT 
model, and cannot overcome the considerable real world obstacles to 
pure economic redispatch, including overlapping and dynamic 
constraints, and the physical realities in the Western Interconnection 
that often limit the pool of resources that can be redispatched to 
solve constraints. LPPC contends that the principal advantage of ATC is 
the certainty that it provides for available capacity, suggesting that 
the contract path paradigm facilitates long-term bilateral contracting.
---------------------------------------------------------------------------

    \166\ E.g., APPA, CMUA, CPA, Duke, EEI, Entergy, LPPC, Public 
Power Council, Sacramento, and WestConnect Reply.
---------------------------------------------------------------------------

Commission Determination
    232. In this rulemaking, the Commission is requiring consistency in 
the determination of ATC with the purpose of improving a customer's 
ability to receive transmission service on a non-discriminatory basis. 
These reforms are fully consistent with operational reality, and we 
decline to mandate the security constrained economic dispatch 
alternative proposed by Chandley-Hogan. Chandley-Hogan argue that it 
would be unduly discriminatory to exclude third-party generators from 
an efficient dispatch to serve native load and therefore a centralized, 
bid-based market is required. We agree that a centralized bid-based 
market can benefit customers and, over a large region, can manage 
congestion efficiently. We do not believe, however, that mandating that 
result--essentially requiring that Day 2 RTOs be adopted in every 
region of the country--is necessary to remedy undue discrimination in 
the provision of transmission service. The concern raised by Chandley-
Hogan is not related solely to the nondiscriminatory use of the 
transmission system. It also implicates the purchase decisions of 
transmission providers on behalf of their native load customers. These 
decisions are regulated primarily by the states and we decline to take 
generic action in this rulemaking to reform the processes by which 
those purchases are made.
e. ATC Components
    233. The next several sections address components of ATC that must 
be made consistent to remove the potential for undue discrimination, 
namely TTC/TFC, ETC, CBM, and TRM.
(1) Total Transfer Capability (TTC)/Total Flowgate Capability (TFC)
NOPR Proposal
    234. The Commission proposed to direct public utilities, working 
through NERC, to develop consistent practices for calculating total 
transfer/flowgate capability (TTC/TFC). Although the NERC reliability 
regions have historically calculated transfer capability using 
different approaches, the Commission expressed its view that guidelines 
for a common approach to calculating transfer capability are 
achievable. The Commission also stated that the criteria used for 
identifying flowgates and determining TFC could be more consistent.
Comments
    235. Entergy supports the development of consistent practices for 
determining transfer capability while maintaining flexibility to 
recognize regional and system-specific differences. APPA agrees that 
the calculation of TTC/TFC is, for the most part, a regional 
calculation. APPA states that the Western Interconnection and ERCOT use 
their own methods, which are generally applied system-wide. APPA 
believes that more standardization and coordination of TTC/TFC among 
transmission providers in the Eastern Interconnection, where two 
primary methods are used to calculate TTC or TFC, would be desirable 
because of reported loop-flow problems in the Eastern Interconnection.
    236. In order to increase transfer capability from existing 
facilities, AWEA proposes that the Commission direct NERC, as part of 
developing consistent ATC standards, to investigate the impact of 
implementing dynamic line ratings in TTC/TFC calculations and propose 
protocols to effectuate such a program. In response to AWEA's proposal, 
commenters state that if the Commission decides to provide guidance to 
NERC with regard to dynamic line ratings, the Commission should 
encourage NERC to develop standards with regard to dynamic line ratings 
in the operating horizon, but not in the planning horizon.\167\
---------------------------------------------------------------------------

    \167\ E.g., MAPP and MidAmerican.
---------------------------------------------------------------------------

Commission Determination
    237. The Commission adopts the NOPR proposal and directs public 
utilities, working through NERC, to develop consistent practices for 
calculating TTC/TFC. We direct public utilities, working through NERC, 
to address, through the reliability standards process, any differences 
in developing TTC/TFC for transmission provided under the pro forma 
OATT and for transfer capability for native load and reliability 
assessment studies.
    238. We acknowledge that reliability regions have historically 
calculated transfer capability using different approaches, and we agree 
that regional differences should be respected.\168\ However, as already 
discussed above regarding ATC, the TTC requirements will be determined 
by the NERC reliability standards and any request for a regional 
difference from the reliability standards must take place through the 
NERC process.
---------------------------------------------------------------------------

    \168\ For example, WECC has a documented open process for 
establishing TTC for the Western Interconnection.

---------------------------------------------------------------------------

[[Page 12300]]

    239. With respect to AWEA's proposal regarding implementing dynamic 
line ratings in TTC/TFC calculations, the Commission finds that this 
proposal is outside the scope of this rulemaking as it does not appear 
to relate to undue discrimination in transmission service and, in any 
event, would best be addressed in the first instance through the NERC 
reliability standards development process, addressing reliability 
standards that regulate facility ratings. If AWEA desires to pursue 
this proposal, it should propose an appropriate dynamic line rating 
standard within the ERO's reliability standards development process.
(2) Existing Transmission Commitments (ETC)
NOPR Proposal
    240. In the NOPR, the Commission expressed its view that the lack 
of consistency in modeling of existing transmission commitments (ETC) 
resulted in excessive discretion in determining how much capacity a 
transmission provider sets aside for native load, including its network 
customers. The Commission therefore proposed the development of a 
consistent methodology for determining the capacity needed and set 
aside for native load usage. The Commission also proposed that 
accounting for transmission reservations in an ATC/AFC calculation be 
more consistent. The Commission further proposed that public utilities, 
working through NERC, establish and specifically identify the 
reservations to be used in determining ETC.
Comments
    241. Entegra and PGP support increasing consistency in determining 
ETC. APPA agrees that it would be helpful to standardize the method of 
accounting for ETC on an interconnection-wide basis. APPA states, 
however, that flexibility might be required among the interconnections. 
TDU Systems requests that the Commission define with specificity the 
types of transmission service requests or scheduled transmission 
transactions that should be included in ETC and agrees with the 
Commission that inclusion of all requests for transmission service in 
ETC is likely to overstate usage of the system, thus understating ATC. 
It suggests that the Commission develop a bright line method for 
calculating ETC. NERC notes that its proposed reliability standards 
would define ETC and require appropriate documentation. NERC adds, 
however, that the components included in ETC appear to be candidates 
for business practices rather than reliability standards.
    242. Williams proposes that ETC be the subject of an expanded 
definition and that native load growth projections be based on 
verifiable data provided by an independent source. It also states that 
transmission providers should be required to update ATC based on each 
confirmed transmission service reservation (point-to-point or network, 
firm or non-firm).
Commission Determination
    243. To achieve greater consistency in ETC calculations and further 
reduce the potential for undue discrimination, the Commission adopts 
the NOPR proposal and directs public utilities, working through NERC 
and NAESB, to develop a consistent approach for determining the amount 
of transfer capability a transmission provider may set aside for its 
native load and other committed uses. We expect that NERC will address 
ETC through the MOD-001 reliability standard rather than through a 
separate reliability standard.\169\ By using MOD-001, the ETC 
calculation can be adjusted to be applicable to each of the three ATC 
methodologies under development by NERC.
---------------------------------------------------------------------------

    \169\ The purpose of MOD-001 is to promote the consistent and 
uniform application of transfer capability calculations among the 
transmission system users.
---------------------------------------------------------------------------

    244. In order to provide specific direction to public utilities and 
NERC, we determine that ETC should be defined to include committed uses 
of the transmission system, including (1) Native load commitments 
(including network service), (2) grandfathered transmission rights, (3) 
appropriate point-to-point reservations,\170\ (4) rollover rights 
associated with long-term firm service, and (5) other uses identified 
through the NERC process. ETC should not be used to set aside transfer 
capability for any type of planning or contingency reserve, which are 
to be addressed through CBM and TRM.\171\ In addition, in the short-
term ATC calculation, all reserved but unused transfer capability (non-
scheduled) shall be released as non-firm ATC.
---------------------------------------------------------------------------

    \170\ By ``appropriate,'' we mean that reservations accounted 
for under ETC depend on the firmness and duration of the 
reservation. The specific characteristics should be developed in the 
reliability standard.
    \171\ TRM also includes such things as loop flow and parallel 
path flow.
---------------------------------------------------------------------------

    245. We agree with TDU Systems that inclusion of all requests for 
transmission service in ETC would likely overstate usage of the system 
and understate ATC. We therefore find that reservations that have the 
same point of receipt (POR) (generator) but different point of delivery 
(POD) (load), for the same time frame, should not be modeled in the ETC 
calculation simultaneously if their combined reserved transmission 
capacity exceeds the generator's nameplate capacity at POR. This will 
prevent overly unrealistic utilization of transmission capacity 
associated with power output from a generator identified as a POR. We 
direct public utilities, working through NERC, to develop requirements 
in MOD-001 that lay out clear instructions on how these reservations 
should be accounted. One approach that could be used is examining 
historical patterns of actual reservation use during a particular 
season, month, or time of day.
    246. We agree with NERC that some elements of ETC are candidates 
for business practices rather than reliability standards. Accordingly, 
we direct public utilities, working through NAESB, to develop business 
practices necessary for full implementation of the developed MOD-001 
reliability standard.
    247. We decline to adopt Williams's proposal to require that native 
load growth be based on the verifiable data provided by an independent 
source. Through increased consistency and transparency of ATC 
determinations, including requirements for posting additional data, 
third parties will be able to verify the accuracy of ETC, helping to 
eliminate opportunities for undue discrimination.
(3) Capacity Benefit Margin (CBM)
NOPR Proposal
    248. In the NOPR, the Commission proposed three options to address 
the CBM component of ATC: (1) Have NERC develop clear standards for how 
the CBM value should be determined, allocated across transmission 
paths, and used; (2) charge an entity for which transfer capability has 
been set aside to meet generation reliability criteria a separate rate 
for this service; or (3) eliminate CBM and require an entity reserving 
ATC to meet generation reserve (currently through CBM) to designate 
network resources on the other side of the interface and make an 
associated transmission service reservation.
Comments
    249. Numerous commenters support the Commission's proposed option 
one, requiring NERC to develop clear standards for how the CBM value 
should be determined, allocated across

[[Page 12301]]

transmission paths, and used.\172\ They believe that CBM ensures the 
ability to import needed power to support system conditions. TVA argues 
that option two would be costly and may cause some systems to forego 
CBM, thereby jeopardizing service to native load customers. PJM states 
that option two is irrelevant in PJM since PJM ``totals'' reservations 
and decides when CBM can be used. Supporters of option one criticize 
option three, elimination of CBM, as costly and a threat to 
transmission system reliability. Southern, Progress Energy, and PJM 
emphasize that, without CBM, the LSEs would need to increase their 
reserve margin by contracting for additional generation capacity, 
costing millions of dollars. In addition, Ameren and TVA believe that 
CBM elimination will increase the likelihood of widespread blackouts in 
emergency conditions.
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    \172\ E.g., Allegheny, Ameren, EEI, Duke, NRECA, TVA, APPA, 
Bonneville, EPSA, FirstEnergy, Indianapolis Power, MidAmerican, 
Pinnacle, PJM, PGP, PNM-TNMP, Public Power Council, Sacramento, 
Seattle, South Carolina E&G, TANC, TDU Systems, and Wisconsin 
Electric.
---------------------------------------------------------------------------

    250. At the October 12 Technical Conference, Exelon supported 
option two proposing a charge for CBM. Exelon contended that, in a 
rate-making context, there would be an increase in the divisor of the 
rate by the amount of CBM set-aside which would lower the point-to-
point charge. Consequently, those not benefiting from the CBM set-aside 
effectively would be paying a lower charge.
    251. Constellation and Morgan Stanley support the elimination of 
CBM and argue that CBM and TRM are often used interchangeably and 
result in duplicative transmission set-asides. They also argue that 
there is no compelling need for CBM in the current liquid market 
environment. In addition, Morgan Stanley states that LSEs affiliated 
with the transmission provider should not be allowed to use CBM for 
long-term planning purposes as an excuse to avoid undertaking needed 
resource additions or to conceal the true cost of their load serving 
functions. Furthermore, the Commission should not be distracted by 
assertions that such long-term arrangements are necessary for 
``reliability,'' when in fact they are simply a way to protect the 
economic interests of a particular entity.
    252. Duke replies that Constellation mistakenly believes that CBM 
is currently only available to a transmission provider's native load 
when, in fact, for those transmission providers that establish CBM, it 
should be established for the load of all LSEs in the control area. 
Duke contends that not all transmission providers set aside capacity 
through CBM for their native load; to the extent that a transmission 
provider does not set aside CBM, there should be no obligation to allow 
other LSEs to do so. Duke proposes that the Commission should continue 
to permit such flexibility.
    253. NERC takes no position on CBM, expecting that the issue can be 
settled through the NERC and NAESB Procedure for Joint Standards 
Development and Coordination and through other open forums.
    254. TAPS suggests that the Commission ensure that all LSEs have 
both access to CBM to meet their reserve-sharing needs and meaningful 
input into how much CBM is reserved. To do so, TAPS recommends the 
creation of a reserve-sharing group made up of the transmission 
provider and LSEs it serves. It argues that this would remove 
reservation decisions from the sole discretion of the vertically-
integrated transmission provider and instead have them made by the 
transmission provider/LSE reserve-sharing group, subject to dispute 
resolution at the Commission. All LSEs would be invited to participate 
in the studies as well as review the results and assumptions. Moreover, 
once a regional planning process is established, as proposed in the 
NOPR, TAPS recommends that the regional planning group be required to 
approve the CBM reservation as well.
    255. Williams suggests that a transmission provider must designate 
network resources and reserve firm transfer capability on both sides of 
the control area transmission interface in order to reserve CBM. Duke 
replies that, although some commenters prefer eliminating CBM and 
replacing it with additional designated network resources, CBM is the 
preferable option because it is less costly. Duke further argues that 
the choice is between setting aside both additional transmission and 
generation capacity to deal with emergencies (the additional designated 
network resource approach) versus setting aside only transmission (the 
CBM approach). Having to procure additional designated network 
resources to keep in reserve reduces one of the main benefits of 
interconnected operations. Duke argues that eliminating CBM would drive 
up costs for network customers, as they would have to procure 
additional generation and transmission resources. EEI adds that such a 
proposal may result in increased LSE reserve requirements, over-
building of generation supply, and a reduction, rather than an 
increase, in ATC.
Commission Determination
    256. The Commission concludes that it is appropriate to allow LSEs 
to retain the option of setting aside transfer capability in the form 
of CBM to maintain their generation reliability requirement. We agree 
with commenters that, without CBM, LSEs would have to increase their 
generation reserve margins by contracting for generation capacity, 
which may result in higher costs without additional reliability 
benefits. We require, however, the development of standards for how CBM 
is determined, allocated across transmission paths, and used in order 
to limit misuse of transfer capability set aside as CBM. Transmission 
providers also must reflect the set-aside of transfer capability as CBM 
in the development of the rate for point-to-point transmission service 
to ensure comparable treatment for point-to-point to customers.
    257. The Commission therefore adopts a combination of the NOPR 
options one and two, and declines to adopt option three. First, we 
require public utilities, working through NERC and NAESB, to develop 
clear standards for how the CBM value shall be determined, allocated 
across transmission paths, and used. We understand that NERC has 
already begun the process of modifying several of the CBM-related 
reliability standards and that the drafting process is a joint project 
with NAESB. Second, we require transmission providers to reflect the 
set-aside of transfer capability as CBM in the development of the rate 
for point-to-point transmission service.
    258. We note that there is broad concern that eliminating CBM 
(option three) would impose extraordinary costs for meeting generation 
reliability criteria, which then may lead utilities to reduce their 
generation reliability requirement to avoid the cost increase. We 
believe that the reforms reflected in combining options one and two are 
sufficient to remedy undue discrimination and that the adverse effects 
associated with option three are neither warranted nor required. We 
reject Morgan Stanley's call for CBM elimination on the grounds that 
CBM is acting as a disincentive to undertake needed generation resource 
additions. It would be inappropriate for the Commission to restrict the 
ability of an LSE to determine how best to meet its generation 
reliability criteria.
    259. To ensure CBM is used for its intended purpose, CBM shall only 
be used to allow an LSE to meet its generation reliability criteria. 
Consistent with Duke's statement, we clarify that

[[Page 12302]]

each LSE within a transmission provider's control area has the right to 
request the transmission provider to set aside transfer capability as 
CBM for the LSE to meet its historical, State, RTO, or regional 
generation reliability criteria requirement such as reserve margin, 
loss of load probability (LOLP), the loss of largest units, etc.
    260. We direct public utilities, working through NERC, to develop 
clear requirements for allocating CBM over transmission paths and 
flowgates. While we do not mandate a particular methodology for 
allocating CBM to paths and flowgates, one approach could be based on 
the location of the outside resources or spot market hubs that an LSE 
has historically relied on during emergencies resulting from an energy 
deficiency.
    261. We concur with TAPS' proposal that all LSEs should have access 
to CBM and meaningful input into how much transfer capability is set 
aside as CBM. In the transparency section below, we provide detailed 
requirements regarding availability of documentation used to determine 
the amount of transfer capability to be set aside as CBM and the 
posting of CBM values and narratives. Access to this documentation will 
enable LSEs to validate how much transfer capability is set aside as 
CBM on each system and provide them with information to question 
whether the set-aside is consistent with the reliability standards and 
this Final Rule.
    262. Concerning TAPS' proposal to remove the reservation decision 
from the sole discretion of transmission providers, we determine that 
LSEs should be permitted to call for use of CBM, if they do so pursuant 
to conditions established in the reliability standards development 
process. We direct public utilities working through NERC to modify the 
CBM-related standards to specify the generation deficiency conditions 
during which an LSE will be allowed to use the transfer capability 
reserved as CBM. In addition, we direct that transmission set aside as 
CBM shall be zero in non-firm ATC calculations. Finally, we order 
public utilities to work with NAESB to develop an OASIS mechanism that 
will allow for auditing of CBM usage.
    263. We also require transmission providers to design their 
transmission charges to ensure that the class of customers not 
benefiting from the CBM set-aside, i.e., point-to-point customers, do 
not pay a transmission charge that includes the cost of the CBM set-
aside. To do this, transmission providers are required to submit 
redesigned transmission charges that reflect the CBM set-aside through 
a limited issue FPA section 205 rate filing as part of its initial ATC-
related compliance filing. These filings, which may be submitted within 
120 days after the publication of the Final Rule in the Federal 
Register, may be limited to the rate design change only, i.e., they 
will not require the submission of cost of service data or a revision 
to the transmission provider's revenue requirement.
    264. With respect to TAPS' proposal that all LSEs should be allowed 
to use CBM to meet their reserve-sharing needs, we believe that TRM is 
the appropriate category for that purpose, not CBM. We reject TAPS' 
proposal to use CBM for the LSE's reserve-sharing needs, but instead 
make TRM available for the incremental power flows resulting from 
reserve sharing, as explained next.
    265. As we are rejecting option three, which would have required 
the reservation of transfer capability rather than using CBM, we also 
reject Williams' proposal to require the reservation of transfer 
capability on both sides of an interface for CBM.
(4) Transmission Reserve Margin (TRM)
NOPR Proposal
    266. Finally, the Commission proposed the development of 
reliability standards MOD-008 and MOD-009 \173\that specify the 
uncertainties that TRM could be used to accommodate, which could 
include (1) Load forecast and load distribution error, (2) variations 
in facility loadings, (3) uncertainty in transmission system topology, 
(4) loop flow impact, (5) variations in generation dispatch, including 
intermittent resources, (6) automatic sharing of reserves, and (7) 
other uncertainties identified through the NERC reliability standards 
development process.
---------------------------------------------------------------------------

    \173\ The MOD-008 and MOD-009 reliability standards document 
regional TRM methodologies and procedures for verifying TRM values.
---------------------------------------------------------------------------

Comments
    267. Most commenters agree that the existing definitions for TRM 
require clarification.\174\ Commenters also agree that NERC should be 
required to develop clear standards for the determination of TRM, 
including specifying the criteria used in the determination of 
TRM.\175\ PNM-TNMP supports the Commission's proposal, pointing out 
that the implementation of the current NERC standards definition for 
TRM and CBM could result in its double-counting, which must be 
eliminated. APPA members in the Western Interconnection suggest that 
regional variations be permitted. They also note that the modeling 
methods used by WECC and its sub-regions may differ from those used in 
the Eastern Interconnection. For example, they contend that 
uncertainties associated with transmission maintenance schedules that 
are driven by hydro-production curves will seasonally affect TRM set-
asides on certain transfer paths. PJM believes that the TRM methodology 
should be consistent at the regional reliability organization level. 
PJM also contends that TRM should be coordinated, exchanged and 
respected on external flowgates and that the concept of a maximum TRM, 
by percentage, should be adopted in the NERC standards.
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    \174\ E.g., Allegheny, APPA, EEI, EPSA, Exelon, LPPC, 
MidAmerican, NRECA, Northwest IOUs, NorthWestern, Occidental, 
Pinnacle, Powerex, PNM-TNMP, PPL, PJM, PPM, and WestConnect.
    \175\ Exelon recommends that the following factors should be the 
same for the planning process and ATC/AFC process to achieve 
consistency: base case flows, reservation impacts, TRM and CBM 
forecasted to occur simultaneously; counterflows; positive impacts 
resulting from reservations and generation dispatch; TRM for the 
same scenarios; and CBM.
---------------------------------------------------------------------------

    268. Consistent with its position on CBM, TAPS proposes that TRM 
set-asides should be conditioned on inclusive reserve-sharing 
arrangements, with the reservations determined by the reserve-sharing 
group, subject to dispute resolution before the Commission (and, 
eventually, approval by joint planning groups).
    269. PNM-TNMP suggests that the Commission consider definitions to 
include the following clarification taken from WECC procedures on ATC: 
``If the limitation on the use of TRM to 59 minutes would force a 
Transmission Provider to set aside unnecessary CBM on the same path as 
the TRM, that Transmission Provider may utilize the TRM beyond the 59 
minutes.'' \176\ PNM-TNMP states that this would allow the transmission 
provider to maximize the ATC by not needlessly setting aside twice the 
amount of transmission (TRM and CBM) than is necessary for reliability.
---------------------------------------------------------------------------

    \176\ Citing WECC Rocky Mountain Operating and Planning Group, 
Determination of Available Transfer Capability within the Western 
Interconnection, June 2001, page 9, http://www.wecc.biz/modules.php?op=modload&name=Downloads&file=index&req=getit&lid=1035
.

---------------------------------------------------------------------------

    270. Nevada Companies argue that no new standards are required for 
TRM and that any further action would be burdensome. They explain that 
NERC has a well-established definition that does not require further 
clarification. In their view, all that is required is a complete 
statement, to be posted on OASIS, regarding the transmission provider's 
application of TRM. NERC

[[Page 12303]]

comments that the existing reliability standards for TRM will be 
revised to require clear documentation of the calculation of TRM. It 
also adds that the revised standard will make various TRM components 
mandatory to achieve more consistency across methodologies.
    271. Santee Cooper urges the Commission to ensure that service to 
native load and transmission system reliability will not be compromised 
as the Commission seeks greater levels of consistency in the 
calculation of ATC. It states that the Commission also must be 
cognizant of the importance of TRM in the provision of service to 
native load.
Commission Determination
    272. The Commission adopts the NOPR proposal and requires public 
utilities, working through NERC, to complete the ongoing process of 
modifying TRM standards MOD-008 and MOD-009. We understand that the 
standard drafting process is underway as a joint project with NAESB.
    273. The Commission also adopts the NOPR proposal to establish 
standards specifying the appropriate uses of TRM to guide NERC and 
NAESB in the drafting process. Transmission providers may set aside TRM 
for (1) Load forecast and load distribution error, (2) variations in 
facility loadings, (3) uncertainty in transmission system topology, (4) 
loop flow impact, (5) variations in generation dispatch, (6) automatic 
sharing of reserves, and (7) other uncertainties as identified through 
the NERC reliability standards development process. Because load, 
facility loading and other uncertainties constantly deviate, we will 
not require that TRM set aside capacity be set at zero in the non-firm 
ATC calculation. In other words, we will not require transfer 
capability that is set aside as TRM to be sold on a non-firm basis. We 
find that clear specification in this Final Rule of the permitted 
purposes for which entities may reserve CBM and TRM will virtually 
eliminate double-counting of TRM and CBM.
    274. We will not adopt PNM-TNMP's proposal regarding use of set 
aside transfer capability as TRM beyond 59 minutes, rather than 
converting it to CBM. Our proposal is to separate transfer capability 
set asides as either CBM or TRM without regard to duration of use of 
the set aside. Therefore, such a clarification is not necessary.
    275. In addition, we direct public utilities, working through NERC, 
to establish an appropriate maximum TRM. One acceptable method may be 
to use a percentage of ratings reduction, i.e., model the system 
assuming all facility ratings are reduced by a specific percentage. 
This is a relatively simple method and, if adopted as the reliability 
standard's method, should not restrict a transmission provider from 
using a more sophisticated method that may allow for greater ATC 
without reducing overall reliability.
    276. Because of the operational characteristics of the 
uncertainties that are to be accommodated using TRM, and their 
aggregate impact on reliable operation, we require each transmission 
provider to calculate, and allocate on the paths and flowgates, the 
aggregate TRM value for all LSEs within its area. We support NERC's 
plan to revise existing reliability standards for TRM to require clear 
documentation of the TRM calculation, as we expect the TRM value to be 
supported and fully transparent. In addition, we require each 
transmission provider to make available all underlying documentation, 
including work papers and load flow base cases, used to determine TRM, 
to any transmission customer and LSE within its control area, subject 
to a confidentiality agreement,\177\ if necessary. We agree with Santee 
Cooper's comments that the Commission must ensure that service to 
native load and system reliability are not compromised. We believe that 
our requirement for public utilities to work through NERC satisfies 
such concerns.
---------------------------------------------------------------------------

    \177\ The agreement may appropriately restrict the sharing of 
sensitive information with customer personnel that are involved only 
in transmission functions, as opposed to merchant functions.
---------------------------------------------------------------------------

    277. With respect to the proposal to permit regional variations in 
the TRM calculation methodology, we reiterate our position stated above 
that any request for regional difference from the applicable 
reliability standards must take place through the NERC reliability 
standards development process. With respect to TAPS' proposal regarding 
reserve sharing groups, we clarify that, to the extent transfer 
capability is needed for transmission of shared reserves, this is 
included under TRM. However, as noted previously in the CBM discussion, 
we are not mandating the use of reserve sharing groups.
f. Modeling, Assumptions and Input Data
NOPR Proposal
    278. The Commission's proposal with regard to modeling, assumptions 
and data inputs was based on a principle that there should be 
consistency among transmission providers and between what the 
transmission provider does for its operation and expansion planning for 
native load and what it does in determining short and long-term ATC for 
all uses. The Commission stated its view that consistency is necessary 
to ensure non-discriminatory treatment by eliminating a transmission 
provider's ability to use discretion to the disadvantage of 
competitors. The Commission proposed three specific areas for reform.
    279. First, the Commission proposed to require public utilities, 
working through NERC, to modify the ATC-related standards to 
incorporate a requirement for periodic validation and modification of 
models to ensure that they are up to date.\178\ The Commission stated 
that the models should be updated and benchmarked to actual events.
---------------------------------------------------------------------------

    \178\ The Commission noted that this would include review of 
load flow base cases, short circuit data, transient and dynamic 
stability simulation data, contingency (files should contain 
information on special protection schemes and remedial action plans) 
subsystem and monitoring files, and production cost models.
---------------------------------------------------------------------------

    280. Second, the Commission proposed that, to the maximum extent 
practicable, the same data must be used by the transmission provider to 
determine short- and long-term ATC as those used in system operation 
and planning studies, respectively.
    281. Third, the Commission proposed that public utilities, working 
through NERC, develop assumptions for use in ATC determinations and 
that the assumptions remain consistent among transmission providers to 
the maximum extent practicable. The Commission indicated that short- 
and long-term ATC calculations should be developed using consistent 
assumptions regarding representative load levels, generation dispatch, 
transmission reservations and counterflows, in addition to any other 
modeling assumptions identified by NERC. The Commission further 
proposed that there should be a consistent approach to the modeling of 
load levels, a method established for determining which generators 
should be modeled in service (including guidance on how independent 
generators should be considered), consistency in the simulation of 
power flows from points of receipt to delivery when sources are 
unknown, and consistency in the manner in which ATC/AFC reservations 
are accounted for. The Commission stated that the model for long-term 
ATC should include, to the maximum extent practicable, the same 
assumptions regarding new transmission and generation facilities 
additions and retirements as those used in planning for expansion.
    282. The Commission noted that the proposal is not intended to 
change the manner in which native load is served

[[Page 12304]]

and sought comment on whether (and, if so, how) this proposal would 
affect service to native load customers.
Comments
    283. Commenters generally discuss consistency of data, assumptions 
and modeling together so we in turn do the same. Many commenters 
support the proposals for consistency in data, assumptions and/or 
modeling.\179\ Others support flexibility or regional variation.\180\ A 
few commenters oppose specific aspects of the overall proposal.\181\
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    \179\ E.g., APPA, Arkansas Commission, Constellation, Entegra, 
Exelon, EPSA, ISO/RTO Council, LDWP, MidAmerican, Municipals, NRECA, 
CREPC, Sacramento, Santee Cooper, Suez Energy NA, TAPS, TDU Systems, 
WestConnect, and Williams.
    \180\ E.g., Bonneville. Santee Cooper, and Entergy.
    \181\ E.g., PJM, EPSA, and Ameren.
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    284. TDU Systems and Sacramento express support for the 
Commission's proposal to require public utilities, working through 
NERC, to develop modeling assumptions for use in calculating ATC that 
are consistent with those used to plan the operation and expansion of 
the transmission system. Xcel, however, would have the Commission go 
further. Xcel recommends that the Commission enhance its proposal by 
establishing a date certain for transmission providers in the Western 
Interconnection to be required to account for impacts of loop flows 
when processing transmission service requests and calculating ATC. Xcel 
suggests that NERC be directed to develop standards for evaluation of 
counterflows on ATC. EPSA offers examples of specific data inputs that, 
in its view, should also be standardized among all transmission 
providers, which include: Load levels and distribution studies; 
transmission outages; generation outages; and generation dispatch. 
Ameren submits that any modeling of base generation dispatch must model 
generators, including merchant generators, as they are expected to run.
    285. Williams asks the Commission to require consistency between 
transmission planning horizon and procurement terms, and transparency 
around the long-term transmission planning assumptions. Williams states 
that third-party bids to a request for proposals are evaluated with 
transmission costs that may already be included in long-term 
transmission plans. Thus, argues Williams, procurement and long-term 
planning assumptions are intertwined. In reply, Entergy acknowledges 
and agrees that the models used for planning, operations and service 
request evaluations should generally be based on similar data and 
procedures, but argues that due to changes in system configuration, 
facilities included in transmission plans are often not needed at all 
and thus are not constructed. Therefore, Entergy proposes that the 
Commission allow NERC to determine the circumstances under which 
differences between models would be appropriate.
    286. Southern asks for clarification on what the Commission intends 
by proposing that modeling assumptions be consistent in the context of 
TTC assessments. Southern explains that, as the Commission has 
recognized, the inevitable changes in system conditions between 
different time horizons (e.g., real-time and planning and operations) 
would render this approach unreliable because load levels, dispatch 
arrangements, reservations, and outages cannot be the same over 
significantly different time horizons.
    287. Supporting regional differences, Bonneville contends that 
calculating ATC for a hydroelectric system requires different inputs 
and modeling assumptions than are appropriate for thermal-based 
systems. Bonneville explains that non-power constraints placed on 
hydroelectric projects that were built for multiple uses are a major 
concern on the Bonneville system. Consequently, hydro operators are 
more limited in their ability to use generation redispatch as a tool to 
meet long-term firm load obligations. Similarly, Santee Cooper cautions 
that over-standardization may result in certain parameters being 
misstated or inappropriately constrained, resulting in inaccurate 
reservations of capacity for native load purposes and a potentially 
detrimental effect on the reliability of service. It recommends that 
the Commission direct NERC to allow deviations from the standard 
modeling assumptions where the need can be supported, with the caveat 
that a utility's modeling assumptions must be transparent and available 
for scrutiny. Seattle contends that modeling assumptions should be 
developed at the sub-regional level, consistent among adjacent 
transmission providers. TVA suggests that the transmission providers be 
allowed to retain flexibility to conduct risk analyses and reflect 
those in their modeling assumptions.
    288. Other commenters argue that modeling assumption 
standardization should not be performed by NERC and, instead, should be 
delegated to the regional reliability organizations or RTOs, as they 
possess a superior knowledge of the physical grid within their 
boundaries.\182\ PJM states that such issues are best left to the joint 
stakeholder processes and the resulting joint and common market 
initiatives.
---------------------------------------------------------------------------

    \182\ E.g., Sacramento, Manitoba Hydro, Nevada Companies, and 
TANC.
---------------------------------------------------------------------------

    289. In response to the Commission's inquiry as to how 
standardizing the modeling assumptions and data would affect native 
load, commenters generally state that standardization of ATC modeling 
assumptions would increase comparability of service to LSEs and enhance 
the ATC methodology and its nondiscriminatory application to grid 
utilization.\183\
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    \183\ E.g., Sacramento.
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Commission Determination
    290. The Commission directs public utilities, working through NERC, 
to modify the reliability standards MOD-010 through MOD-025 \184\ to 
incorporate a requirement for the periodic review and modification of 
models for (1) Load flow base cases with contingency, subsystem, and 
monitoring files, (2) short circuit data, and (3) transient and dynamic 
stability simulation data, in order to ensure that they are up to date. 
This means that the models should be updated and benchmarked to actual 
events. We find that this requirement is essential in order to have an 
accurate simulation of the performance of the grid and from which to 
comparably calculate ATC, therefore increasing transparency and 
decreasing the potential for undue discrimination by transmission 
providers.
---------------------------------------------------------------------------

    \184\ The MOD-010 through MOD-025 reliability standards 
establish data requirements, reporting procedures, and system model 
development and validation for use in the reliability analysis of 
the interconnected transmission systems.
---------------------------------------------------------------------------

    291. We note that commenters generally were very supportive of the 
Commission's proposals for review and update of models and for 
consistency of assumptions and data inputs. We received no adverse 
comments concerning our general proposal to require public utilities, 
working through NERC, to modify the ATC-related standards to 
incorporate a requirement for the periodic review and modification of 
models to ensure that they are up to date. Moreover, the need to 
improve the quality of system modeling was one of the U.S.-Canada Power 
System Task Force recommendations.\185\
---------------------------------------------------------------------------

    \185\ Final Report on the August 14, 2003 Blackout in the United 
States and Canada: Causes and Recommendations.
---------------------------------------------------------------------------

    292. The Commission also adopts the NOPR proposal to require 
transmission providers to use data and modeling assumptions for the 
short- and long-term ATC calculations that are consistent with that 
used for the

[[Page 12305]]

planning of operations and system expansion, respectively, to the 
maximum extent practicable. This includes, for example: (1) Load 
levels, (2) generation dispatch, (3) transmission and generation 
facilities maintenance schedules, (4) contingency outages, (5) 
topology, (6) transmission reservations, (7) assumptions regarding 
transmission and generation facilities additions and retirements, and 
(8) counterflows. We find that requiring consistency in the data and 
modeling assumptions used for ATC calculations will remedy the 
potential for undue discrimination by eliminating discretion and 
ensuring comparability in the manner in which a transmission provider 
operates and plans its system to serve native load and the manner in 
which it calculates ATC for service to third parties. The Commission 
directs public utilities, working through NERC, to modify ATC standards 
to achieve this consistency.
    293. With regard to EPSA's request for the standardization of 
additional data inputs, we believe they are already captured in the 
Commission's proposal as adopted in this Final Rule. Xcel asks the 
Commission to require consistency in the determination of counterflows 
in the calculation of ATC. Counterflows are included in the list of 
assumptions that public utilities, working through NERC, are required 
to make consistent. We believe that counterflows, if treated 
inconsistently, can adversely affect reliability and competition, 
depending on how they are accounted for. Accordingly, we reiterate that 
public utilities, working through NERC and NAESB, are directed to 
develop an approach for accounting for counterflows, in the relevant 
ATC standards and business practices. We find unnecessary Xcel's 
request that we require a date certain for specific issues in the 
Western Interconnection to be addressed. Above we require public 
utilities, working through NERC, to modify the ATC standards within 270 
days after the publication of the Final Rule in the Federal Register.
    294. With regard to Williams' request that the Commission require 
consistency between transmission planning horizons and procurement 
terms, we believe that such an express requirement is neither 
appropriate nor necessary. The manner in which transmission providers 
procure power for native load customers is generally outside the scope 
of this rulemaking. This notwithstanding, we note that by this Final 
Rule, Williams and other affected market participants will have an 
opportunity to participate in a transmission provider's coordinated, 
regional planning process. This will provide a vehicle for interested 
parties to gain access to planning-related information and to have 
their own plans for transmission evaluated at the same time the 
transmission provider plans for its needs. Coupled with the 
modifications to the ATC-related reliability standards that require the 
same data and assumptions to be used for calculating long-term ATC as 
in system planning, these reforms are adequate to address Williams' 
concern. To the extent there are changes on the system, these should be 
captured in the regional transmission planning process and in the 
determination of ATC. We therefore reject Entergy's proposal to allow 
NERC to determine the circumstances under which differences between 
models would be appropriate in order to ensure comparable service for 
all transmission customers.
    295. We offer the following clarifications. In response to 
Southern, we clarify that we require consistent use of assumptions 
underlying operational planning for short-term ATC and expansion 
planning for long-term ATC calculation. We also clarify that there must 
be a consistent basis or approach to determining load levels. For 
example, one approach may be for transmission providers to calculate 
load levels using an on- and off-peak model for each month when 
evaluating yearly service requests and calculating yearly ATC. The same 
(peak- and off-peak) or alternative approaches may be used for monthly, 
weekly, daily and hourly ATC calculations. Regardless of the ultimate 
choice of approach, it is imperative that all transmission providers 
use the same approach to modeling load levels to enable the meaningful 
exchange of data among transmission providers. Accordingly, we direct 
public utilities, working through NERC, to develop consistent 
requirements for modeling load levels in MOD-001 for the services 
offered under the pro forma OATT.
    296. With respect to modeling of generation dispatch, we direct 
public utilities, working through NERC, to develop requirements in 
NERC's MOD-001 reliability standard specifying how transmission 
providers shall determine which generators should be modeled in 
service, including guidance on how independent generation should be 
considered. We agree with Ameren that any modeling of base generation 
dispatch must model generators, including merchant generators, as they 
are expected to run. Accordingly, we direct public utilities, working 
through NERC, to revise reliability standard MOD-001 by specifying that 
base generation dispatch will model (1) All designated network 
resources and other resources that are committed or have the legal 
obligation to run, as they are expected to run and (2) uncommitted 
resources that are deliverable within the control area, economically 
dispatched as necessary to meet balancing requirements.
    297. Regarding transmission reservations modeling, we direct public 
utilities, working through NERC, to develop requirements in reliability 
standard MOD-001 that specify (1) A consistent approach on how to 
simulate reservations from points of receipt to points of delivery when 
sources and sinks are unknown and (2) how to model existing 
reservations.
    298. In response to commenter requests in favor of flexibility and 
regional differences, we again require that any waivers from the 
approved NERC reliability standards must take place through the NERC 
reliability standards process as a request for regional difference. 
Also, we disagree with commenters who argue that modeling assumptions 
should be delegated to regional reliability organizations. The goal of 
this rulemaking is to increase consistency in ATC calculations and that 
is best accomplished through NERC, which has established processes to 
address requests for regional differences from the reliability standard 
requirements. We conclude that the NERC process is appropriate as it is 
open to all industry participants and, therefore, is a suitable arena 
for establishment of common standards for modeling assumptions.
g. ATC Calculation Frequency
NOPR Proposal
    299. The Commission proposed the development of standards requiring 
that the ATC calculation be performed with consistent frequency among 
transmission providers. Specifically, the Commission proposed that 
transmitting public utilities, working through NERC and NAESB, develop 
standards requiring that the calculation be performed by all 
transmission providers on a consistent time interval and in a manner 
that closely reflects the actual topology of the system, e.g., 
generation and transmission outages, load forecast, interchange 
schedules, transmission reservations, facility ratings, and other 
necessary data. The Commission also supported uniform updating of ATC 
values and its components (e.g., TTC, ETC, CBM, and TRM).
Comments
    300. Alcoa and Powerex emphasize the critical need for ATC to be 
calculated more frequently for

[[Page 12306]]

constrained facilities. On constrained paths, where transmission 
equipment is stressed to its limits, Alcoa recommends that ATC be 
calculated on an hourly or real-time basis and be adjusted for 
temperature extremes. Seattle comments that ATC should be updated on a 
``by exception'' basis, i.e., when significant model changes or 
confirmations of service requests occur. While supporting the 
Commission proposal, TAPS cautions against updating ATC/AFC too 
frequently, as this may play into the hands of those who use 
reservation computer programs.
Commission Determination
    301. The Commission adopts the NOPR proposal and requires the 
development of reliability standards that ensure ATC is calculated at 
consistent intervals among transmission providers. The Commission thus 
directs public utilities, working through NERC and NAESB, to revise 
reliability standard MOD-001 to require ATC to be recalculated by all 
transmission providers on a consistent time interval and in a manner 
that closely reflects the actual topology of the system, e.g., 
generation and transmission outages, load forecast, interchange 
schedules, transmission reservations, facility ratings, and other 
necessary data. This process must also consider whether ATC should be 
calculated more frequently for constrained facilities. ATC-related 
requirements for OASIS posting are discussed below.
h. Data Exchange
NOPR Proposal
    302. The Commission proposed the development through NERC of 
standard protocols that would enable and require the exchange of data 
and coordination among transmission providers. The Commission proposed 
that the following data, at a minimum, be exchanged among transmission 
providers for the purposes of ATC modeling: (1) Load levels; (2) 
transmission planned and contingency outages; (3) generation planned 
and contingency outages; (4) base generation dispatch; (5) existing 
transmission reservations, including counterflows; (6) ATC 
recalculation frequency and times; and (7) source/sink modeling 
identification. The Commission expressed its view that significant 
improvements in the communication, coordination, and exchange of data 
across all transmission providers in an interconnection are needed to 
produce accurate determinations of ATC. The Commission sought comment 
as to how much data sharing is workable, whether there are additional 
data that should be provided, whether access to such data should be 
limited to transmission providers, and if there are existing forums by 
which these or similar data are already shared.
Comments
    303. Most commenters support the Commission's proposal to establish 
rules for data exchange, but express a preference for confidential data 
exchange.\186\ NERC states that proposed changes to its existing 
modeling standards would require transmission providers to coordinate 
the calculation of TTC/ATC/AFC with others. TVA emphasizes that it has 
already incorporated these principles into its operating processes by 
executing agreements that provide for data exchange and coordination 
with neighboring transmission systems.
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    \186\ E.g., Allegheny, Ameren, Arkansas Municipal, Bonneville, 
Constellation, CAISO, Entergy, Exelon, FirstEnergy, LPPC, 
MidAmerican, Santee Cooper, Seattle, and TAPS.
---------------------------------------------------------------------------

    304. PJM suggests that the data exchange protocols be developed as 
minimum requirements and not interfere with existing protocols that PJM 
has with neighboring control areas under agreements such as the MISO/
PJM JOA.\187\ Similarly, SPP states that it also has developed seams 
coordination agreements with adjoining transmission providers \188\ 
that fully meet and, in some cases exceed, the Commission's objective 
of fostering greater data exchanges between transmission providers.
---------------------------------------------------------------------------

    \187\ Under the PJM/MISO Joint Operating Agreement (JOA) and 
other operating agreements modeled on that agreement, parties have 
developed comprehensive data exchange protocols to facilitate 
coordination and consistent AFC calculations. Much of this data is 
supplied through industry standard sources such as NERC SDX and NERC 
eTags.
    \188\ SPP has developed seams agreements to exchange ATC data 
and coordinate congestion with non-RTO neighbors such as the 
Southwest Power Administration. Further, SPP exchanges ATC/AFC data 
and coordinates planning, reserve sharing, outage coordination, and 
transmission service administration under a transmission 
coordination agreement with Associated Electric Cooperative, Inc. 
(AECI), an individual transmission provider situated on SPP's border 
that is not a member of SPP or any other RTO.
---------------------------------------------------------------------------

    305. MISO is concerned that the NOPR does not address transparency 
and regional coordination issues arising at the seams between RTO and 
non-RTO regions, particularly with respect to ATC calculations. In 
MISO's view, the Commission-approved joint operating agreements between 
various ISOs and RTOs contain cutting edge ATC calculation 
methodologies, while no comparable common protocols have evolved with 
non-RTO utilities. In its reply comments, Exelon agrees with MISO that 
the various joint operating agreements are not consistent. Exelon 
proposes that the NERC standards specify requirements for coordination 
and the type of data that must be exchanged and used for accurate ATC 
calculations. Exelon contends that having uniform standards for 
coordination developed by NERC will enhance efficiency throughout the 
industry, particularly between and among RTO and non-RTO areas. 
MidAmerican reiterates that ATC coordination remains an issue for RTOs 
and that any improvements in ATC coordination resulting from this 
proceeding must apply to the OATTs of RTOs and non-RTOs alike.
    306. NAESB states that coordination and data exchange may require 
business practices for existing transmission reservations, including 
counterflows, ATC calculation frequency, and source/sink modeling 
identification. Some commenters request that the Commission clarify 
that only information necessary for purposes of ATC modeling needs to 
be exchanged.\189\ In particular, they propose that proprietary 
generation or market information data that might harm their competitive 
position should not be publicly disseminated since that would not 
enhance the ability of transmission providers to accurately calculate 
ATC.
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    \189\ E.g., Allegheny, Constellation, and Indianapolis Power.
---------------------------------------------------------------------------

    307. While acknowledging these confidentiality and commercial 
sensitivity concerns, other commenters recommend that the availability 
of shared data not be limited to transmission providers.\190\ For 
example, TAPS explains that transmission dependent utilities need an 
opportunity to access the data periodically as a check on the process. 
To address confidentiality or standards of conduct concerns, TAPS 
proposes that transmission dependent utilities' access to data could be 
achieved through an employee barred from disclosing information to 
marketing staff or a third party independent consultant retained by the 
transmission dependent utility. However, APPA and Seattle urge the 
Commission to eliminate artificial and institutional barriers to the 
exchange of data and information.
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    \190\ E.g., APPA, Bonneville, TAPS, and Seattle.
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    308. APPA and Seattle also contend that, even if data were openly 
available, the vast quantities of hourly data points are difficult to 
manage, process and analyze using existing methods. To address this 
issue, APPA recommends

[[Page 12307]]

that the Commission encourage ongoing efforts to obtain greater 
resolution of system-model State variables, contractual uses and 
probabilistic ranges and to refine data management and analytical 
methods.
    309. New York Commission suggests having an overarching entity, 
such as a Transmission Oversight Center, that is responsible for 
calculating and coordinating ATC between various ISOs/RTOs could 
overcome this lack of data.
Commission Determination
    310. The Commission adopts the NOPR proposal and directs public 
utilities, working through NERC, to revise the related MOD reliability 
standards to require the exchange of data and coordination among 
transmission providers and, working through NAESB, to develop 
complementary business practices. The following data shall, at a 
minimum, be exchanged among transmission providers for the purposes of 
ATC modeling: (1) Load levels; (2) transmission planned and contingency 
outages; (3) generation planned and contingency outages; (4) base 
generation dispatch; (5) existing transmission reservations, including 
counterflows; (6) ATC recalculation frequency and times; and (7) 
source/sink modeling identification. The Commission concludes that the 
exchange of such data is necessary to support the reforms requiring 
consistency in the determination of ATC adopted in this Final Rule. As 
explained above, transmission providers are required to coordinate the 
calculation of TTC/TFC and ATC/AFC with others and this requires a 
standard means of exchanging data.
    311. While there is a near consensus among commenters that 
significant improvements in the communication, coordination, and 
exchange of data across all transmission providers are needed to 
produce accurate determinations of ATC, we acknowledge the concerns of 
ISO/RTOs that new data exchange protocols may interfere with the 
existing protocols and seams coordination agreements. Although we will 
not provide a blanket exemption for ISOs and RTOs from meeting or 
exceeding the data exchange requirements of this Final Rule, they may, 
as explained in section IV.C.2, demonstrate in relevant filings that 
their existing data exchange protocols are consistent with or superior 
to those that are developed in the NERC and NAESB processes.\191\
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    \191\ We are not requiring that every transmission provider 
follow identical protocols. Rather, all transmission providers must 
meet the relevant NERC reliability standards and NAESB business 
practices, and each entity will be subject to reliability standards 
compliance audits through which they will have to demonstrate that 
they meet or exceed the reliability standards.
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    312. With respect to concerns regarding the exchange of data that 
may be a subject of confidentiality and commercially sensitive, we only 
require information necessary for purposes of ATC modeling to be 
exchanged. As suggested by some commenters, proprietary generation or 
market information data that might harm a competitive position should 
not be publicly disseminated, since that would not enhance the ability 
of transmission providers to accurately calculate ATC. If any of the 
data are subject to confidentiality and are commercially sensitive, 
they must be disclosed in accordance with a confidentiality agreement.
2. Transparency
a. OATT Transparency
(1) Attachment C
NOPR Proposal
    313. In the NOPR, the Commission proposed to require each 
transmission provider to include in Attachment C of its OATT more 
descriptive information concerning its ATC/AFC calculation methodology. 
Specifically, the Commission proposed to require the transmission 
provider to state its specific mathematical algorithm used to calculate 
firm and non-firm ATC/AFC for its scheduling horizon, operating 
horizon, and planning horizon. The Commission also proposed to require 
transmission providers to provide a process flow diagram that 
illustrates the various steps through which ATC/AFC is calculated. In 
addition, the Commission proposed to require transmission providers to 
provide definitions and explain in detail how TTC, ETC, AFC, TRM, and 
CBM are calculated for both operating and planning horizons.
Comments
    314. Most commenters support the Commission's overall proposal on 
transparency in ATC calculations.\192\ Numerous commenters support the 
Commission's proposal to require detailed information in Attachment C 
regarding the transmission provider's ATC/AFC calculation 
methodology.\193\ Barrick agrees in its reply comments that a thorough 
explanation of how ATC is calculated should be made readily available 
either in the transmission provider's OATT or on its OASIS, thereby 
improving transparency and making it less difficult for customers to 
determine whether the calculations are unduly discriminatory. Old 
Dominion calls for greater transparency in the details of calculating 
ATC, even as applied to RTOs such as PJM because of the relevance of 
ATC at the borders of an RTO/ISO and the market impact of 
inconsistencies in definitions, data, modeling assumptions and 
frequency of ATC calculations. NERC states that the revised NERC 
reliability standards will address transparency.
---------------------------------------------------------------------------

    \192\ E.g., Alberta Intervenors, AWEA, Bonneville, CAISO, 
Constellation, Duke, East Texas Cooperatives, ELCON, Entergy, 
Entegra, EPSA, E.ON, Exelon, MidAmerican, Morgan Stanley, 
Municipals, Nevada Companies, NPPD, PGP, PJM, Powerex, CREPC, Santee 
Cooper, TVA, TAPS, and TDU Systems.
    \193\ E.g., Arkansas Municipal, Arkansas Commission, CAISO, 
Constellation, ELCON, Entergy, ISO New England, Morgan Stanley, 
NARUC, Nevada Companies, Occidental, PJM, Powerex, Project for 
Sustainable FERC Energy Policy, Santee Cooper, and Suez Energy NA.
---------------------------------------------------------------------------

    315. NARUC contends that understanding ATC calculation 
methodologies and having access to the underlying data is essential to 
a range of critical State commission functions and, therefore, greater 
transparency of ATC information will significantly enhance State 
commissions' abilities to fulfill their statutory obligations. On 
reply, North Carolina Agencies agree with NARUC and state that efforts 
aimed at increased transparency of ATC calculations should help uncover 
any actual discriminatory behavior by transmission providers, provide a 
clearer standard against which to evaluate claims of unduly 
discriminatory activities, and facilitate regional planning efforts. 
Entegra states on reply that transmission providers should be required 
to post narratives explaining changes in models and factors underlying 
ATC and AFC values, which would be invaluable to the Commission and 
customers in identifying problems that may warrant enforcement actions.
    316. While APPA generally supports the Commission's proposal, some 
of APPA's members along with other commenters express concern that 
including all the information might be too burdensome and result in 
numerous tariff changes.\194\ Some APPA members in the West also 
express concerns about the competitive implications of

[[Page 12308]]

providing such confidential and sensitive information.
---------------------------------------------------------------------------

    \194\ E.g., EEI, PNM-TNMP, Sacramento, Seattle, and Southern.
---------------------------------------------------------------------------

    317. EEI also notes that providing additional detailed information 
in Attachment C would be duplicative and may result in confusion due to 
inconsistencies between the wording of the NERC and NAESB ATC documents 
and each transmission provider's Attachment C. To avoid uncertainty, 
EEI recommends that the Commission require transmission providers to 
comply with the requirements of Attachment C by referencing NERC 
reliability standards or business practices that provide the 
information that is called for in the Attachment. MidAmerican believes 
that additional information concerning calculating ATC and its 
components would best be retained in the transmission provider's 
business practices rather than Attachment C. In its reply comments, 
Powerex suggests an alternative of permitting transmission providers to 
provide a general reference to NERC, WECC, or NAESB standards and fully 
outline core definitions, processes, data and assumptions when 
deviating from such standards.
    318. Southern contends that the transparency concerns expressed in 
the NOPR are driven more by the complexity and volume of the data 
involved rather than a lack of information. Southern suggests that 
sufficient information is readily available and the best course of 
action by the Commission would be to focus on documenting transfer 
capability methodologies available to transmission customers. NRECA 
replies that many commenters provided input into why more transparency 
is needed and repeats the example provided in its NOI comments of a 
cooperative that spent many months in discussions with a public utility 
transmission provider in an effort to understand ATC-related 
information posted on OASIS.
    319. Pinnacle contends that the Commission's proposal for detailed 
information in Attachment C is only relevant in flow-based systems, 
pointing out that in the Western Interconnection, the scheduling 
horizon, and the operating horizon are the same and thus reporting such 
information is not necessary. APPA and Bonneville believe that adding 
such detail in Attachment C may only result in incremental changes and 
suggest that better regional coordination would provide greater 
transparency.
    320. Though ISO New England believes this proposal would not create 
an undue burden, it urges the Commission to allow for variety in the 
illustration of the process flow diagram. Regarding the proposal to 
require a ``detailed explanation'' of the calculation of ATC, TTC, ETC, 
and TRM components, ISO New England argues that the relevant inputs can 
change on a daily basis because ATC for Pooled Transmission Facilities 
(PTF) in New England is a function of market conditions, as opposed to 
an administratively-derived calculation. In ISO New England's view, the 
level of detail required should reflect the operation of competitive 
markets. MISO is concerned that the NOPR does not address transparency 
and regional coordination issues arising at the seams between market 
and non-market areas, particularly with respect to ATC calculations.
    321. MidAmerican strongly urges the Commission to ensure that non-
public utility transmission providers adhere to the transparency 
requirements, since in the Pacific Northwest many of the ``backbone'' 
transmission lines are co-owned by jurisdictional and nonjurisdictional 
entities. A jurisdictional co-owner may be limited in its ability to 
determine such parameters as TRM and CBM because it may not be the line 
operator. LPPC, in its reply comments, believes it is unnecessary and 
redundant to require non-public utility transmission providers to adopt 
the ATC requirements of the pro forma OATT, because the Commission 
recognizes in the NOPR that NERC and NAESB are currently drafting 
standards for ATC, which when final will be filed with the Commission 
and become part of the ERO's mandatory reliability standards and fully 
applicable to otherwise nonjurisdictional entities.
    322. Suez Energy NA contends that it is essential that the 
Commission include an explanation of each component of the ATC 
calculation in Attachment C to ensure that the transmission provider 
incorporates NERC standards appropriately and to ensure proper 
enforcement in the event that an audit shows that the transmission 
provider has employed other methods of calculating ATC. Suez Energy NA 
also notes that the mathematical algorithms and process flow diagrams 
should be provided to users of the transmission system, independent 
monitors, transmission coordinators and regulators, even if a 
confidentiality agreement is required. APPA suggests that the 
Commission and regional reliability organizations conduct additional 
audits to ensure that these posted practices and procedures are in fact 
being followed, and that the data used are verifiable.
Commission Determination
    323. The Commission adopts the NOPR proposal to increase 
transparency regarding ATC calculations by requiring each transmission 
provider to set forth its ATC calculation methodology in its OATT. Each 
transmission provider must, at a minimum, include the following 
information in Attachment C to its OATT. It must clearly identify which 
of the NERC-approved methodologies it employs (e.g., contract path, 
network ATC, or network AFC). It also must provide a detailed 
description of the specific mathematical algorithm the transmission 
provider uses to calculate firm and non-firm ATC for the scheduling 
horizon (same day and real-time), operating horizon (day ahead and pre-
schedule), and planning horizon (beyond the operating horizon). In 
addition, transmission providers must include a process flow diagram 
that describes the various steps that it takes in performing the ATC 
calculation. Furthermore, transmission providers must set forth a 
definition of each ATC component (i.e., TTC, ETC, TRM, and CBM) and a 
detailed explanation of how each one is derived in both the operating 
and planning horizons. Requiring transmission providers to file a 
statement of their ATC calculation methodology along with a process 
flow diagram and more detailed definitions of ATC components in 
Attachment C of the OATT will provide greater transparency to 
transmission customers and assist in identifying any discrepancies that 
may arise in ATC determinations. These new requirements will assist in 
alleviating any appearance of discrimination in the determination of 
ATC.
    324. The Commission acknowledges NARUC's comments that 
understanding ATC methodologies and the underlying data also will 
enhance State regulators' ability to meet their regulatory obligations. 
More transparent ATC calculations are critical to coordinated regional 
transmission planning that ultimately will improve transmission access 
for customers and enhance grid reliability. Transparent ATC 
calculations facilitate the ability of market participants and 
regulators to detect discrimination.
    325. We do not believe our requirement to include additional 
information in Attachment C will be overly burdensome or lead to an 
excessive level of future tariff revisions. Attachment C must provide 
an accurate documentation of processes and procedures related to the 
calculation of ATC, not the actual mathematical algorithms themselves, 
which should be

[[Page 12309]]

posted on the transmission provider's Web site. These processes define 
service availability and, as such, must be part of the transmission 
provider's OATT. It is entirely appropriate that, because revisions to 
such processes impact transmission availability, they should be filed 
for Commission approval and included in a transmission provider's OATT. 
We also require transmission providers to file a revised Attachment C 
to incorporate any changes in NERC's and NAESB's revised reliability 
standards and business practices related to ATC calculations, as 
requested by the Commission in this Final Rule. This filing should be 
made within 60 days of completion of the NERC and NAESB processes. As 
we expect transmission providers to rarely change their ATC calculation 
methodologies, we do not believe this requirement will trigger an 
unacceptable level of tariff filings modifying the Attachment C 
description of the ATC components and processes.
    326. We agree with ISO New England that the process flow diagram 
requirement may be met with a variety of illustrations, so long as it 
is of sufficient detail to provide the transmission customer with a 
reasonable understanding of the transmission provider's ATC calculation 
processes. The process flow diagram should support the other Attachment 
C requirements. As noted above, we agree with Suez Energy NA that 
mathematical algorithms and process flow diagrams should be made 
available. We do not find that a confidentiality agreement is 
generically warranted; however, we note that, a transmission provider 
may require a confidentiality agreement for CEII materials, consistent 
with our CEII requirements, or may otherwise protect the 
confidentiality of proprietary customer information.
    327. We also require transmission providers to document their 
processes for coordinating ATC calculations with their neighboring 
systems. This requirement is particularly important with respect to 
seams between market and non-market areas, as identified by MISO, and 
with respect to the request of other commenters to increase regional 
coordination regarding ATC calculation. While this Final Rule does not 
address all seams issues between market and non-market areas, it does 
take important steps towards that end by improving data exchange 
between transmission providers and providing increased transparency 
with respect to ATC calculation.
    328. We reject proposals to address the transparency of ATC 
methodology by merely referencing business practices and reliability 
standards developed by NERC, NAESB, and WECC.\195\ ATC calculations 
have a direct and tangible effect on the granting of open access 
transmission service.\196\ As such, an accurate and detailed statement 
of the methodology and its components that defines how the transmission 
provider determines ATC belongs in the transmission provider's OATT as 
the means of holding the transmission provider accountable for 
following non-discriminatory procedures for granting service, not in 
business practices kept by the transmission provider.\197\ However, as 
noted above, the actual mathematical algorithms should be posted on the 
transmission provider's web site, with the link noted in the 
transmission provider's Attachment C.
---------------------------------------------------------------------------

    \195\ WECC has on file a Reliability Management System agreement 
under which transmission providers agreed, through contracts, to 
follow WSCC reliability criteria. Western Systems Coordinating 
Council, 87 FERC ] 61,060 (1999).
    \196\ The Commission recognized in Order No. 889 that the 
methodology for calculating ATC and TTC belongs in the tariff. Order 
No. 889 at 31,607. At the time, the industry represented that it was 
engaged in efforts to develop uniform methods of determining ATC. 
The Commission encouraged such industry efforts and required that 
the tariff include the methodology, which was to be based on current 
industry practices, standards and criteria.
    \197\ For the same reason, the Commission disagrees with the 
assertions of Southern and EEI that more information in Attachment C 
would be duplicative because some ATC-related information is already 
available elsewhere.
---------------------------------------------------------------------------

    329. We also reject Pinnacle's assertion that more detailed 
information in Attachment C would only apply to flow-based systems. 
Regardless of what type of ATC calculation methodology is employed, 
transparency in ATC calculations is critical to avoid undue 
discrimination when allocating transmission capacity under the pro 
forma OATT.
    330. In response to MidAmerican's comments regarding the 
applicability of the ATC-related reforms to non-public utilities, we 
again refer to section IV.C.3 where we discuss this issue generally. We 
note here, however, that the ERO's reliability standards currently in 
development before the Commission will be applicable to all users, 
owners and operators of the bulk electric grid, which includes non-
public utilities.
    331. We do not believe ATC-specific tariff audits are necessary to 
order at this time. The Commission will continue to provide oversight 
of all tariff-related activities through its enforcement program. 
Moreover, ATC requirements will be part of the mandatory and 
enforceable reliability standards and, as such, will be subject to 
compliance audits through that process.
(2) CBM Practices
NOPR Proposal
    332. In the CBM Order, the Commission required transmission 
providers to post a specific narrative explanation of their CBM 
practices.\198\ In addition, the Commission directed transmission 
providers to post their procedures for allowing access to CBM during 
emergencies. The Commission further stated in the CBM Order that, if a 
utility's practice was not to set aside transfer capability as CBM, it 
should reflect that in Attachment C.
---------------------------------------------------------------------------

    \198\ Capacity Benefit Margin in Computing Available 
Transmission Capacity, 88 FERC ] 61,099 (1999) (CBM Order).
---------------------------------------------------------------------------

    333. In the NOPR, the Commission proposed to require transmission 
providers to include this CBM narrative in Attachment C of their OATTs. 
In addition, the Commission proposed that transmission providers 
explain their definition of CBM, list the databases used in their CBM 
calculations, and prove that there is no double-counting of contingency 
outages when performing CBM calculations.
Comments
    334. Seattle and Suez Energy NA support this proposal. Seattle 
states that CBM information should be specified in Attachment C in 
order to provide clear guidance for the specific information that is 
posted on OASIS. Seattle and APPA suggest that CBM should be verifiable 
and subject to audit by independent parties such as regional 
reliability organizations.
    335. EEI suggests that the Commission revise Attachment C, section 
3(f) to replace the word ``prove'' with the word ``demonstrate'' in the 
requirement that the transmission provider ``prove'' that it does not 
double count contingency outages when calculating CBM, TTC and TRM. EEI 
notes that the term ``prove'' implies a determination on the merits 
after evaluation of competing arguments and evidence. A transmission 
provider should be able to satisfy its obligations by ``demonstrating'' 
the absence of a double count. Any customer that wishes to challenge 
the demonstration can do so, at which time the issue of ``proof'' would 
arise.
    336. With regards to ``double counting,'' TVA references TRM and 
agrees that additional explanations regarding the calculation of TRM, 
including methods used to avoid double counting contingency events, 
should improve transparency in providing open access transmission 
service. TVA points out that this is being addressed by a NERC 
standards drafting team.

[[Page 12310]]

Commission Determination
    337. The Commission adopts the NOPR proposal requiring additional 
information in the transmission provider's OATT Attachment C regarding 
its determination of CBM. Transmission providers must provide in 
Attachment C a narrative description detailing their CBM practices. In 
addition, a transmission provider must explain its definition of CBM 
and list the databases used to derive its value. These new requirements 
will provide transmission customers transparency into the CBM component 
of ATC and help discourage the potential for undue discrimination in 
the calculation and use of CBM.
    338. We adopt EEI's proposal that the Commission revise Attachment 
C, section 3(f) to replace the word ``prove'' with the word 
``demonstrate.'' The word ``demonstrate'' more accurately describes the 
showing we expect the transmission provider to make. We agree that the 
word ``prove'' implies a standard of proof that we did not intend to 
impose. We also acknowledge TVA's comments that the NERC standards 
drafting team is developing standards that should address ``double 
counting'' in ATC calculations in general. However, we require that the 
information in Attachment C be sufficient to demonstrate that a 
transmission provider is not double counting CBM in its ATC 
calculation.
    339. Finally, the Commission rejects the proposal by Suez Energy 
NA, APPA, and Seattle to establish formal audits of CBM set asides. 
Requirements for CBM will be part of the mandatory and enforceable 
reliability standards and, as such, will be subject to compliance 
audits through that process. Moreover, the Commission provides 
oversight of all tariff-related activities through its enforcement 
program.
b. OASIS
(1) ATC/TTC Posting Requirements
NOPR Proposal
    340. The Commission's existing regulations require certain ATC-
related information to be posted on each transmission provider's OASIS 
and other information to be provided on request. To ensure that 
relevant information is available on a timely basis to all market 
participants, the Commission proposed in the NOPR to amend its 
regulations to allow potential customers greater access to information 
that will enable them to obtain service on a non-discriminatory basis 
from any transmission provider.
    341. The Commission noted in the NOPR that existing regulations 
require ATC and TTC calculations to be performed according to 
consistently applied methodologies referenced in the transmission 
provider's OATT and current industry practices, standards and criteria. 
The Commission proposed that these calculations be based on the ERO 
reliability standards.
    342. The Commission further proposed to maintain the requirement 
that transmission providers provide, on request, all data used to 
calculate ATC and TTC for any constrained paths. Transmission providers 
also would remain required, on request, to make publicly available any 
system planning studies or specific network impact studies performed 
for customers and to post a list of such studies on OASIS.
Comments
    343. Several commenters support the proposal to post ATC-related 
information on OASIS.\199\ TDU Systems supports each of the 
Commission's proposals with respect to providing easier access to data 
underlying ATC calculations and greater transparency to the process. 
Sacramento states that posting on OASIS will ensure proper public 
access, but will avoid the need for Commission approval of an OATT 
change.
---------------------------------------------------------------------------

    \199\ E.g., APPA, Constellation, FirstEnergy, Indianapolis 
Power, Sacramento, Suez Energy NA, TAPS, and TDU Systems.
---------------------------------------------------------------------------

    344. Constellation strongly supports the need for additional 
transparency, stating that providing transmission customers with 
meaningful insight into the current ``black box'' determination of ATC 
will help minimize the mystery underlying many transmission provider 
responses to service requests. According to Constellation, further 
transparency will assist customers in predicting the outcome of 
transmission service requests and facilitate increased commercial 
activity. Constellation suggests that the Commission require 
transmission providers to provide transmission customers, on request, 
with specific details related to modeling data, modeling support 
information, modeling benchmarking and forecasting data, and 
transmission service request audit data. It requests that the 
information be in a form and format usable by the transmission 
customers and that the Commission take steps to ensure that 
transmission customers understand how ATC is calculated and the data 
inputs are used to affect those calculations.
    345. Great Northern likewise requests that the Commission enhance 
the requirement to provide all data on request, specifically on 
constrained paths, by requiring a posted tabulation of annual and 
monthly ATC calculation details. Great Northern suggests including TTC, 
network load for each transmission customer, capacity reserved for each 
network resource, each point-to-point transmission service reservation, 
CBM and other deductions from TTC.
    346. APPA members support the posting of ATC information, as it 
will assist in using ATC more efficiently, and they support the posting 
of system planning studies and specific network impact studies that the 
transmission provider performs for its own merchant function, as well 
as studies performed for customers. In addition, APPA suggests the 
posting of facilities studies at the time they become available, 
assuming that this can be done consistent with CEII concerns. TAPS goes 
further by urging the Commission to close gaps in the current OASIS 
requirements by requiring posting of all studies performed for 
transmission owners' own transmission network resource designations and 
other uses of the system, including facilities studies as well as 
system impact studies, ensuring posted study lists are updated 
contemporaneously with the availability of new studies, and requiring 
retention of studies for a minimum of five years.
    347. Nevada Companies and TVA support cost effective measures that 
increase transparency in transmission operations and, unless the 
requirement becomes unduly time consuming or burdensome, in general 
support more disclosure rather than less.
Commission Determination
    348. The Commission adopts the proposal in the NOPR to continue to 
require transmission providers to comply with existing ATC-related 
posting obligations as supplemented by this Final Rule. The Commission 
will continue to require transmission providers, on request, to make 
available all data used to calculate ATC and TTC for any constrained 
paths and any system planning studies or specific network impact 
studies performed for customers. Transmission providers must also 
continue to post a list of such studies on OASIS.
    349. In addition, we agree with the requests of APPA and TAPS to 
require the additional posting of, at a minimum, a listing of all 
system impact studies, facilities studies, and studies performed for 
the transmission provider's own network resources and affiliated 
transmission customers, to be made available upon request. We note that 
appropriate procedures to accommodate CEII concerns should be developed 
to

[[Page 12311]]

ensure eligible entities with a legitimate interest in transmission 
study data can receive access to it. Also, we adopt TAPS' suggestion 
that the studies be made available for five years to make the 
requirement consistent with data retention requirements pertaining to 
denial of service requests.
    350. The Commission rejects Constellation's and Great Northern's 
proposals to require transmission providers to provide upon request or 
regularly post additional information beyond that required in the 
regulations and this Final Rule. The transmission provider is already 
required to make available, upon request and in electronic format, all 
information related to the calculation of ATC and TTC for any 
constrained path. Accordingly, we see little benefit to require 
transmission providers to provide upon request or regularly post 
additional information suggested by these commenters.
(2) CBM/TRM Posting Requirements
NOPR Proposal
    351. The Commission's OASIS regulations currently require 
transmission providers to calculate and post ATC and TTC for each 
posted path, but make no requirement for CBM and TRM postings. In the 
CBM Order, however, the Commission required transmission providers, 
with respect to each path for which the utility already posts ATC, to 
post (and update) the CBM figure for that path. The Commission also 
required transmission providers to make any transfer capability set 
aside for CBM available on a non-firm basis and to post this 
availability on OASIS. In the NOPR, the Commission proposed to 
incorporate these CBM posting requirements into its regulations. The 
Commission also proposed that transmission providers post (and update) 
the TRM values for the paths on which the transmission provider already 
posts ATC, TTC, and CBM.
Comments
    352. Several commenters strongly support the Commission's proposal 
to require transmission providers to post TRM and CBM.\200\ APPA and 
EPSA agree that the posting of TRM for near term transmission services 
would provide greater assurance that ATC calculations are being 
performed according to established procedures. Since transmission 
providers already have this information, FirstEnergy states that it 
does not appear to be unduly burdensome for them to post such 
information. Bonneville indicates that it currently posts TRM values in 
its Business Practices Forum, which is useful for examining curtailment 
events, supporting transmission planning objectives, and validating 
posted ATC values.
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    \200\ E.g., Powerex, PJM, PPL, Seattle, and Pinnacle.
---------------------------------------------------------------------------

    353. EPSA also recommends that the Commission provide guidance on 
standards that should be developed to require each transmission 
provider to notify the Commission in writing and post a notice on its 
OASIS within 24 hours of a transmission provider's use of CBM to import 
emergency power. EPSA also requests that the amount of CBM reserved for 
each interface be posted on OASIS.
Commission Determination
    354. The Commission adopts the CBM posting requirements proposed in 
the NOPR. In doing so, we amend our OASIS regulations to incorporate 
the directives established in the CBM Order. Accordingly, we require 
transmission providers to post (and update) the CBM amount for each 
path. In addition, the Commission requires transmission providers to 
make any transfer capability set aside for CBM but unused for such 
purpose available on a non-firm basis and to post this availability on 
OASIS. Furthermore, the Commission requires transmission providers to 
post (and update) the TRM values for the paths on which the 
transmission provider already posts ATC, TTC, and CBM.
    355. We reject EPSA's request to require transmission providers to 
notify the Commission in writing and post a notice on OASIS within 24 
hours of a transmission provider's use of CBM to import emergency power 
and transfer capability set aside as CBM at each of the transmission 
provider's interfaces. The additional transparency of CBM-related 
information provided in this Final Rule, along with the reforms related 
to consistency of CBM, will cause sufficient information to be made 
available to customers concerning the use of CBM. The use and 
allocation of CBM and TRM will be more transparent to transmission 
customers, thus reducing the potential for undue discrimination.
(3) Periodic Reevaluation of the CBM Set-Aside
NOPR Proposal
    356. In the CBM Order, the Commission stated that the level of ATC 
set aside for CBM can and should be reevaluated periodically to take 
into account more certain information (such as assumptions that may not 
have, in fact, materialized).\201\ The Commission therefore directed 
transmission providers to periodically reevaluate their generation 
reliability needs so as to make known the availability of CBM and to 
post on OASIS their practices in this regard.\202\ In the NOPR, the 
Commission proposed to incorporate these requirements in the 
Commission's regulations and to obligate transmission providers to 
reevaluate the CBM set-aside at least quarterly.
---------------------------------------------------------------------------

    \201\ CBM Order at 61,237.
    \202\ Id.
---------------------------------------------------------------------------

Comments
    357. Some commenters support quarterly reevaluation of CBM set-
asides.\203\ TAPS agrees with the need for full transparency of CBM 
reservations and practices and states that, because CBM values may 
differ from season to season, CBM values should be separately 
calculated for at least each quarter. However, TAPS does not find that 
it is necessary or appropriate for the CBM values to be reevaluated 
quarterly, given the effort involved in collecting the data and 
performing the modeling analysis. Rather, CBM studies should be 
performed at least every other year, supplemented with ``off-year 
studies'' when appropriate.
---------------------------------------------------------------------------

    \203\ E.g., EPSA, Sacremento, Santa Clara, Suez Energy NA, and 
TDU Systems.
---------------------------------------------------------------------------

Commission Determination
    358. The Commission incorporates into its regulations the 
requirement in the CBM Order for a transmission provider to 
periodically reevaluate its transfer capability set-aside for CBM. With 
respect to TAPS' concerns over the effort involved in the re-evaluation 
process, we will require CBM studies to be performed at least every 
year. This requirement is consistent with the CBM Order, in which the 
Commission stated that the level of ATC set aside for CBM should be 
reevaluated periodically to take into account more certain information 
(such as assumptions that may not have, in fact, materialized).\204\ 
While changes requiring a reevaluation of CBM are longer-term in nature 
(e.g., installation of a new generator or a long-term outage), 
quarterly may be too frequent, though two years may be too long and may 
prevent a portion of the CBM set-aside from being released as ATC. 
Moreover, annual reevaluation is consistent with the current NERC 
standard being developed in MOD-005.\205\ The requirement to evaluate 
CBM at least every year also is consistent with the CBM Order in that

[[Page 12312]]

the Commission directed transmission providers to periodically 
reevaluate their generation reliability needs so as to make known the 
need for CBM and to post on OASIS their practices in this regard.
---------------------------------------------------------------------------

    \204\ CBM Order at 61,237.
    \205\ The MOD-005 reliability standard establishes the procedure 
for verifying CBM values.
---------------------------------------------------------------------------

(4) ATC/TTC Narrative Explanation
NOPR Proposal
    359. In the NOPR, the Commission proposed to largely retain 
existing posting requirements for unconstrained posted paths, but to 
amend the regulations relating to data posted for constrained posted 
paths. Existing regulations require ATC and TTC on constrained paths to 
be updated when (1) Transactions are reserved, (2) service ends, or (3) 
whenever the TTC estimate for the path changes by more than 10 
percent.\206\ In the NOPR, the Commission proposed to supplement the 
existing regulations by requiring the transmission provider to post a 
brief, but specific, narrative explanation of the reason for the change 
at the time a change in monthly and yearly ATC values on a constrained 
path is posted. The Commission sought comment on whether the posting of 
this new information would provide adequate transparency to the 
customer on a frequent enough basis without imposing an undue burden on 
the transmission provider. The Commission also sought comment on 
whether a similar narrative should be required when ATC remains 
unchanged at a value of zero for some specified period of time.
---------------------------------------------------------------------------

    \206\ See 18 CFR 37.6(b)(3)(i)(C).
---------------------------------------------------------------------------

Comments
    360. Some commenters support the Commission's proposal to require 
transmission providers to post more detailed explanations about changes 
in ATC values on their OASIS sites.\207\ NAESB, TranServ, and Williams 
request that the Commission clarify the regulatory requirements for 
posting of updated ATC values such as the level of standardization, 
frequency and time of postings, and other requirements. CAISO believes 
that ATC should be updated on a daily basis.
---------------------------------------------------------------------------

    \207\ E.g., Arkansas Commission, CAISO, Constellation, East 
Texas Cooperatives, Exelon, FirstEnergy, LPPC, Morgan Stanley, 
NRECA, Pinnacle, Powerex, Santa Clara, and Suez Energy NA.
---------------------------------------------------------------------------

    361. Powerex and Nevada Companies propose that additional 
disclosures be posted, such as data on grandfathered contracts, time-
specific data relevant to transmission constraints and ATC rights on 
posted paths, and remaining customer rights under a reservation-based 
network service system.
    362. A few commenters caution that some of the data that the 
Commission is requiring to be posted by transmission providers is 
market-sensitive and, if posted on a real-time basis, could be used by 
third parties to obtain an unfair competitive advantage.\208\ These 
commenters propose that the transmission providers should be allowed a 
brief period of delay (e.g., one week) before posting data. 
Indianapolis Power also advocates a delay due to the burden on 
transmission providers of the new posting.
---------------------------------------------------------------------------

    \208\ E.g., Ameren, ISO New England, Southern, and NRECA.
---------------------------------------------------------------------------

    363. Several commenters oppose the Commission's proposal to require 
that transmission providers post narratives on OASIS outlining reasons 
why monthly and yearly ATC values on constrained paths change.\209\ 
These commenters contend that this will cause undue burden on 
transmission providers without providing customers with any significant 
or new information. They also argue that the proposal is impractical 
and will not result in providing transmission customers with meaningful 
information regarding transmission service options.
---------------------------------------------------------------------------

    \209\ E.g., Ameren, EEI, Entergy, MISO, Pinnacle, PJM, PNM-TNMP, 
Southern, TranServ, and TVA.
---------------------------------------------------------------------------

    364. If such a requirement is adopted, MISO recommends that a 
threshold higher than a 10 percent change in ATC be established and 
that the Commission clarify what the term ``specific explanation'' 
means in this context. PJM states that it already exceeds the 
Commission's proposed requirement. However, if strictly applied, this 
proposal would be unduly burdensome on PJM because it would require PJM 
to post a narrative each hour. PJM asks that the Commission not apply 
unnecessary and costly posting requirements on independent RTOs and 
ISOs.
    365. EEI and Southern are concerned that monthly ATC may change in 
response to every reservation of hourly transmission service because a 
reservation of hourly firm service on a constrained path may reduce the 
availability of monthly firm service. EEI contends that, if 
transmission providers are required to post changes in TTC instead of 
ATC, they would not be required to post a new narrative every time a 
reservation is made, thus reducing the overall burden on transmission 
providers. EEI additionally states that the reasons for changes in TTC 
and ATC values often are complex and involve the interaction of 
multiple variables in the model that produces the TTC and ATC values 
and a specific change in TTC or ATC cannot easily be traced to a 
specific change in the inputs. Alternatively, EEI suggests that 
transmission providers could post the major changes in the inputs to 
the TTC modeling software that are made in connection with each updated 
TTC posting without ascribing specific inputs to specific changes in 
TTC and ATC values on specific lines.
    366. Several commenters are supportive of the proposed requirement 
that transmission providers provide a narrative explanation when ATC 
values remain at zero.\210\ APPA suggests that if a particular 
interface shows an ATC of zero for a specified period, the transmission 
provider should provide a narrative explanation of why this is the case 
and how its plans to address this problem. It also suggests that this 
information should be employed in the transmission planning process. 
East Texas Cooperatives, in reply comments, state that the narrative 
can provide useful information to the transmission customers and State 
and Federal regulators regarding specific conditions regarding ATC 
coordination.
---------------------------------------------------------------------------

    \210\ E.g., APPA, East Texas Cooperatives, Suez Energy NA, and 
TAPS.
---------------------------------------------------------------------------

    367. In supplemental comments, NAESB states that the Commission 
should specify whether it is sufficient for the explanation of changes 
in ATC or TTC values to be limited to broad generalized statements or 
whether the posted information should include such information as the 
specific events which gave rise to the change, the new values for ATC 
at all points on the network, the impact of the change on transmission 
customers, and a detailed snapshot of the conditions on the system at 
all flowgates or constrained elements when the change occurred.\211\
---------------------------------------------------------------------------

    \211\ November 2, 2006, Addendum to the Testimony of Ronald M. 
Mucci on behalf of the North American Energy Standards Board, 
Preventing Undue Discrimination and Preference in Transmission 
Service, Docket Nos. RM05-25-000 and RM05-17-000, October 12 
Technical Conference, pp. 2-3.
---------------------------------------------------------------------------

    368. Southern states that posting a narrative when ATC remains at 
zero is unwarranted and unnecessary, as it simply indicates that the 
market has responded to market signals of ATC availability and 
purchased all available capacity.
Commission Determination
    369. The Commission adopts the NOPR proposal, with the 
modifications discussed below, to require that the transmission 
provider post a brief, but specific, narrative explanation of the 
reason for a change in monthly and yearly ATC values on a constrained 
path. Rather than requiring a narrative

[[Page 12313]]

when a monthly or yearly ATC value changes as a result of transactions 
being reserved, service ending, or the TTC estimate for the path 
changing by more than 10 percent, we will require a narrative when a 
monthly or yearly ATC value changes only as a result of a 10 percent 
change in TTC. This will reduce the number of ATC changes for which a 
narrative will be required and address concerns that the new 
requirement unduly burdens transmission providers. Any remaining burden 
is justified by the benefit to transmission customers of receiving 
timely information regarding changes in TTC that result in changes to 
ATC. In addition, we adopt NAESB's suggestion that posted information 
include the (1) Specific events which gave rise to the change and (2) 
new values for ATC on that path (as opposed to all points on the 
network).
    370. We reject calls for delays prior to posting data. While 
commenters allege the possibility of granting others a competitive 
advantage through the release of ``market-sensitive'' data, they have 
proffered no evidence to support the allegation of potential harm.
    371. We do require, as suggested in the NOPR, a narrative with 
regard to monthly or yearly ATC values when ATC remains unchanged at a 
value of zero for a significant period, and will set that period at six 
months or longer. This information will be valuable to customers and 
regulators in assessing the ability of a transmission provider's 
facilities to meet existing service requests. The information also will 
provide assurance to customers that the transmission provider is 
diligent in regularly evaluating ATC on all paths, monitoring 
persistent constraints and addressing them in its planning processes.
    372. Finally, we reject CAISO's suggestion that ATC be updated 
daily on a transmission provider's OASIS site, because CAISO offered no 
justification for the proposal.
(5) Denial of Service/Records Retention
NOPR Proposal
    373. In the NOPR, the Commission proposed to maintain the 
requirement that a transmission provider post the reason for a denial 
of a request for service. The Commission also proposed to amend this 
provision to require a transmission provider to maintain and make 
available information supporting the reason for the denial. The 
Commission further proposed to extend the time period for which 
transmission providers must maintain transmission service information 
for audit. Currently, regulations require that audit data be retained 
and made available upon request for download for three years from the 
date when they are first posted. The Commission proposed to change the 
period from three to five years.
Comments
    374. Many commenters support posting of the reasons for denying 
service and the 5-year retention proposal.\212\ TAPS supports the 
proposal but suggests several modifications. First, it suggests that 
the Commission clarify the requirement to post the reasons for denying 
service is triggered not only by denial of the entirety of a 
transmission request, but to any disposition that falls short of a full 
unconditional grant of the service (with rollover rights if 
applicable). Second, TAPS recommends that the regulatory text of 
proposed section 37.6(e)(2)(ii) be modified to make the supporting data 
available, upon request, to any eligible customer rather than just to 
the customers who were denied service. Third, it asks that the 
Commission expand its OASIS regulations to require the transmission 
provider to maintain and make available on request the information 
supporting the disposition (positive, negative, or in between) of its 
own network resource designations and other usage needs. East Texas 
Cooperatives suggest that the Commission also require that transmission 
providers distinguish between denials of requests for firm and non-firm 
transmission service.
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    \212\ E.g., APPA, Arkansas Commission, Arkansas Municipal, Duke, 
East Texas Cooperatives, MISO, ISO New England, Williams, Nevada 
Companies, PPL, Sacremento, Sant Clara, Suez Energy NA, and TDU 
Systems.
---------------------------------------------------------------------------

    375. Some commenters urge the Commission to clearly define the 
scope of any transmission service request information subject to the 
proposed five-year record retention requirement to ensure that no undue 
administrative burden is placed on transmission providers.\213\ TVA 
questions the need to extend the time period for an additional two 
years. TVA states that the benefits of extension are not commensurate 
with the increased costs, since it is unaware of any problems that have 
arisen with the current three-year timeline. Seattle argues on reply 
that the Commission should retain the NOPR posting requirements in the 
Final Rule because information on actual transmission congestion can be 
helpful instead of sole reliance on simulation models.
---------------------------------------------------------------------------

    \213\ E.g., MidAmerican, PacifiCorp, PNM-TNMP, and PJM.
---------------------------------------------------------------------------

Commission Determination
    376. As proposed in the NOPR, the Commission maintains the 
requirement that a transmission provider post the reason for a denial 
of service and extends from three years to five years the period for 
which transmission providers must maintain data providing reasons for 
denial of service. In general, commenters support the requirement for 
posting denial of service information and the increase in retention 
time to five years, indicating that such information can be helpful to 
customers in their awareness of actual transmission congestion, rather 
than relying on simulation models.
    377. We also adopt TAPS' suggestion to expand the regulations to 
include availability of information supporting the disposition of a 
transmission provider's own network resource designations and to make 
such information available to any eligible customer rather than just to 
that customer denied service. In addition, we clarify that a partial 
denial of service triggers the requirements as well. Such information 
is consistent with the new regulations established by this Final Rule 
and will help ensure that customers receive transmission service that 
is not unduly discriminatory. The development of a log of service 
denials, full or partial, will establish an ongoing record of service 
requests and transmission provider responses demonstrating the 
transmission provider's provision of nondiscriminatory open access 
service. Furthermore, repeated denials of service over a particular 
path or flowgate will provide an indication of congestion that can be 
used in the transmission planning process. In addition, we agree with 
East Texas Cooperatives that postings of denials of service should 
indicate whether the requested service was firm or non-firm.
(6) Designation and Termination of Network Resources
NOPR Proposal
    378. In the NOPR, the Commission proposed to require the 
transmission provider and network customers to use the transmission 
provider's OASIS to request designation of a new network resource and 
to terminate the designation of a network resource. This information 
would be posted on OASIS for 90 days and be available for audit for a 
five-year period. Transmission customers therefore would be able to 
query such requests to designate and

[[Page 12314]]

terminate a network resource.\214\ The Commission also proposed to 
require the transmission provider to post on its OASIS a list of its 
current designated network resources and all network customers' current 
designated network resources. The list would include the resource name, 
geographic and electrical location and amount of capacity of the 
designated network resource.
---------------------------------------------------------------------------

    \214\ See 18 CFR 37.6(a)(6).
---------------------------------------------------------------------------

Comments
    379. Several commenters support the Commission's proposal to 
require transmission providers and network customers to use the 
transmission provider's OASIS to request or terminate designation of 
resources, though some indicated that the required network resource 
information is currently available via OASIS.\215\ PJM supports the 
proposal, provided that the electrical location is based on an industry 
standard format and any standard adopted by NERC takes into 
consideration possible confidentiality issues when posting the 
geographic location of designated network resources.
---------------------------------------------------------------------------

    \215\ E.g., APPA, Exelon, PJM, TAPS, TranServ, and TDU Systems.
---------------------------------------------------------------------------

    380. APPA suggests that reservations related to future load growth 
also should be posted so that it is clear to all industry participants 
what transmission capacity transmission providers are reserving for 
load growth purposes. Williams submits that the list of current 
designated resources needs to indicate whether they are for native load 
or network customers, or whether they are for meeting forecasted loads 
and system emergencies.
    381. TranServ supports the Commission's proposal and indicates that 
NAESB is the appropriate forum for development of standards necessary 
to support posting the designation and termination of network 
resources. TranServ cautions that implementation will require a 
sufficient period of time after the practices and standards are 
developed and suggests that changes to OASIS should be timed to avoid 
peak summer and winter seasons.
    382. Exelon requests that the Commission clarify that transmission 
providers and network customers making firm off-system sales may 
terminate designation of network resources solely for the term of such 
sale and not for other periods of time. During this period of 
termination, the firm capacity is posted and made available to other 
customers.
    383. Great Northern supports the proposal and requests 
clarification that, when a network resource is ``undesignated,'' ATC 
will not be set aside in anticipation that it might be designated again 
as a network resource in the future. Great Northern requests that the 
Commission confirm that new requests to designate network resources, 
regardless of the prior designation of those resources, are placed at 
the end of the transmission service queue.
    384. Sacramento states that the posting requirements for network 
resources are an unnecessary burden and instead recommends that the 
transmission provider should be required to identify resources it is 
transmitting to native load when it denies a request for transmission 
service from a third party.
Commission Determination
    385. The Commission adopts the NOPR proposal and requires 
transmission providers and network customers to use OASIS to request 
designation of new network resources and to terminate designation of 
network resources.\216\ This information shall be posted on OASIS for 
90 days and available for audit for a five-year period. Transmission 
customers thus shall be able to query requests to designate and 
terminate a network resource. This requirement adds valuable 
transparency without undue burden, since it is nothing more than 
maintaining a database of designation requests made and responded to 
electronically. The Commission orders public utilities, working through 
NAESB, to develop appropriate templates for OASIS.
---------------------------------------------------------------------------

    \216\ See paragraph 1477, where further detail on using OASIS to 
request designation of network resources is provided.
---------------------------------------------------------------------------

    386. The requests for clarifications by Exelon and Great Northern 
will not be addressed in this section. These requests are not related 
to OASIS postings, but involve changes in tariff language. They are 
addressed in section V.D.6 of this Final Rule.
(7) Posting of Unused Transfer Capability
NOPR Proposal
    387. In the NOPR, the Commission reminded transmission providers 
that transfer capability associated with transmission reservations that 
is not scheduled in real time should be included in non-firm ATC and 
posted on OASIS.
Comments
    388. Entegra, TANC, and TDU Systems emphasize the need for the 
posting of unused transfer capability. TDU Systems state that the 
requirement to post on OASIS all transfer capability associated with 
transmission reservations not scheduled in real time furthers not only 
the Commission's goals with respect to comparability and transparency 
of ATC calculations, but also the Commission's goals in freeing up 
access to transmission capacity for transmission customers.
Commission Determination
    389. We affirm our statement in the NOPR proposal acknowledging 
that transfer capability associated with transmission reservations that 
are not scheduled in real time is required to be made available as non-
firm, and posted on OASIS.
(8) Other OASIS Issues
Comments
    390. MidAmerican, PacifiCorp and Pinnacle contend that the 
development of the OASIS posting requirements is technical in nature 
and should be addressed by the NERC and NAESB processes.
    391. NRECA recommends that the Commission require public utility 
transmission providers to make OASIS data available in a useable, 
machine-readable and manipulable format to transmission customers (so 
they can be better prepared to make decisions about their transmission 
needs) and to the Commission (so that it can monitor the provision of 
transmission service). Similarly, Powerex states that posted data must 
be in sufficient detail to permit third parties to independently review 
and verify ATC postings and treatment of transmission service requests.
    392. Utah Municipals suggest that OASIS sites be as uniform and 
compatible as possible and reasonably user-friendly, and that 
certificate fees for access to non-public sites be evaluated for 
legitimacy. Arkansas Commission and Seattle also express concern over 
the OASIS access requirements established by most transmission 
providers, which require viewers to purchase certificates or licenses 
for the particular computers from which OASIS access is sought.
    393. Williams suggests that all transmission service-related 
business practices and local procedures, including the exercise of 
discretion or waiver or granting of exception, be posted on the 
transmission provider's OASIS. It also suggests that real-time data and 
import/export limits by constrained area should be posted on OASIS, 
along with line outages


[[Continued on page 12315]]


From the Federal Register Online via GPO Access [wais.access.gpo.gov]
]                         
 
[[pp. 12315-12364]] Preventing Undue Discrimination and Preference in Transmission 
Service

[[Continued from page 12314]]

[[Page 12315]]

(planned and unplanned), estimated return to service dates and de-rates 
of a line.
Commission Determination
    394. In response to NRECA and other commenters regarding the 
availability and format of data available on OASIS, we note that 
current regulations already require that OASIS data be made available 
in a useable, machine-readable user friendly format to transmission 
customers. The improvements required in the Final Rule will enhance the 
level of detail posted on OASIS and, in turn, transmission customers' 
ability to verify the transmission provider's treatment of transmission 
requests. Thus, to the extent NRECA or others desire greater 
consistency in data formats, they should propose such revisions through 
the NERC and NAESB processes.
    395. Regarding comments received expressing concern about the use 
of certificates for OASIS access, we believe that the use of such 
certificates can be appropriate. However, the Commission reminds 
transmission providers that the cost of OASIS access, whether by 
registration, certificate or other form of license, should be limited 
to a nominal charge, e.g., no more than $100. This nominal fee provides 
funding for OASIS maintenance while assuring that all transmission 
customers and potential customers will not be denied access because of 
excessive fees.
    396. With respect to Williams' request for additional OASIS 
postings, we agree that such additional data would be useful to 
transmission customers and is already posted on some ISO and RTO Web 
sites and, to a lesser extent, on the NERC web site (TLR data). 
Therefore, we require that all transmission service-related business 
practices and local procedures, including waivers, should be posted on 
or made available through OASIS. With respect to real-time data and 
import/export limits by constrained area, estimated return-to-service 
dates and line de-ratings, we are confident that most of this data is 
already required by this Final Rule and shall be provided whenever TTC 
and ATC changes in value trigger the posting of a narrative explanation 
of the causes of those changes. Moreover, the Final Rule requires a 
broad data exchange among transmission providers, including information 
on line outages and other data relating to ATC calculations. 
Accordingly, we will not require additional OASIS postings for this 
data.
(9) CEII
NOPR Proposal
    397. Critical Energy Infrastructure Information (CEII) is 
information concerning proposed or existing critical infrastructure 
(physical and virtual) that (1) Relates to the production, generation, 
transportation, transmission or distribution of energy, (2) could be 
useful to a person in planning an attack on critical infrastructure, 
(3) is exempt from mandatory disclosure under the Freedom of 
Information Act, 5 U.S.C. 552, and (4) does not simply give the 
location of the critical infrastructure.\217\ Access to such 
transmission related information has been restricted by the 
Commission's CEII regulations.\218 \
---------------------------------------------------------------------------

    \217\ See Critical Energy Infrastructure Information, Order No. 
683, 71 FR 58273 (Oct. 3, 2006), FERC Stats. & Regs. ] 31,228 at P 
66 (2006), reh'g pending. We note that the Commission is proposing 
to change the definition of CEII in a proceeding in Docket No. RM06-
23-000. See Critical Energy Infrastructure Information, Notice of 
Proposed Rulemaking, 71 FR 58325 (Oct. 3, 2006), FERC Stats. & Regs. 
] 32,607 (2006).
    \218\ See 18 CFR 388.112-113.
---------------------------------------------------------------------------

    398. In the NOPR, the Commission recognized that the use of the 
existing CEII processes could undermine their goal of providing 
increased transparency to information necessary to evaluate the use of 
the transmission system. As a result, the Commission requested comment 
on procedures that could be adopted by transmission providers to 
streamline the resolution of CEII concerns and allow timely disclosure 
of information from the transmission providers to interested parties.
Comments
    399. APPA and other commenters argue that the additional 
information disclosure requirements proposed in the NOPR raise 
substantial CEII concerns, and request the Commission to refine its 
CEII procedures to allow those with legitimate need for the information 
to obtain it on a timely basis.\219\ Bonneville would like to permit 
public access for stakeholders to review principles and methods used in 
ATC calculations, but only permit limited access, subject to background 
checks and non-disclosure agreements, to modeling data that may 
compromise infrastructure security. APPA suggests establishing a 
process for advance qualification for receipt of such information by 
those industry participants with rights to review information on the 
customer side of OASIS, without giving blanket public access. TDU 
Systems urge the Commission to adopt a streamlined process to ensure 
timely resolution of ATC calculation disputes and to adopt measures 
that ensure that CEII claims do not unduly restrict information.
---------------------------------------------------------------------------

    \219\ E.g., MidAmerican, Sacramento, Southern, and TVA.
---------------------------------------------------------------------------

    400. EEI and Southern caution that the release of a transmission 
provider's explanation of methodologies, practices, and procedures in 
Attachment C may not give rise to CEII concerns, but that other 
information such as energy infrastructure data, models and assessments 
do raise security and confidentiality concerns. They propose that a 
transmission provider have the ability to seek confidential treatment 
of such information. Allegheny proposes that an independent third party 
or Commission staff review and explain ATC calculations to interested 
parties without disclosing CEII.
    401. Several commenters believe that much of the information the 
Commission proposes to require transmission providers to provide will 
not pose CEII concerns.\220\ However, Entergy states that some of the 
information requires protection as proprietary information because its 
public availability over OASIS would reveal commercially sensitive 
information. ISO New England also points out that information relevant 
to the ATC calculation may be market-sensitive
---------------------------------------------------------------------------

    \220\ E.g., Nevada Companies, East Texas Cooperatives, PJM, and 
TDU Systems.
---------------------------------------------------------------------------

    402. Pinnacle believes the current CEII process is not unduly 
burdensome and urges the Commission to continue to apply the existing 
CEII procedures, which allow transmission customers with digital 
certificates or passwords to access publicly restricted transmission 
information.
Commission Determination
    403. The Commission acknowledges that certain data and studies 
required to be made public under this Final Rule may contain CEII. The 
Commission has a responsibility to protect this information. However, 
the Commission agrees with APPA, Bonneville, and TDU Systems that those 
with a legitimate need for CEII information must be able to obtain it 
on a timely basis. The Commission also shares EEI and Southern's 
concerns that the data, models and assessments used to calculate ATC 
may contain information that raises security and confidentiality 
concerns, and ISO New England and Entergy's concerns about commercial 
and market-sensitive information.
    404. In order to provide transparency and avoid undue delays in 
providing information to those with a legitimate need for it, the 
Commission requires

[[Page 12316]]

transmission providers to establish a standard disclosure procedure for 
CEII required to be disclosed by this Final Rule. We note that 
transmission customers already have digital certificates or passwords 
to access publicly restricted transmission information on OASIS. 
Transmission providers may set up an additional login requirement for 
users to view CEII sections of the OASIS, requiring users to 
acknowledge that they will be viewing CEII information. Transmission 
providers may require customers to sign a nondisclosure agreement at 
the time that the customer obtains access to this portion of the OASIS. 
Only information that meets the criteria for CEII, as defined in 
section 388.113 of the Commission's regulations,\221\ should be posted 
in this section of the OASIS. Transmission providers will be 
responsible for identifying CEII and facilitating access to it by 
appropriate entities, and the Commission will be available to resolve 
disputes if they arise.
---------------------------------------------------------------------------

    \221\ 18 CFR 388.113.
---------------------------------------------------------------------------

(10) Additional Data Posting
NOPR Proposal
    405. To further reduce discretion in calculating ATC/AFC, the 
Commission proposed that transmission providers post on OASIS metrics 
related to the provision of transmission service under their OATT. In 
the NOPR, the Commission proposed to require the monthly posting of (1) 
The number of affiliate versus non-affiliate requests for transmission 
service that have been rejected and (2) the number of affiliate versus 
non-affiliate requests for transmission service that have been made. 
This posting would also detail the length of service request (e.g., 
short-term or long-term) and the type of service requested (e.g., firm 
point-to-point, non-firm point-to-point or network service). The 
Commission sought comments regarding whether it should require 
transmission providers to post their underlying load forecast 
assumptions for all ATC calculations and, on a daily basis their actual 
daily peak load for the prior day. Finally, the Commission asked for 
comment on the overall benefit of posting the proposed metrics, on 
potential alternative metrics, and on working through NAESB to develop 
standards for consistent methods of posting the new requirements on 
OASIS.
Comments
    406. PJM and other commenters support the proposal to post data 
showing acceptances and denials of transmission service requests of 
non-affiliates and affiliates.\222\ However, PJM and Ameren argue that 
the affiliate posting requirement should not apply to RTOs and ISOs, 
because they are independent, have no affiliates, and lack incentive to 
favor one transmission customer over another. MDEA requests 
clarification on how the additional posting requirements would be 
applied under Entergy's weekly procurement process. Entergy notes on 
reply that the Commission has already established metrics to measure 
the performance of its weekly procurement process, and the creation of 
further metrics are beyond the scope in a generic rulemaking. Entergy 
further points out that non-affiliated generating facilities that are 
designated as network resources to serve native load also benefit from 
transmission service obtained in this manner. It suggests that NAESB is 
the best forum for considering such issues and developing specific 
procedures for calculating these metrics. TranServ suggests that there 
are other useful metrics that NAESB should be directed to define, such 
as average time to evaluate requests and confirm requests, and 
percentage of requests denied, approved and withdrawn.
---------------------------------------------------------------------------

    \222\ E.g., Arkansas Commission, Constellation, MidAmerican, 
MDEA, Morgan Stanley, Nevada Companies, NRECA, Suez Energy NA, and 
TranServ.
---------------------------------------------------------------------------

    407. PJM notes its support of proposed OASIS posting reforms, but 
cautions that all industry groups must have an equitable and 
proportionate voice in NAESB if it is requested to develop standards. 
It also expresses concern that PJM and other RTOs have established a 
practice of posting a significant amount of data for participants' use 
in formats and applications which respective members have requested and 
approved through stakeholder processes.
    408. APPA points out that the data on transmission denials would be 
useful to the Department of Energy (DOE) in reporting on congestion in 
its triennial congestion studies to be prepared under FPA section 
216(a), and that NAESB may be able to provide standard formats for 
disclosure of such data. Some APPA members express a preference for 
NERC to develop these standards, while others stress the need for 
regional variation in posting requirements.
    409. Ameren questions whether the posting requirement would serve 
the Commission's objective of identifying undue discrimination even in 
cases where the transmission provider is not an RTO or other 
independent transmission provider, because the metrics can lead to 
incorrect impressions. MidAmerican also states that the proposed 
posting would require sophisticated analysis to yield useful benefits.
    410. EEI is not opposed to the proposal to post metrics on 
acceptance and denial of requests for transmission service, but 
suggests such information is already available on OASIS and that any 
customer or the Commission staff can develop its own metrics. Southern 
also states that this data is currently available.
    411. Several commenters support the posting of forecast and actual 
daily peak loads.\223\ Ameren states that the proposed requirement 
would produce a useful comparison, increase transparency, and provide 
the ability to verify that an appropriate amount of capacity is being 
set aside for native load. E.ON states that RTO and ISO forecasts and 
actual data need to be posted with sufficient granularity to allow for 
meaningful comparison of control area and LSE load levels. EEI requests 
that the Commission clarify that its proposal to require the posting of 
peak loads applies to system-wide loads and not only to the native load 
of the transmission provider. It also seeks clarification that the 
differences between forecast and actual system peak loads not result in 
any repercussions.
---------------------------------------------------------------------------

    \223\ E.g., Ameren, Constellation, E.ON, Nevada Companies, 
NRECA, Powerex, Suez Energy NA, TAPS, TDU Systems, and TranServ.
---------------------------------------------------------------------------

    412. APPA members in the East generally favor the proposal to post 
the load information, but its members in the West expressed concerns 
about the competitive implications of providing such data. Additional 
commenters express concern about data confidentiality.\224\ TAPS 
contends that providing for data disclosure on a one-day lag basis 
would alleviate these commercial concerns, but it also suggests that 
the Commission should require the disclosure of projected load forecast 
information on request to a customer's non-market employees or agents.
---------------------------------------------------------------------------

    \224\ E.g., E.ON, Entergy, LDWP, and TranServ.
---------------------------------------------------------------------------

Commission Determination
    413. The Commission adopts the proposed requirement to post on 
OASIS metrics related to the provision of transmission service under 
the OATT. Specifically, transmission providers must post (1) The number 
of affiliate versus non-affiliate requests for transmission service 
that have been rejected and (2) the number of affiliate versus non-
affiliate requests for

[[Page 12317]]

transmission service that have been made. This posting must detail the 
length of service request (e.g., short-term or long-term) and the type 
of service requested (e.g., firm point-to-point, non-firm point-to-
point or network service). The Commission also will require 
transmission providers to post their underlying load forecast 
assumptions for all ATC calculations and, to post on a daily basis, 
their actual daily peak load for the prior day. The Commission directs 
transmission providers to work through NAESB to develop standards for 
consistent methods of posting the new requirements on OASIS.
    414. The Commission agrees with PJM and Ameren that affiliate 
posting requirements do not apply to RTOs and ISOs, since they do not 
have affiliates to transact with. The Commission also agrees with 
Entergy that the metrics established for its weekly procurement process 
are outside the scope of this proceeding.
    415. In response to Southern's point that the information necessary 
to compute the metrics is already available on OASIS, while it is true 
that service denial information is available on OASIS for long periods, 
request information is not. As such, a customer would need to 
continuously download information from OASIS to record the data 
sufficient to calculate the metrics on its own. The Commission 
concludes that it is not unduly burdensome for transmission providers 
to calculate the metrics required by this Final Rule.
    416. With regard to posting of load forecasts and actual daily peak 
load, we conclude that such postings are necessary to provide 
transparency for transmission customers. We agree with E.ON that RTO 
and ISO load data needs to be posted at a sufficient granularity to 
allow for meaningful comparison of control area and LSE load levels. 
Most RTOs and ISOs post load data for the entire footprint, but few 
post it on an LSE or control area basis. We therefore direct ISOs and 
RTOs to post load data for the entire ISO/RTO footprint and for each 
LSE or control area footprint within the ISO/RTO. This will not create 
an undue burden on ISOs and RTOs, since the load data for the entire 
footprint is an aggregation of load data across the LSEs or control 
areas in the footprint. We also agree with EEI that the peak load 
applies to system-wide load, including native load. We direct 
transmission providers to post load forecasts and actual daily peak 
load for both system-wide load (including native load) and native load, 
as this data will be useful to customers and regulators. We deny EEI's 
request for a guarantee that transmission providers will not be held 
accountable for producing a reasonable load forecast. While we do not 
intend to penalize transmission providers for failing to account for 
unforeseen circumstances, we retain our ability to investigate any 
allegations of manipulation of load forecasts, as this could be used as 
a means of inappropriately denying requested transmission service.
    417. The Commission is not convinced by the views of some 
commenters that load data has competitive implications. The Commission 
notes, as PJM pointed out in its comments, that many RTOs have an 
established practice of posting significant amounts of load data for 
participants' use, and this data posting has not raised competitive 
concerns.

B. Coordinated, Open and Transparent Planning

1. The Need for Reform
    418. Order No. 888 set forth certain minimum requirements for 
transmission system planning. For example, Order No. 888 and the pro 
forma OATT require that transmission providers plan and upgrade their 
transmission systems to provide comparable open access transmission 
service for their transmission customers. With regard to network 
service, section 28.2 of the pro forma OATT provides that the 
transmission provider ``will plan, construct, operate and maintain its 
Transmission System in accordance with Good Utility Practice in order 
to provide the Network Customer with Network Integration Transmission 
Service over the Transmission Provider's Transmission System.'' Section 
28.2 also provides that the Transmission Provider shall, consistent 
with Good Utility Practice, ``endeavor to construct and place into 
service sufficient transfer capability to deliver the Network 
Customer's Network Resources to serve its Network Load on a basis 
comparable to the Transmission Provider's delivery of its own 
generating and purchased resources to its Native Load Customers.''
    419. The pro forma OATT also requires that new facilities be 
constructed to meet the service requests of long-term firm point-to-
point customers. Section 13.5 of the pro forma OATT requires the 
transmission provider to consider redispatch of the system to relieve 
any constraints that are inhibiting a transmission customer's point-to-
point service if it is economical to do so; but if redispatch is not 
economical, the transmission provider is obligated to expand or upgrade 
its system. This expansion obligation on the part of the transmission 
provider for point-to-point service is found in section 15.4 of the pro 
forma OATT, which provides that, when a transmission provider cannot 
accommodate a request for point-to-point transmission because of 
insufficient capability on its system, it will ``use due diligence to 
expand or modify its Transmission System to provide the requested Firm 
Transmission Service.'' Section 15.4 goes on to provide that ``the 
Transmission Provider will conform to Good Utility Practice in 
determining the need for new facilities and in the design and 
construction of such facilities.'' The transmission provider's 
obligation to upgrade or expand its system to provide point-to-point 
service as detailed in section 15.4 is contingent on the transmission 
customer agreeing to compensate the transmission provider for such 
costs pursuant to the terms of section 27 (providing for cost 
responsibility for upgrades and/or redispatch ``to the extent 
consistent with Commission policy'').
    420. In Order No. 888-A, the Commission encouraged utilities to 
engage in joint planning with other utilities and customers and to 
allow affected customers to participate in facilities studies to the 
extent practicable. The Commission also encouraged regional planning so 
that the needs of all participants are represented in the planning 
process.\225\ Order No. 888-A did not, however, require that 
transmission providers coordinate with either their network or point-
to-point customers in transmission planning or otherwise publish the 
criteria, assumptions, or data underlying their transmission plans. The 
Commission also did not require joint planning between transmission 
providers and their customers or between transmission providers in a 
given region.\226\ The only section of the existing pro forma OATT that 
directly speaks to joint planning is section 30.9, which provides that 
a network customer must receive credit when facilities constructed by 
the customer are jointly planned and installed in coordination with the 
transmission provider.\227\
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    \225\ See Order No. 888-A at 30,311.
    \226\ See id.
    \227\ Pro forma OATT section 21.2, ``Coordination of Third-Party 
System Additions,'' provides for certain rights for transmission 
providers to coordinate construction of facilities on their systems 
associated with point-to-point customer requests and related 
construction on a third-party transmission system, but imposes no 
obligation on transmission providers.

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[[Page 12318]]

    421. As the Commission stated in the NOPR, the Nation has witnessed 
a decline in transmission investment relative to load growth in the ten 
years since Order No. 888 was issued. Transmission capacity per MW of 
peak demand has declined in every NERC region. Transmission constraints 
plague most regions of the country, as reflected in the limited amounts 
of ATC posted in many regions, increased frequency of denied 
transmission requests, increasingly common transmission service 
interruptions or curtailments and rising congestion costs in organized 
markets.\228\
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    \228\ The number of TLRs has increased significantly since NERC 
started reporting annual statistics. The total number of TLRs each 
year has grown from under 500 in 1998 and 1999 to around 2000 over 
the last four years from 2002 to 2006. The number of TLR actions at 
the highest levels, requiring curtailment of firm transmission 
flows, has also grown, from under 10 before 2001 to 70 in 2006, 
averaging 55 per year from 2003 to 2006. Source: NERC Web site, 
ftp://www.nerc.com/pub/sys/all_updl/oc/scs/logs/trends.htm. In 

addition, congestion costs continue to be a major issue in RTO 
markets. For example, congestion costs in PJM were $2.09 billion in 
calendar year 2005, which was a 179 percent increase over 2004. 
Although this increase resulted primarily from increases in PJM 
annual billings, the congestion costs in both years were 
approximately 9 percent of total PJM billings in both years and have 
ranged from 6 percent to 10 percent of total billings since 2000. 
Source: 2005 PJM State of the Markets Report, April 2006.
---------------------------------------------------------------------------

    422. We do not believe that the existing pro forma OATT is 
sufficient in an era of increasing transmission congestion and the need 
for significant new transmission investment. We cannot rely on the 
self-interest of transmission providers to expand the grid in a 
nondiscriminatory manner. Although many transmission providers have an 
incentive to expand the grid to meet their State-imposed obligations to 
serve, they can have a disincentive to remedy transmission congestion 
when doing so reduces the value of their generation or otherwise 
stimulates new entry or greater competition in their area. For example, 
a transmission provider does not have an incentive to relieve local 
congestion that restricts the output of a competing merchant generator 
if doing so will make the transmission provider's own generation less 
competitive. A transmission provider also does not have an incentive to 
increase the import or export capacity of its transmission system if 
doing so would allow cheaper power to displace its higher cost 
generation or otherwise make new entry more profitable by facilitating 
exports.
    423. As the Commission explained in Order No. 888, ``[i]t is in the 
economic self-interest of transmission monopolists, particularly those 
with high-cost generation assets, to deny transmission or to offer 
transmission on a basis that is inferior to that which they provide 
themselves.'' \229\ The court agreed on review of Order No. 888, noting 
in TAPS v. FERC that ``[u]tilities that own or control transmission 
facilities naturally wish to maximize profit. The transmission-owning 
utilities thus can be expected to act in their own interest to maintain 
their monopoly and to use that position to retain or expand the market 
share for their own generated electricity, even if they do so at the 
expense of lower-cost generation companies and consumers.'' \230\ The 
Supreme Court in New York v. FERC similarly explained that ``public 
utilities retain ownership of the transmission lines that must be used 
by their competitors to deliver electric energy to wholesale and retail 
customers. The utilities' control of transmission facilities gives them 
the power either to refuse to deliver energy produced by competitors or 
to deliver competitors' power on terms and conditions less favorable 
than those they apply to their own transmissions.'' \231\
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    \229\ Order No. 888 at 31,682.
    \230\ 225 F.3d at 684.
    \231\ 535 U.S. at 8-9 (citation and footnotes omitted).
---------------------------------------------------------------------------

    424. The existing pro forma OATT does not counteract these 
incentives in the planning area because there are no clear criteria 
regarding the transmission provider's planning obligation. Although the 
pro forma OATT contains a general obligation to plan for the needs of 
their network customers and to expand their systems to provide service 
to point-to-point customers, there is no requirement that the overall 
transmission planning process be open to customers, competitors, and 
State commissions.\232\ Rather, transmission providers may develop 
transmission plans with limited or no input from customers or other 
stakeholders. There also is no requirement that the key assumptions and 
data that underlie transmission plans be made available to customers.
---------------------------------------------------------------------------

    \232\ As discussed in more detail in the NOPR, the need for 
reform was recognized by the Consumer Energy Council of America 
(CECA), a public interest energy policy organization with a 30-year 
history of bringing stakeholders together to find solutions to 
contentious energy policy issues. CECA launched its Transmission 
Infrastructure Forum in early 2004, which published its conclusions 
in January 2005 in a final report titled ``Keeping the Power 
Flowing: Ensuring a Strong Transmission System to Support Consumer 
Needs for Cost-Effectiveness, Security and Reliability'' (CECA 
Report). Among other things, the CECA Report concludes that regional 
transmission planning with consumer input early in the process is 
needed to ensure the development of a robust transmission system 
capable of meeting consumer needs reliably and at reasonable cost 
over time. The CECA Report stresses that regional transmission 
planning must address inter-regional coordination, the need for both 
reliability and economic upgrades to the system, and critical 
infrastructure to support national security and environmental 
concerns. See NOPR at P 207.
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    425. Taken together, this lack of coordination, openness, and 
transparency results in opportunities for undue discrimination in 
transmission planning. Without adequate coordination and open 
participation, market participants have no means to determine whether 
the plan developed by the transmission provider in isolation is unduly 
discriminatory. This means that disputes over access and discrimination 
occur primarily after-the-fact because there is insufficient 
coordination and transparency between transmission providers and their 
customers for purposes of planning.\233\ The Commission has a duty to 
prevent undue discrimination in the rates, terms, and conditions of 
public utility transmission service and, therefore, an obligation to 
remedy these transmission planning deficiencies. As we explain above, 
our authority to remedy undue discrimination is broad.\234\ In 
addition, new section 217 of the FPA requires the Commission to 
exercise its jurisdiction in a manner that facilitates the planning and 
expansion of transmission facilities to meet the reasonable needs of 
LSEs. A more transparent and coordinated regional planning process will 
further these priorities, as well as support the DOE's responsibilities 
under EPAct 2005 section 1221 to study transmission congestion and 
issue reports designating National Interest Electric Transmission 
Corridors and the Commission's responsibilities under EPAct 2005 
section 1223.
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    \233\ In our discussion of enforcement issues at section V.E of 
this Final Rule, we note specific situations in which transmission 
providers have agreed to resolve staff allegations that they engaged 
in OATT violations involving transactions with affiliates. While 
these specific situations may not directly relate to discrimination 
in planning, they nevertheless document the continuing incentive of 
transmission providers to favor themselves and their affiliates in 
the provision of transmission service.
    \234\ See Order No. 888 at 31,669 (noting that the FPA ``fairly 
bristles'' with concern for undue discrimination (citing AGD, 824 
F.2d at 998).
---------------------------------------------------------------------------

NOPR Proposal
    426. In order to provide for more comparable open access 
transmission service, limit the potential for undue discrimination and 
anticompetitive conduct, and satisfy its statutory responsibilities 
under section 217 of the FPA, the Commission proposed to amend the pro 
forma OATT to require coordinated, open, and transparent transmission 
planning on both a local and regional level. Each public utility

[[Page 12319]]

transmission provider would be required to submit, as part of its 
compliance filing in this proceeding, a proposal for a coordinated and 
regional planning process that complies with the following eight 
planning principles: Coordination, openness, transparency, information 
exchange, comparability, dispute resolution, regional participation, 
and congestion studies. In the alternative, transmission providers 
could make a compliance filing in this proceeding describing their 
existing coordinated and regional planning processes and showing that 
they are consistent with or superior to that required in the Final 
Rule.
    427. The Commission stated that it expected non-public utility 
transmission providers to participate in the proposed planning 
processes, given that effective regional planning cannot occur without 
the participation of all transmission providers, owners, and customers. 
Although the Commission encouraged the use of an independent third 
party to oversee or coordinate the planning process, the NOPR did not 
propose to require it. The Commission also strongly encouraged the 
participation of State commissions and other State agencies in planning 
activities.
    428. The Commission sought comment on several aspects of the NOPR 
proposal. First, the Commission inquired as to the level of flexibility 
each transmission provider should be given in implementing any 
principles adopted. Second, the Commission sought comment, by way of 
example, on transmission planning processes that comply with the NOPR 
reforms in principle. Third, the Commission sought comment on whether 
there are other principles or requirements that should be adopted to 
support the construction of needed new infrastructure and otherwise 
ensure that all market participants are treated on a comparable basis. 
Specifically, the Commission inquired: (a) Whether there should be a 
principle or guideline to govern the recovery and allocation of costs 
associated with funding the regional planning requirement; (b) whether 
there should be a requirement that, at least for large new transmission 
projects, there be an open season to allow market participants to 
participate in joint ownership of these projects; (c) whether there 
should be a specific study process to identify opportunities to enhance 
the grid for purposes beyond maintaining reliability or reducing 
current congestion; and, (d) whether public utilities should be 
required to develop cost allocation principles to address the sharing 
of the costs of new transmission projects and, given that such projects 
can take years to construct, whether the planning process should be 
required to look out at least as far as the longest time it would take 
to build such an upgrade in the region in question. Finally, the 
Commission sought comment on the level of detail to be required in 
transmission providers' OATTs.
Comments
    429. Most commenters support the development of coordinated, open, 
and transparent planning. While differing on how they should be 
implemented, commenters express broad support for the eight planning 
principles,\235\ though all RTOs and ISOs and many investor-owned 
utilities believe that their planning processes already comply with the 
proposals in the NOPR. ISO/RTO Council, as well as individual RTOs and 
ISOs, advance the position that RTOs and ISOs already meet the planning 
requirements in the NOPR, that there has been no credible case made for 
reopening their already approved planning processes, and that RTOs and 
ISOs should be exempt from complying with the NOPR's planning 
principles.
---------------------------------------------------------------------------

    \235\ The one exception is the congestion studies requirement, 
which is generally opposed by transmission providers and supported 
by customers.
---------------------------------------------------------------------------

    430. Some transmission providers agree that RTOs already meet the 
principles, and others argue against commenters who maintain that RTOs 
``rubber stamp'' transmission provider plans.\236\ For example, MISO 
asserts that it conducts an open planning process and does not ``rubber 
stamp'' projects. Duke concurs with MISO, stating that there are 
abundant opportunities for participation in the MISO planning process. 
Xcel also replies in support of the MISO process.
---------------------------------------------------------------------------

    \236\ E.g., Duke, Exelon, and Xcel.
---------------------------------------------------------------------------

    431. Several transmission customers, however, argue that current 
RTO processes are insufficient because, among other things, they merely 
accept the transmission owners' plans and only provide for after-the-
fact input, thus failing to satisfy the planning principles proposed in 
the NOPR.\237\ Old Dominion also asserts that RTOs generally approve 
transmission owner identified upgrades, which give them the advantage 
of having their own parochial plans incorporated into the regional plan 
without any separate evaluation or complete stakeholder input. TAPS 
asserts that open planning should apply both to the RTO and the 
underlying transmission owners' planning efforts. In its reply, WPS 
opposes MISO's proposal to be exempt from the NOPR's planning 
requirements, arguing that the MISO process is not open and only 
aggregates the plans of the transmission providers.
---------------------------------------------------------------------------

    \237\ E.g., Indicated Parties Reply, Old Dominion, NRECA, and 
TAPS.
---------------------------------------------------------------------------

    432. EEI takes issue with broad statements in the NOPR that assert 
that transmission providers have a disincentive to remedy transmission 
congestion and to plan their transmission systems on a comparable 
basis. Other individual investor-owned utilities also assert that the 
record does not support the NOPR's claims that a mandatory coordinated, 
open, and transparent planning process is necessary to remedy undue 
discrimination.\238\ Many others, however, believe the NOPR correctly 
diagnoses the problem of discrimination.\239\
---------------------------------------------------------------------------

    \238\ See, e.g., Duke and Southern.
    \239\ See, e.g., APPA and EPSA. However, NRG and Reliant believe 
that the planning process outside of RTOs is fundamentally flawed 
and cannot be remedied by the NOPR's planning proposal.
---------------------------------------------------------------------------

    433. Most commenters do not question the Commission's jurisdiction 
to address the transmission planning process generally. Southern, 
however, argues that the Commission has no general authority in this 
area and that section 217 of the FPA does not grant the Commission any 
additional jurisdiction to impose a regional planning requirement.\240\ 
FMPA counters that the Commission has FPA authority to cure undue 
discrimination and to ensure ``just and reasonable'' transmission rates 
and terms by adopting transmission planning criteria.\241\ In their 
replies, APPA and TAPS agree with the Commission that FPA section 
217(b)(4) can be cited as legal support for transmission planning. In 
its reply, NRECA stresses that the transmission planning process must 
focus, consistent with FPA section 217(b)(4), on the reasonable long-
term needs of LSEs, not all users of the system as argued by EPSA and 
NRG. Santee Cooper urges the Commission to be mindful of the limits of 
its jurisdiction in establishing study requirements that may delve into 
generation resource adequacy or issues related to the mix of 
generation. Other commenters urge the Commission not to impinge on 
State jurisdiction.\242\ In its reply, LPPC emphasizes that the 
Commission's expectation that public power entities will participate is

[[Page 12320]]

sufficient and asserts that there is no reason to take further action 
that might test the limits of jurisdiction under FPA section 211A.\243\
---------------------------------------------------------------------------

    \240\ Progress Energy also claims that the Commission does not 
have any jurisdiction to mandate regional planning.
    \241\ See also TAPS Reply.
    \242\ See, e.g., Nevada Companies, New Mexico Attorney General, 
North Carolina Commission Reply, and Southern.
    \243\ Other jurisdictional arguments primarily relate to the 
question of joint ownership, in which some commenters argue that the 
Commission lacks jurisdiction to mandate joint ownership 
arrangements. See, e.g., Duke, EEI, National Grid, Northeast 
Utilities, PSEG, and Southern. FMPA and others, however, argue that 
the Commission does have the authority to order joint ownership. 
Joint ownership will be discussed more fully below.
---------------------------------------------------------------------------

    434. WIRES endorses several planning objectives it believes to be 
critical to successful planning. These objectives include open and 
transparent planning procedures, a long-term planning horizon, broad-
based inclusion of reliability, economic, efficiency and environmental 
considerations in planning, clear conditions under which a transmission 
owner will commit to build planned facilities, and provision for fair 
and efficient allocation of the costs of planned facilities. WIRES also 
emphasizes the importance of considering non-transmission alternatives, 
arguing that an appropriate grid plan must be based on an integrated 
view of all alternatives, including demand response and distributed 
generation.
Commission Determination
    435. In order to limit the opportunities for undue discrimination 
described above and in the NOPR, and to ensure that comparable 
transmission service is provided by all public utility transmission 
providers, including RTOs and ISOs, the Commission concludes that it is 
necessary to amend the existing pro forma OATT to require coordinated, 
open, and transparent transmission planning on both a local and 
regional level. We disagree with commenters arguing either that we lack 
jurisdiction to require coordinated transmission planning or that we 
have not established a basis for such a requirement. The Commission has 
broad authority to remedy undue discrimination by ensuring that 
transmission providers plan for the needs of their customers on a 
comparable basis.\244\ That fundamental requirement was adopted in 
Order No. 888 and the reforms adopted herein should ensure that it will 
be implemented properly. Further, we explained in detail above why 
undue discrimination remains a concern in the planning area and why the 
existing OATT is insufficient to address that concern.
---------------------------------------------------------------------------

    \244\ See AGD, 824 F.2d at 1008 (Commission has broad discretion 
to promulgate generic rules to eliminate undue discrimination 
without ``conduct[ing] experiments in order to rely on the 
prediction that an unsupported stone will fall'').
---------------------------------------------------------------------------

    436. New section 217 of the FPA further supports reform in this 
area, as it reflects Congress' intent that the Commission utilize its 
powers to facilitate the planning and expansion of the transmission 
system.\245\ Through EPAct 2005 sec. 1223, Congress also directed the 
Commission to encourage the deployment of advanced transmission 
technologies in infrastructure improvements, including among others 
optimized transmission line configurations (including multiple phased 
transmission lines), controllable load, distributed generation 
(including PV, fuel cells, and microturbines), and enhanced power 
device monitoring.
---------------------------------------------------------------------------

    \245\ FPA section 217(b)(4) provides that ``[t]he Commission 
shall exercise the authority of the Commission under [the FPA] in a 
manner that facilitates the planning and expansion of transmission 
facilities to meet the reasonable needs of load-serving entities to 
satisfy the service obligations of the load-serving entities, and 
enables load-serving entities to secure firm transmission rights (or 
equivalent tradable or financial rights) on a long term basis for 
long term power supply arrangements made, or planned, to meet such 
needs.''
---------------------------------------------------------------------------

    437. Accordingly, each public utility transmission provider is 
required to submit, as part of a compliance filing in this proceeding, 
a proposal for a coordinated and regional planning process that 
complies with the planning principles and other requirements in this 
Final Rule.\246\ In the alternative, a transmission provider (including 
an RTO or an ISO, as discussed below), may make a compliance filing in 
this proceeding describing its existing coordinated and regional 
planning process, including the appropriate language in its tariff, and 
show that this existing process is consistent with or superior to the 
requirements in this Final Rule. Under either of these approaches, the 
process must be documented as an attachment to the transmission 
provider's OATT.
---------------------------------------------------------------------------

    \246\ The pro forma OATT, as modified by this Final Rule, 
reflects the proposed planning requirement in sections 15.4, 16.1, 
17.2(x), 28.2, 29.2, 31.6. The planning process itself will be 
included as Attachment K to the pro forma OATT. We understand that 
some transmission providers may already have attachments to their 
OATTs labeled with the letter ``K,'' in which case transmission 
providers are free to label their planning process OATT attachment 
with the next available letter.
---------------------------------------------------------------------------

    438. At the outset, we note that the planning obligations imposed 
in this Final Rule do not address or dictate which investments 
identified in a transmission plan should be undertaken by transmission 
providers. Furthermore, except for the discussion below of cost 
allocation for transmission investments under Principle 9, the planning 
obligations included in this Final Rule do not address whether or how 
investments identified in a transmission plan should be compensated. 
Through the principles described below, we establish a process through 
which transmission providers must coordinate with customers, 
neighboring transmission providers, affected State authorities, and 
other stakeholders in order to ensure that transmission plans are not 
developed in an unduly discriminatory manner.
    439. As for the application of the Final Rule's coordinated 
planning requirement to RTOs and ISOs, which already have a Commission-
approved transmission planning process on file with us, we note that 
the intent of our reform in this Final Rule is not to reopen prior 
approvals, but rather to ensure that the transmission planning process 
utilized by each RTO and ISO is consistent with or superior to the 
planning process adopted here. When the Commission approved the 
existing RTO and ISO transmission planning processes, they were found 
to be consistent with or superior to the existing pro forma OATT. 
Because the pro forma OATT is being reformed by this Final Rule, it is 
necessary for each RTO and ISO to now either reform its process or show 
that its planning process is consistent with or superior to the pro 
forma OATT, as modified by the Final Rule.
    440. We also make clear that transmission owning members of ISOs 
and RTOs must participate in the planning processes adopted in this 
Final Rule. In order for an RTO's or ISO's planning process to be open 
and transparent, transmission customers and stakeholders must be able 
to participate in each underlying transmission owner's planning 
process. This is important because, in many cases, RTO planning 
processes may focus principally on regional problems and solutions, not 
local planning issues that may be addressed by individual transmission 
owners. These local planning issues, however, may be critically 
important to transmission customers, such as those embedded within the 
service areas of individual transmission owners. Consequently, the 
intent of the Final Rule will not be realized if only the regional 
planning process conducted by the RTOs and ISOs is shown to be 
consistent with or superior to the Final Rule. To ensure full 
compliance, individual transmission owners must, to the extent that 
they perform transmission planning within an RTO or ISO, comply with 
the Final Rule as well. Without such a requirement, the more regional 
RTO or

[[Page 12321]]

ISO planning process will not comply with the requirements of the Final 
Rule to the extent they incorporate and rely on information prepared by 
underlying transmission owners that, in turn, have not complied with 
the Final Rule. Accordingly, as part of their compliance filings in 
this proceeding, RTOs and ISOs must indicate how all participating 
transmission owners within their footprint will comply with the 
planning requirements of this Final Rule. While we leave the mechanics 
of such compliance to each RTO and ISO, we emphasize that the RTO's or 
ISO's planning processes will be insufficient if its underlying 
transmission owners are not also obligated to engage in transmission 
planning that complies with Final Rule.\247\
---------------------------------------------------------------------------

    \247\ We understand that there are some transmission owners in 
RTOs or ISOs that continue to have OATTs on file under which they 
provide service over certain transmission facilities that they did 
not turn over to the operational control of the RTO or ISO. Like any 
other transmission provider, those entities must submit a compliance 
filing to their OATTs that satisfies all requirements of this Final 
Rule, including the inclusion of an attachment governing their own 
planning procedures. As we explain elsewhere, the compliance filing 
deadline for transmission owning participants in RTOs and ISOs shall 
be the same as the RTO and ISO deadline, i.e., 210 days after 
publication of the Final Rule in the Federal Register.
---------------------------------------------------------------------------

    441. The Commission also expects all non-public utility 
transmission providers to participate in the planning processes 
required by this Final Rule. A coordinated, open, and transparent 
regional planning process cannot succeed unless all transmission owners 
participate. We are encouraged, based on the representations of LPPC 
and others, that non-public utility transmission providers will fully 
participate in such processes. We therefore do not believe it is 
necessary at this time to invoke our authority under FPA section 211A, 
which gives us authority to require non-public utility transmission 
providers to provide transmission services on a comparable and not 
unduly discriminatory or preferential basis.\248\ If we find on the 
appropriate record, however, that non-public utility transmission 
providers are not participating in the planning processes required by 
this Final Rule, the Commission may exercise its authority under 
section 211A on a case-by-case basis. Further, we note that reciprocity 
dictates that non-public utility transmission providers that take 
advantage of open access due to improved planning should be subject to 
the same requirements as jurisdictional transmission providers.
---------------------------------------------------------------------------

    \248\ FPA section 211A(b) provides, in pertinent part, that 
``the Commission may, by rule or order, require an unregulated 
transmitting utility to provide transmission services--(1) At rates 
that are comparable to those that the unregulated transmitting 
utility charges itself; and (2) on terms and conditions (not 
relating to rates) that are comparable to those under which the 
unregulated transmitting utility provides transmission services to 
itself and that are not unduly discriminatory or preferential.'' The 
non-public utility transmission providers referred to in this Final 
Rule include unregulated transmitting utilities that are subject to 
FPA section 211A.
---------------------------------------------------------------------------

    442. In sum, each OATT planning process attachment must incorporate 
the transmission planning principles and concepts in this Final Rule 
and must be filed with the Commission within 210 days after the 
publication of the Final Rule in the Federal Register. Alternatively, 
RTOs, ISOs, and other transmission providers that currently have 
planning processes they believe comply with the Final Rule may make a 
filing with the Commission documenting those processes in an OATT 
attachment and explaining how their planning processes are consistent 
with or superior to the planning process adopted here. Such filings 
must also be submitted within 210 days after the publication of the 
Final Rule in the Federal Register.
    443. In order to assist transmission providers in complying with 
the Final Rule, and ensure that the planning procedures are developed 
with customer and stakeholder participation, the Commission will 
convene staff technical conferences in several broad regions around the 
country to discuss regional implementation and other compliance issues 
in advance of the compliance date. We extend an invitation to State 
regulatory commissions to participate in these technical conferences 
with our staff in order to ensure that State concerns are fully 
addressed. The Commission will endeavor to hold the technical 
conferences 90 to 120 days after the publication of the Final Rule in 
the Federal Register. To facilitate these conferences, each 
transmission provider should, within 75 days after the publication of 
the Final Rule in the Federal Register, post a ``strawman'' proposal 
for compliance with each of the planning principles adopted in the 
Final Rule, including a specification of the broader region in which it 
will conduct coordinated regional planning. This strawman may be posted 
on the transmission provider's OASIS, or its Web site if it does not 
have its own OASIS (e.g., in the case of a transmission owning member 
of an RTO or ISO that does not have its own OATT). We strongly urge 
transmission providers to consult with their stakeholders in the 
development of this strawman.
2. Planning Principles
    444. We set forth below the planning principles that must be 
satisfied for a transmission provider's planning process to be 
considered compliant with the Final Rule. The NOPR identified eight 
such principles, but based on the comments received the Commission will 
require compliance with nine--the original eight plus a cost allocation 
principle, as described further below.
a. Coordination
    445. In the NOPR, the Commission proposed that transmission 
providers must meet with all of their transmission customers and 
interconnected neighbors to develop a transmission plan on a 
nondiscriminatory basis. We sought comment on specific requirements for 
this coordination, such as the minimum number of meetings to be 
required each year, the scope of the meetings, the notice requirements, 
the format, and any other features deemed important by commenters.
Comments
    446. Commenters express universal support for the general concept 
of coordination, but differ on how specific the requirement should be. 
Several commenters argue that the requirement that transmission 
providers ``must meet'' with customers and utilities is 
unrealistic.\249\ EEI requests that the Commission clarify that 
transmission providers will be responsible for coordinating with 
customers and holding meetings, but that the requirement to meet should 
be limited to making reasonable efforts to meet with all customers. 
NRECA asks on reply that the Commission make clear that the lack of 
full participation by some nonjurisdictional utilities that take 
network service under the OATT should not excuse the transmission 
provider's obligation to engage in transmission planning. NRECA states 
that inclusion in the planning process must be an opportunity for LSEs, 
not an obligation.
---------------------------------------------------------------------------

    \249\ E.g., Allegheny, Duke, EEI, International Transmission, 
MidAmerican, NorthWestern, and SCE.
---------------------------------------------------------------------------

    447. Other commenters express a more general concern that the 
Commission not be prescriptive with respect to meeting 
requirements.\250\ For example, most commenters generally believe the 
Commission should not prescribe rigid rules regarding the number of 
meetings that must be held

[[Page 12322]]

each year. Xcel, however, suggests that a minimum of three meetings a 
year would be appropriate. Progress notes that coordination in North 
Carolina already occurs as a result of regular meetings throughout the 
year. Nevada Companies believe that meetings should be dependent on 
need and should not be programmatically established. TDU Systems 
recommend at least monthly meetings, but stress that meetings should be 
as frequent as is required to specify and perform the studies forming 
the basis for the plan. NCPA believes that the minimum requirements are 
not as important as how they can be monitored or enforced to ensure 
that true participation indeed occurs.
---------------------------------------------------------------------------

    \250\ E.g., Allegheny, APPA, Bonneville, California Commission, 
Duke, Entergy, Imperial, International Transmission, MidAmerican, 
NCEMC, NC Transmission Planning Participants Reply, NorthWestern, 
NRECA, Pinnacle, Progress Energy, CREPC, Santee Cooper, SCE, TVA, 
and WAPA.
---------------------------------------------------------------------------

    448. Seattle suggests 30 days notice for meetings and that 
information regarding meetings be posted at least one week in advance. 
Entergy finds a notice requirement reasonable, and other utilities 
suggest a 30-day requirement would be appropriate.\251\ Seattle also 
suggests e-mail notification and Salt River supports internet posting. 
With respect to details beyond frequency and notice, Entergy cautions 
the Commission against being too prescriptive.
---------------------------------------------------------------------------

    \251\ E.g., Nevada Companies and NorthWestern.
---------------------------------------------------------------------------

    449. On meeting scope, several commenters request that the 
Commission make clear that the purpose of the meeting is to focus on 
transmission issues and not provide a broad forum for other 
issues.\252\ Sacramento believes that meetings should be limited to 
sub-regional or regional transmission planning and not include planning 
to meet local transmission needs.
---------------------------------------------------------------------------

    \252\ E.g., Entergy, Progress Energy, SCE, and Southern.
---------------------------------------------------------------------------

    450. Other commenters stress that joint planning requires more than 
just meeting with customers and that all LSEs need to be integrated 
into the planning process so that they are actively developing 
transmission plans alongside transmission providers from the 
inception.\253\ This concept of collaborative planning is a running 
theme in the comments provided by several public power entities, such 
as NRECA, TAPS, and TDU Systems. TDU Systems argue that comparability 
requires that LSEs have equal weight in decision-making rather than 
provide de facto veto authority to transmission providers. NRECA argues 
in its reply that collaborative planning is required by FPA section 
217(b)(4). These commenters assert that LSEs must be able to 
participate in the development of planning models, including the 
assumptions and criteria that go into these models, and in the 
development of the base case and change case for study purposes, 
particularly as to the identification and projection of loads and 
resources.\254\ Progress and Southern, however, argue in replies that 
giving customers equal weight in decision-making crosses the line from 
planning to control by third parties, and Southern believes this would 
be opposed by State regulators.
---------------------------------------------------------------------------

    \253\ E.g., NRECA, Seminole Reply, TAPS, and TDU Systems.
    \254\ This collaborative approach is also generally supported by 
East Texas Cooperatives, FMPA, NCEMC, NCPA, and Old Dominion. NCEMC 
believes that the key to ensuring true collaboration is a voting 
structure, like that adopted in the North Carolina Transmission 
Planning Collaborative, which gives all load-serving entities an 
equal say in planning decisions. APPA also believes that giving 
customers a say in the outcome (e.g., through voting) is critical.
---------------------------------------------------------------------------

Commission Determination
    451. The Commission adopts the coordination principle proposed in 
the NOPR. Commenters overwhelmingly desire flexibility as to the 
coordination principle, and as such, we will not prescribe the 
requirements for coordination, such as the minimum number of meetings 
to be required each year, the scope of the meetings, the notice 
requirements, the format, and any other features. We will allow 
transmission providers, with the input of their customers and other 
stakeholders, to craft coordination requirements that work for those 
transmission providers and their customers and other stakeholders.
    452. We emphasize that the purpose of the coordination requirement 
is to eliminate the potential for undue discrimination in planning by 
opening appropriate lines of communication between transmission 
providers, their transmission-providing neighbors, affected State 
authorities, customers, and other stakeholders. Rigid and formal 
meeting procedures may be one way to accomplish this goal, but there 
may be other ways as well. For example, a transmission provider could 
meet this requirement by facilitating the formation of a permanent 
planning committee made up of itself, its neighboring transmission 
providers, affected State authorities, customers, and other 
stakeholders. Such a planning committee could develop its own means of 
communication, which may or may not emphasize formal meeting 
procedures. We are more concerned with the substance of coordination 
than its form.
    453. In response to the concerns of some commenters, we clarify 
that transmission providers are not required to meet with customers and 
other stakeholders that choose not to meet. Transmission providers 
cannot force others to meet with them. Transmission providers are, 
however, required to craft a process that allows for a reasonable and 
meaningful opportunity to meet or otherwise interact meaningfully. We 
also clarify that the coordination requirements imposed in this Final 
Rule are intended to address transmission planning issues, and are not 
intended to provide a forum for ancillary issues, such as specific 
siting concerns, which are better addressed elsewhere. As for NRECA's 
concern that transmission providers must plan for their 
nonjurisdictional network customers even if they decline to fully 
participate in the planning process, a transmission provider cannot be 
expected to effectively plan for a customer if that customer declines 
to engage in the planning process. Therefore, we encourage NRECA and 
non-public utilities to participate fully in the planning process.
    454. In response to the suggestion by some commenters that we 
require transmission providers to allow customers to collaboratively 
develop transmission plans with transmission providers on a co-equal 
basis, we clarify that transmission planning is the tariff obligation 
of each transmission provider, and the pro forma OATT planning process 
adopted in this Final Rule is the means to see that it is carried out 
in a coordinated, open, and transparent manner, in order to ensure that 
customers are treated comparably. Therefore, the ultimate 
responsibility for planning remains with transmission providers. With 
this said, we fully intend that the planning process adopted herein 
provide for the timely and meaningful input and participation of 
customers into the development of transmission plans. This means that 
customers must be included at the early stages of the development of 
the transmission plan and not merely given an opportunity to comment on 
transmission plans that were developed in the first instance without 
their input.
b. Openness
    455. In the NOPR, the Commission proposed that transmission 
planning meetings must be open to all affected parties (including all 
transmission and interconnection customers and State authorities). The 
Commission also sought comment on whether there are any circumstances 
under which participation should be limited, for example, to address 
confidentiality concerns.

[[Page 12323]]

Comments
    456. Commenters generally agree on the need to meet with all 
affected parties, as well as the need to limit some meetings for 
security or confidentiality reasons. Certain commenters urge the 
Commission to make clear that openness does not extend to a requirement 
to meet with the general public and that the meetings are for 
``industry and governmental representatives'' only.\255\ For example, 
Southern agrees that eligible transmission customers and State 
commissions should be allowed to participate in the meetings, but 
states that these meetings should not be open to the general public to 
help ensure that the focus is on core transmission planning and not be 
diverted to other issues.
---------------------------------------------------------------------------

    \255\ E.g., APPA, EEI, Salt River, and Southern.
---------------------------------------------------------------------------

    457. Transmission providers generally note that some meetings will 
need to be limited for CEII concerns or for discussion of commercially-
sensitive information.\256\ Progress Energy states the Commission 
should be flexible regarding the composition of meetings and openness, 
noting that in North Carolina meetings involving CEII are limited to 
transmission personnel and non-marketing personnel of participating 
LSEs, while other meetings in the North Carolina process are open to 
the public. In their reply, NC Transmission Planning Participants note 
that they have been able to negotiate confidentiality protocols 
agreeable to each of them. Duke believes that restrictions on open 
meetings need to be in place when sensitive commercial information is 
being discussed, so that personnel engaged in the merchant function do 
not gain access to sensitive information about their competitors. 
Indianapolis Power recommends the Commission keep existing restrictions 
on access to planning meetings in place to preserve current protections 
on security and competitive information. TVA states that it is 
particularly concerned with maintaining confidentially and asks the 
Commission to defer to NERC and its Regional Entities, which TVA says 
are developing procedures for planning.
---------------------------------------------------------------------------

    \256\ Other commenters also recognize the need to maintain 
confidentiality for CEII and commercially-sensitive information. 
E.g., Arkansas Commission, AWEA, California Commission, NCPA, NRECA, 
CREPC, Seattle, TDU Systems, and WAPA.
---------------------------------------------------------------------------

    458. Commenters also raise issues regarding the application of the 
Commission's Standards of Conduct to those that participate in planning 
meetings.\257\ EEI, for example, believes that if information is 
disclosed during a planning meeting and is not simultaneously made 
public, then all planning participants--including nonjurisdictional 
entities--should be subject to the Commission's Standards of Conduct. 
APPA understands the need to ensure that non-public information 
obtained during planning meetings is not utilized to gain an unfair 
advantage in the power market; however, it believes that other means 
short of the application of the Standards of Conduct would suffice, 
such as requiring simultaneous disclosure of information as a ``safe 
harbor'' or the use of confidentiality agreements.\258\
    459. NRECA and TDU Systems argue that meetings should be open and, 
joined by APPA, suggest that confidentiality issues can be managed with 
confidentiality agreements and other arrangements (such as password 
protected access to information). TAPS suggests that access to data be 
limited to transmission dependent utility employees not involved in 
marketing or to an outside consultant. California Commission stresses 
that any advisory subcommittees must also be open to all stakeholders.
---------------------------------------------------------------------------

    \257\ Commenters raise issues with regard to the application of 
the Commission's Standards of Conduct to planning participants in 
their comments addressing some of the other principles as well, 
which will be discussed below, as well as addressed in the pending 
rulemaking in Docket No. RM07-1-000. See Standards of Conduct NOPR.
    \258\ See also East Texas Cooperatives Reply and NRECA Reply.
---------------------------------------------------------------------------

Commission Determination
    460. The Commission adopts the NOPR's proposal and will require 
that transmission planning meetings be open to all affected parties 
including, but not limited to, all transmission and interconnection 
customers, State commissions and other stakeholders. We recognize that 
it may be appropriate in certain circumstances, such as a particular 
meeting of a subregional group, to limit participation to a relevant 
subset of these entities. We emphasize, however, that the overall 
development of the transmission plan and the planning process must 
remain open. We agree with the concerns of some commenters that 
safeguards must be put in place to ensure that confidentiality and CEII 
concerns are adequately addressed in transmission planning activities. 
Accordingly, we will require that transmission providers, in 
consultation with affected parties, develop mechanisms, such as 
confidentiality agreements and password-protected access to 
information, in order to manage confidentiality and CEII concerns. 
Lastly, concerns surrounding the application of the Commission's 
Standards of Conduct to planning participants, and whether and how 
these standards should affect access to and use of information obtained 
in the planning process, will be discussed below.
c. Transparency
    461. In the NOPR, the Commission proposed that transmission 
providers be required to disclose to all customers and other 
stakeholders the basic criteria, assumptions, and data that underlie 
their transmission system plans. The Commission also sought comment on 
whether the information provided in FERC Form 715 (Form 715) is 
adequate and, if not, what additional detail should be provided. In 
addition, the Commission sought comment on the format for disclosure, 
including protections to address confidentiality concerns.
Comments
    462. Transmission providers generally agree that they should 
provide the basic criteria, assumptions, and data for planning, but 
argue that non-public utility transmission providers should also be 
required to provide comparable information.\259\ In general, EEI 
believes that information provided during the planning process should 
be treated as confidential and not disclosed to the general public.
---------------------------------------------------------------------------

    \259\ E.g., CAISO, EEI, and SCE.
---------------------------------------------------------------------------

    463. Public power entities and other commenters support 
transparency and also are sensitive to confidentiality concerns.\260\ 
NCPA believes that the failure of CAISO to release planning data is one 
of the biggest failings of CAISO planning process. Without access to 
criteria, assumptions, and data inputs, NCPA argues that customers 
cannot duplicate planning results, nor can they independently determine 
whether the assumptions are correct, whether the model is producing the 
right results, whether those results are being fairly applied in the 
choice of projects to be undertaken, or assess the impacts on their own 
customers. APPA suggests that transmission providers be required to 
reduce to writing the methodology, criteria, and processes they use to 
develop their transmission plans, including how they treat retail 
native loads, in order to ensure that standards are consistently 
applied.

[[Page 12324]]

CREPC points out that transparency is necessary if State regulatory 
processes are to give deference to planning results. Sacramento asserts 
that it may be reasonable to allow customers and stakeholders access to 
the planning model or at least allow access to a comprehensive 
description of the model and methodology, in order to allow others to 
closely replicate the planning analysis. Sacramento is joined by 
Imperial in referencing WECC's on-going effort to increase planning 
transparency.
---------------------------------------------------------------------------

    \260\ E.g., APPA, California Commission, NCPA, CREPC, Salt 
River, and WAPA. Old Dominion, however, does not believe that any of 
the data required to be disclosed is commercially-sensitive; 
however, it does recognize that it may be CEII, in which case it 
claims security can be maintained via a secure OASIS site.
---------------------------------------------------------------------------

    464. NRECA and TDU Systems, however, do not believe that a specific 
disclosure principle would be necessary if LSEs were truly integrated 
into the planning process. In other words, they argue that if the 
process is truly open, then LSEs, as participants in the development of 
the joint plan, should already have access to the inputs and 
assumptions underlying the plans and, in fact, should have helped 
develop them.
    465. EEI believes that Standards of Conduct requirements should be 
placed on all participants in the planning process whenever disclosure 
of commercially-sensitive information is needed for planning. East 
Texas Cooperatives argues that the Standards of Conduct should not be 
generically applied to public power and that such issues should be 
managed with confidentiality agreements and case-by-case protective 
orders. In its reply, NRECA also asserts that, while it is necessary to 
protect competitively-sensitive information, there is no basis for 
requiring nonjurisdictional entities to comply with the formal 
separation of functions requirements simply because they have received 
information in the planning process, as this is inconsistent with the 
cooperative utility business model. Rather, NRECA believes 
commercially-sensitive information can be handled in other established 
ways. APPA also suggests that Standards of Conduct issues can be 
managed by providing for certain ``safe harbors'' for participation, 
such as simultaneous disclosure of information or the use of an 
independent facilitator.\261\
---------------------------------------------------------------------------

    \261\ NARUC asks the Commission to re-examine the need for its 
Standards of Conduct rules concerning communications between 
resource and transmission planners in light of the mitigation 
provided by the open planning processes proposed in the NOPR.
---------------------------------------------------------------------------

    466. Commenters express a range of views on the information found 
in Form 715. MidAmerican believes Form 715 to be more than adequate and 
recommends shortening or eliminating it. Other investor-owned utilities 
find Form 715 to be generally sufficient.\262\ Others believe the 
information in Form 715, as currently supplemented by other information 
in the planning process, is adequate.\263\ Duke and WAPA contend that 
Form 715 does not contain sufficient information for transmission 
planning, but believe that disclosure of further details should be left 
to stakeholders. According to NorthWestern, Form 715 contains the basic 
data, but may not always provide the needed information.
---------------------------------------------------------------------------

    \262\ E.g., Indianapolis Power, Southern, and Xcel.
    \263\ E.g., Allegheny (with data from PJM) and Nevada Companies 
(with data from WECC).
---------------------------------------------------------------------------

    467. ISO/RTO Council believes that Form 715 data are generally 
inadequate for planning studies, but urges the Commission not to 
attempt to develop ``standardized forms'' for these and other types of 
data. CAISO also cautions against adopting a standardized form for the 
collection of necessary information, because standardized forms do not 
necessarily provide the information needed by individual providers.
    468. A number of other commenters believe that Form 715 information 
is insufficient.\264\ APPA and TAPS point out that Form 715 does not 
include all the information needed to perform a load flow study, 
including information on economic dispatch and interchange, and also 
that Form 715 information is out of date when filed. Seattle notes that 
typical sub-regional planning processes go into significantly greater 
detail than Form 715 and argues that Form 715 is primarily a 
reliability-focused report that seldom delves into economic analysis of 
congestion and transmission options that mitigate congestion.
---------------------------------------------------------------------------

    \264\ E.g., APPA, California Commission, NCPA, CREPC, Seattle, 
TAPS, and TDU Systems. California Commission and CREPC also point 
out that the load forecast information presently used in planning in 
the Western Interconnection is likewise insufficient.
---------------------------------------------------------------------------

    469. Several commenters contend that transparency in the planning 
process is of particular interest to demand resources. New Jersey Board 
suggests that each transmission provider's planning process analyze 
whether demand resources or other solutions could be considered as an 
alternative or a component of new transmission lines or upgrades. New 
Jersey Board states that this analysis should include both supply-side 
and demand-side measures such as load management, new building codes 
and energy efficiency standards, the use of distributive renewable 
energy systems, and renewable portfolio standards. Ohio Power Siting 
Board argues that an open, transparent, and inclusive regional planning 
process should include distributed generation, demand response, and new 
technology as part of the mix of available options for incremental or 
interim congestion relief until longer term solutions can be developed 
and constructed. Fayetteville notes its general support for a SEARUC 
joint planning proposal, which includes a principle that would require 
the integration of demand response in planning. WIRES likewise argues 
that an appropriate grid plan should be based on an integrated view of 
all alternatives, including demand response and distributed generation. 
PJM, Midwest ISO, and ISO New England emphasize that their planning 
processes already provide for the evaluation and integration of demand 
response resources.\265\ Other commenters, such as Alcoa and Steel 
Manufacturer's Association, suggest that demand response resources be 
considered as substitutes for certain ancillary services.
---------------------------------------------------------------------------

    \265\ See also ISO/RTO Council.
---------------------------------------------------------------------------

    470. In response to its notice convening the October 12 Technical 
Conference, the Commission received several comments addressing the 
role of demand response in planning. Participants in the technical 
conference generally responded that demand response programs are 
considered in planning, particularly in the load forecasts. Some 
observed that demand response has often been difficult to incorporate 
in long-term plans when it is not dispatchable and only available in 
one-year increments. Participants stressed that transmission providers 
must have control over a resource throughout the planning horizon if 
they are to rely on that resource in lieu of constructing upgrades. 
Some participants reported that this capability is available from 
several forms of demand response resources.
Commission Determination
    471. The Commission adopts the NOPR's proposal and will require 
transmission providers to disclose to all customers and other 
stakeholders the basic criteria, assumptions, and data that underlie 
their transmission system plans.\266\ In addition, transmission

[[Page 12325]]

providers will be required to reduce to writing and make available the 
basic methodology, criteria, and processes they use to develop their 
transmission plans, including how they treat retail native loads, in 
order to ensure that standards are consistently applied. This 
information should enable customers, other stakeholders, or an 
independent third party to replicate the results of planning studies 
and thereby reduce the incidence of after-the-fact disputes regarding 
whether planning has been conducted in an unduly discriminatory 
fashion. We note, however, that transmission providers cannot be 
expected to fulfill these planning obligations unless non-public 
utility transmission providers that participate in the planning process 
make similar information available and, for the reasons set forth 
above, we fully expect that they will do so. We believe that the same 
safeguards developed as discussed above regarding the openness 
principle, such as confidentiality agreements and password protected 
access to information, will adequately protect against inappropriate 
disclosure of confidential information or CEII.
---------------------------------------------------------------------------

    \266\ Much of the information should be available to those 
engaged in transmission planning already under reliability Standards 
TPL-001-0 through TPL-004-0 proposed in Docket RM06-16-000. See the 
Reliability Standards NOPR. These standards set out detailed 
requirements for annual studies to assess the performance of the 
transmission system and require conducting simulation studies over a 
five-year time horizon, with additional studies as needed for the 
six to ten-year horizon. The Commission proposed that planning 
entities conduct ``studies to bracket the range of probable 
outcomes,'' examining system operation under variations in demand 
levels, existing and planned facilities, reactive power resources, 
generation dispatch and transaction patterns, controllable loads and 
demand-side management, and other factors. Id. at P 1047. While we 
recognize that OATT planning is distinct from these proposed 
reliability planning standards, we expect that the key data 
underlying transmission planning will be provided in conjunction 
with reliability standards and thus should be available for 
transmission planning when those standards are finalized.
---------------------------------------------------------------------------

    472. The Commission also requires that transmission providers make 
available information regarding the status of upgrades identified in 
their transmission plans in addition to the underlying plans and 
related studies. It is important that the Commission, stakeholders, 
neighboring transmission providers, and affected State authorities have 
ready access to this information in order to facilitate coordination 
and oversight. To the extent any such information is confidential or 
consists of CEII, the transmission provider can implement the 
safeguards suggested above.
    473. In response to the concerns of some commenters regarding the 
disclosure of information to non-public utility transmission providers, 
we believe that simultaneous disclosure of transmission planning 
information where appropriate alleviates many of those concerns. In 
those instances where there is non-simultaneous disclosure of 
information, we find that existing reciprocity requirements ensure that 
information is not inappropriately shared with the non-public utility 
transmission provider's marketing affiliate.
    474. In Order No. 888-A, the Commission clarified that, under the 
reciprocity condition, a non-public utility transmission provider must 
also comply with the OASIS and Standards of Conduct requirements or 
obtain waiver of them.\267\ We reiterate that non-public utility 
transmission providers should abide by the Standards of Conduct with 
regard to managing non-public transmission planning information 
obtained through the planning process, consistent with their 
reciprocity obligations. We also note that, given the planning process 
required by this Final Rule, it may be necessary to revisit the waivers 
of the Standards of Conduct granted to certain non-public utility 
transmission providers in the past. We will not do so, however, on a 
generic basis in this proceeding. All such existing waivers thus shall 
remain in place. Whether an existing waiver of the Standards of Conduct 
should be revoked will be considered on a case-by-case basis in light 
of the circumstances surrounding the particular transmission 
provider.\268\
---------------------------------------------------------------------------

    \267\ See Order No. 888-A at 30,286.
    \268\ We believe this same approach should also apply to public 
utilities that have obtained waivers of the Standards of Conduct.
---------------------------------------------------------------------------

    475. In order for the Final Rule's transmission planning process to 
be as effective as possible, we emphasize that all transmission 
providers, both jurisdictional and nonjurisdictional, must be assured 
that the information they provide in that process will not be used 
inappropriately in the wholesale power market. While we decline to 
require a third party independent facilitator as discussed below, we do 
believe that utilizing an independent entity may help parties manage 
Standards of Conduct concerns.\269\ Finally, we wish to emphasize that 
the Commission recognizes that compliance with the Standards of Conduct 
can impose costs on small entities, but we believe that this concern 
must be balanced against the fact that a coordinated and open 
transmission planning process is critical to remedying undue 
discrimination and meeting our Nation's future energy needs and that an 
open planning process cannot be fully successful if certain entities 
(whether jurisdictional or nonjurisdictional) can use the information 
to obtain an undue advantage in power markets. We therefore intend to 
balance the costs of confidentiality restrictions with the importance 
of not allowing any entity an undue competitive advantage in addressing 
this issue on a case-by-case basis.
---------------------------------------------------------------------------

    \269\ The Commission will consider whether further changes to 
the Standards of Conduct would facilitate the transmission planning 
requirement in the Standards of Conduct NOPR initiated in Docket No. 
RM07-1-000. See supra note 257. We also intend to address the 
concerns of NARUC with regard to waiving the Standards of Conduct 
concerning communications between resource and transmission planners 
in that proceeding.
---------------------------------------------------------------------------

    476. Although we adopt the foregoing protections to ensure that 
particular entities do not gain an inappropriate competitive advantage 
over others, we believe that transmission providers should make as much 
transmission planning information publicly available as possible, 
consistent with protecting the confidentiality of customer information. 
Given that one of the primary objectives of the planning reforms 
adopted herein is to allow customers to consider future resource 
options, it will be necessary for market participants, including the 
merchant function of transmission providers, to have access to basic 
transmission planning information in order to consider those options. 
The simultaneous disclosure of transmission planning information can 
alleviate the Standards of Conduct concerns discussed above.\270\
---------------------------------------------------------------------------

    \270\ Transmission providers could ensure simultaneous 
disclosure of information through such actions as providing all 
current and potential customers and other stakeholders equal access, 
notice, and opportunity to attend planning meetings, providing for 
the contemporaneous availability of meeting handouts and minutes on 
the transmission providers' OASIS or Internet Web sites, and 
requiring that an energy affiliate or marketing affiliate employee 
of the transmission provider may not attend a meeting unless a 
representative of at least one additional customer or potential 
customer is present. We believe such actions would typically 
constitute compliance with sections 358.5(a) and (b) of the 
Standards of Conduct, 18 CFR 358.5(a)-(b), dealing with information 
access and prohibited disclosure, respectively.
---------------------------------------------------------------------------

    477. In response to commenter concerns regarding the sufficiency of 
planning information currently available in the Form 715, we find that 
Form 715, as well as Form 714, have not provided customers and others 
with the timely data needed to perform load flow studies and other 
analyses to ensure that planning is being conducted on a comparable 
basis. For example, while we understand that certain planning 
information is already provided in FERC Form No. 714 (Annual Electric 
Control and Planning Area Report) and FERC Form 715 (Annual 
Transmission Planning and Evaluation Report), we believe that with 
regard to transparency of data and assumptions, Forms 714 and 715 are 
limited in a number of ways. An important limitation is that 
information is not necessarily available on a consistent geographic 
basis. Form 715 requires selected powerflow studies by

[[Page 12326]]

control area, while Form 714 requires information on control area 
generation and load, including hourly load on a planning area. Since 
these two areas do not necessarily coincide, it can be difficult to 
apply the data except for the single annual or seasonal system peak. 
Consequently, Form 715 is an insufficient basis for broad transmission 
planning purposes and must be supplemented by additional assumptions 
and data.
    478. Information may also be difficult to compare or apply if a 
region is larger than a single control area. Where the peak periods 
represented in the Form 715 correspond to different time periods in 
different control areas, separate assumptions and information may be 
needed for a study encompassing multiple control areas. In addition, 
each control area may include different criteria for including 
facilities in the data and additional assumptions will be needed to 
resolve these issues as well. Moreover, information on the basis for 
key assumptions is limited. The Form 715 instructions require a 
description of transmission planning reliability criteria and 
assessment practices, but allow the transmitting utility discretion on 
what is reported. As a result, assumptions regarding key inputs, such 
as the load forecasts, are not available. Similarly, information 
regarding customer demand response is not available. Lastly, Form 715 
requires no information explaining the basis for generator dispatch in 
the powerflow cases, nor is any economic information provided. For 
studies of system peak reliability, when all generators are expected to 
be running, this may not be a significant limitation. However, without 
some basis for dispatching the system at other times, it becomes 
difficult or impossible to conduct meaningful load flow studies for 
other planning purposes. Therefore, we will require the disclosure of 
criteria, assumptions, data, and other information that underlie 
transmission plans as described above.
    479. Finally, several commenters assert that demand response 
resources should be considered in transmission planning.\271\ Some 
commenters note that certain regions currently are in the process of 
incorporating demand response into their transmission planning 
processes.\272\ Demand resources currently provide ancillary services 
in some regions, and this capability is in under development in some 
others.\273\ We therefore find that, where demand resources are capable 
of providing the functions assessed in a transmission planning process, 
and can be relied upon on a long-term basis, they should be permitted 
to participate in that process on a comparable basis.\274\ This is 
consistent with EPAct 2005 section 1223.
---------------------------------------------------------------------------

    \271\ E.g., Ohio Power Siting Board, New Jersey Board, and 
WIRES.
    \272\ E.g., PJM and ISO-New England.
    \273\ See Staff Report: Assessment of Demand Response & Advanced 
Metering at 97-100 (Docket Number AD-06-2-000) (Demand Response 
Report), available at http://www.ferc.gov/legal/staff-reports/demand-response.pdf#xml=http://search.atomz.com/search/http://search.atomz.com/search/

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Final Rule are not intended in any way to infringe upon State 
authority with regard to integrated resource planning. Rather, we 
believe that the transparency provided under an open regional 
transmission planning process can provide useful information which 
will help states to coordinate transmission and generation siting 
decisions, allow consideration of regional resource adequacy 
requirements, facilitate consideration of demand response and load 
management programs at the State level, and address other factors 
states wish to consider.
---------------------------------------------------------------------------

d. Information Exchange
    480. In the NOPR, the Commission proposed that network transmission 
customers be required to submit information on their projected loads 
and resources on a comparable basis (e.g., planning horizon and format) 
as used by transmission providers in planning for their native load. 
The Commission further proposed that point-to-point customers be 
required to submit any projections they have of a need for service over 
that planning horizon and at what receipt and delivery points. The 
Commission sought comment on whether specific requirements should be 
adopted for this information exchange.\275\ The Commission also stated 
that transmission providers must allow market participants the 
opportunity to review and comment on draft transmission plans.
---------------------------------------------------------------------------

    \275\ The Commission noted in the NOPR that for network service, 
some of this information is already required by sections 29, 30, and 
31 of the pro forma OATT, but to the extent it is not, the 
Commission proposed to require customers to provide additional 
information as necessary for the transmission provider to develop a 
system plan.
---------------------------------------------------------------------------

Comments
    481. Transmission providers suggest that they should be responsible 
for developing a schedule and format for submission of information and 
the development of a draft plan that provides sufficient time for 
participants to review and comment before completion of a final 
plan.\276\ EEI emphasizes the importance of requiring comparable 
information from all participants in planning, including non-public 
utilities. EEI maintains that similarly-situated participants should 
have comparable information, with commercially-sensitive information 
available only to transmission function personnel. Duke supports the 
information exchange principle in general, but believes the NOPR 
envisions a wider exchange of information on loads and resources than 
is appropriate.\277\ Instead, Duke believes that planning participants 
should agree on how much detail will be available. WAPA similarly 
suggests that any criteria for information exchange should be developed 
by stakeholders, not the Commission.
---------------------------------------------------------------------------

    \276\ E.g., EEI, Pinnacle, Salt River, and Xcel.
    \277\ TVA states that it is unaware of any shortcomings with the 
existing information exchange process and that more specific 
requirements may limit the ability of transmission providers to meet 
changing needs and processes.
---------------------------------------------------------------------------

    482. Although commenters do not generally disagree with a 
requirement for point-to-point customers to submit projections of their 
needs for service, they question the value of these projections if the 
customers have not actually requested service for these projected 
needs.\278\ Nevada Companies state that point-to-point customers should 
provide future use forecasts and that the forecast data transferred by 
all entities should be provided for the planning horizon in a uniform 
manner.
---------------------------------------------------------------------------

    \278\ E.g., APPA, Duke, and Salt River.
---------------------------------------------------------------------------

    483. Southern is concerned that the opportunity for review and 
comment could be construed to apply to draft interconnection, system 
impact, or facilities studies under the transmission provider's OATT. 
Southern argues that such a requirement would cause great delay and 
asks the Commission to clarify that the transparency requirement for 
review and comment on transmission plans is limited to only the 
transmission provider's draft of its base case transmission plan.
    484. Other commenters advance a view that joint planning should 
consist of more than providing the transmission provider with 
information and then reviewing and commenting on the plans it develops; 
rather, customers need to be able to actively participate in the 
development of the planning studies and transmission plans.\279\ APPA 
likewise believes that earlier involvement is needed so that projected 
needs are fully understood and accounted for in the initial development 
of the plan.\280\ NCPA stresses that reviewing plans is meaningless if 
there is no access to data on how the plan was created, how economic 
evaluation was

[[Page 12327]]

performed, and how and why proposed upgrades were chosen. Old Dominion 
suggests that planning information and data be posted no less than 
monthly or, where appropriate, seasonally. TDU Systems and NCEMC stress 
that LSEs should have access to all information at the same time since 
if a transmission provider performs studies without including other 
LSEs, it opens the door for providers to act on sensitive information 
before releasing it to other LSEs.
---------------------------------------------------------------------------

    \279\ E.g., NCPA and TDU Systems.
    \280\ See also Bonneville, California Commission, Imperial, 
NCPA, and Seattle.
---------------------------------------------------------------------------

    485. Some commenters advance the view that distributed generation 
and other demand response resources should be considered in developing 
a transmission plan.\281\
---------------------------------------------------------------------------

    \281\ E.g., New Jersey Board, Ohio Power Siting Board, and 
WIRES.
---------------------------------------------------------------------------

Commission Determination
    486. The Commission adopts the information exchange principle as to 
both network and point-to-point transmission customers. Accordingly, we 
will require transmission providers, in consultation with their 
customers and other stakeholders, to develop guidelines and a schedule 
for the submittal of information. In order for the Final Rule's 
planning process to be as open and transparent as possible, the 
information collected by transmission providers to provide transmission 
service to their native load customers must be transparent and, to that 
end, equivalent information must be provided by transmission customers 
to ensure effective planning and comparability. We clarify that the 
information must be made available at regular intervals to be 
identified in advance. Information exchanged should be a continual 
process, the frequency of which should be addressed in the transmission 
provider's compliance filing required by the Final Rule. However, we 
expect that the frequency and planning horizon will be consistent with 
ERO requirements.
    487. We also believe that it is appropriate to require point-to-
point customers to submit any projections they have of a need for 
service over the planning horizon and at what receipt and delivery 
points. We believe that any good faith projections of a need for 
service, even though they may not yet be subject to a transmission 
reservation, may be useful in transmission planning as they may, for 
example, provide planners with likely scenarios for new generation 
development. If the point-to-point customers do not submit such 
projections, then the transmission provider cannot later be faulted for 
failing to consider planning scenarios that might have taken into 
account reasonable projections of future system uses that were not the 
subject of specific service requests. To the extent applicable, 
transmission customers also should provide information on existing and 
planned demand resources and their impacts on demand and peak demand. 
In addition, stakeholders should provide proposed demand response 
resources if they wish to have them considered in the development of 
the transmission plan.
    488. Lastly, in response to the concerns of some commenters, we 
emphasize that the transmission planning required by this Final Rule is 
not intended, as discussed earlier, to be limited to the mere exchange 
of information and then review of transmission provider plans after the 
fact. The transmission planning required by this Final Rule is intended 
to provide transmission customers and other stakeholders a meaningful 
opportunity to engage in planning along with their transmission 
providers. At the same time, we emphasize that this information 
exchange relates to planning, not other studies performed in response 
to interconnection or transmission service requests.
e. Comparability
    489. In the NOPR, the Commission proposed that, after considering 
the data and comments supplied by market participants, each 
transmission provider develop a transmission system plan that (1) Meets 
the specific service requests of its transmission customers and (2) 
otherwise treats similarly-situated customers (e.g., network and retail 
native load) comparably in transmission system planning.
Comments
    490. Several commenters support the comparability principle,\282\ 
and others state that existing processes already follow this 
principle.\283\ EEI urges the Commission to emphasize that the 
``comparability'' principle requires the transmission provider or 
transmission owner to treat similarly-situated participants comparably 
in the development of a plan, but does not require that all 
participants be treated equally. Pinnacle and others support comparable 
treatment of similarly-situated customers and request the Commission to 
confirm that native load protections will be recognized in the concept 
of comparability.\284\ New Mexico Attorney General asserts that native 
load and non-affiliated merchants and other wholesale customers should 
not be treated comparably, because utilities have a statutory 
obligation to serve.
---------------------------------------------------------------------------

    \282\ E.g., California Commission, NCPA, CREPC, Salt River, 
Seattle, and WAPA.
    \283\ E.g., Duke and Imperial.
    \284\ See also MidAmerican, Progress Energy, and Xcel.
---------------------------------------------------------------------------

    491. TDU Systems and the NRECA repeat the view that comparability 
cannot be achieved if the transmission provider is the only one 
developing the plan, which they believe this principle contemplates. 
They argue instead that LSEs should be allowed to participate actively 
in the development of the plan from the beginning and should have equal 
weight in decision-making. TDU Systems believes that comparability does 
not allow for different planning standards for certain customers, 
because it may leave rural electric cooperatives out of the planning 
loop.\285\ TAPS also argues that comparability is not enough; rather, 
substantive goals should be included.\286\
---------------------------------------------------------------------------

    \285\ See also NRECA Reply and Old Dominion.
    \286\ TAPS cites to its ``Balanced Principles for Transmission 
Planning & Expansion,'' which was attached to its NOI comments, for 
a description of the following substantive goals: (1) Reliability/
adequacy, (2) accommodating load growth, (3) preserving existing 
transmission rights, (4) access to regional competitive generation 
markets, (5) maintaining deliverability, (6) facilitating regional/
inter-regional power transfers, and (7) integrating new generation 
into the regional grid. TAPS emphasizes that the process should 
anticipate needs and propose solutions before serious transmission 
problems emerge.
---------------------------------------------------------------------------

    492. Noting that not all transmission service requests may be 
granted, Southern urges the Commission to clarify that the intent of 
this criteria is that the transmission provider plan its system so as 
to be able to reliably serve all of its long-term firm commitments on 
its transmission system in accordance with its State and Federal legal 
requirements, as well as ERO Standards. With regard to RTO and ISO 
planning, NYAPP argues that it is not comparable for an RTO or ISO to 
only plan for bulk power facilities, while allowing individual 
transmission owners the discretion to plan for lower voltage 
transmission facilities.
    493. Some commenters argue that demand resources should be treated 
comparably to other resources in transmission planning.\287\
---------------------------------------------------------------------------

    \287\ E.g., ELCON, New Jersey Board, and WIRES.
---------------------------------------------------------------------------

Commission Determination
    494. The Commission adopts the NOPR's proposal as to the 
comparability principle and will require the transmission provider, 
after considering the data and comments supplied by customers and other 
stakeholders, to develop a transmission system plan that (1) Meets the 
specific service requests of

[[Page 12328]]

its transmission customers and (2) otherwise treats similarly-situated 
customers (e.g., network and retail native load) comparably in 
transmission system planning.\288\ Further, we agree with commenters 
that customer demand resources should be considered on a comparable 
basis to the service provided by comparable generation resources where 
appropriate.
---------------------------------------------------------------------------

    \288\ As discussed above, we emphasize that the obligation 
imposed herein on transmission providers is meant to include 
transmission owners in RTOs and ISOs that no longer have their own 
OATTs, as well as non-public utility transmission providers required 
to comply with the Final Rule's planning process consistent with 
their reciprocity obligations.
---------------------------------------------------------------------------

    495. We are specifically requiring a comparability principle to 
address concerns, such as those raised by commenters, that transmission 
providers continue to plan their transmission systems such that their 
own interests are addressed without regard to, or ahead of, the 
interests of their customers. Comparability requires that the interests 
of transmission providers and their similarly-situated customers be 
treated on a comparable basis. In response to the concerns expressed by 
several commenters, we emphasize that similarly-situated customers must 
be treated on a comparable basis, not that each and every transmission 
customer should be treated the same.\289\
f. Dispute Resolution
---------------------------------------------------------------------------

    \289\ Additionally, in our discussion of the coordination 
principle above, we clarify that transmission planning is the tariff 
obligation of each transmission provider, and as such, ultimate 
responsibility for planning remains with transmission providers. 
Accordingly, we reject the arguments made by some commenters that 
comparability requires that customers have equal weight in decision-
making.
---------------------------------------------------------------------------

    496. In the NOPR, the Commission proposed that transmission 
providers propose a dispute resolution process, such as requiring 
senior executives to meet prior to the filing of any complaint and 
using a third party neutral. The Commission noted that the Commission's 
Dispute Resolution Service is available to assist transmission 
providers in developing a dispute resolution process. The Commission 
also noted that, in addition to informal dispute resolution, affected 
parties would have the right to file complaints with the Commission 
under FPA section 206. The Commission sought comment on whether any 
specific dispute resolution processes should be required.
Comments
    497. Many commenters support the proposed dispute resolution 
principle,\290\ while others believe existing processes, including 
section 12 of the pro forma OATT, are sufficient.\291\ Other commenters 
simply urge flexibility in the development of a dispute resolution 
process.\292\ However, maintaining that the Commission has no legal 
authority to mandate a regional planning process or dispute resolution 
related thereto, Progress states the Commission should be flexible and 
allow for a voluntary dispute resolution process.\293\
---------------------------------------------------------------------------

    \290\ E.g., APPA, Bonneville, California Commission, Imperial, 
and NCPA.
    \291\ E.g., East Texas Cooperatives, Salt River, Seattle, TVA 
and WAPA. TVA points out that since planning and its principles are 
just now being formed, resources would be better spent on developing 
platforms where interested parties could have input into the 
planning process, as opposed to dispute resolution.
    \292\ E.g., Allegheny, Nevada Companies, Pinnacle, and Southern. 
Xcel, however, does not believe any dispute resolution process is 
required in the OATT.
    \293\ See also Duke and MidAmerican.
---------------------------------------------------------------------------

    498. Southern believes that dispute resolution should be limited to 
whether a provider has complied with any procedural requirements and 
not be utilized by parties to modify a transmission plan. APPA, 
however, argues that such an approach would relegate customers to an 
advisory role. EEI believes the Commission should include principles 
for dispute resolution and should allow stakeholders in the regional 
planning groups to craft their own procedures consistent with those 
principles. Reflecting concerns of some of its members, EEI cautions 
against mandating dispute resolution that includes binding resolution 
of whether, how, where, or when to construct additional transmission 
facilities.
    499. Indianapolis Power believes there should be a dispute 
resolution process in place with specific steps identified, expressing 
reservations about the vagueness of the current MISO process. ATC 
argues that RTO plans should recognize which entity is ultimately 
accountable for building transmission, by requiring transmission 
customers that have a dispute with a plan first to appeal to the local 
transmission owner to ensure both entities fully understand what is 
being requested, before carrying the dispute further.
    500. Consistent with its focus on integrated joint planning, TDU 
Systems asks that the Commission clarify that a dispute resolution 
process is not being required as a principle as an acknowledgement that 
transmission providers will retain control over the process. As long as 
LSEs are an integral part of the planning process, TDU Systems stress 
that there should be no need for an elaborate dispute resolution 
process.
Commission Determination
    501. The Commission adopts the NOPR's proposal to require 
transmission providers to develop a dispute resolution process to 
manage disputes that arise from the Final Rule's planning process.\294\ 
An existing dispute resolution process may be utilized, but those 
seeking to rely on an existing dispute resolution process must 
specifically address how its procedures will be used to address 
planning disputes. The dispute resolution process should be available 
to address both procedural and substantive planning issues, as the 
purpose for including a dispute resolution process is to provide a 
means for parties to resolve all disputes related to the Final Rule's 
planning process before turning to the Commission.
---------------------------------------------------------------------------

    \294\ We have already addressed arguments concerning our 
jurisdiction to require a transmission planning process. A process 
for resolving disputes that arise from that planning process is a 
necessary incident to it.
---------------------------------------------------------------------------

    502. We emphasize that the intent of the dispute resolution process 
required here is not to address issues over which the Commission does 
not have jurisdiction, such as a transmission provider's planning to 
serve its retail native load or State siting issues. As discussed 
above, however, we do intend that the planning process required by this 
Final Rule ensure comparability in planning between that conducted for 
a transmission provider's retail native load and its similarly-situated 
transmission customers and, therefore, issues relating to such 
comparability may be appropriate for the dispute resolution process.
    503. Lastly, we encourage transmission providers, customers, and 
other stakeholders to utilize the Commission's Dispute Resolution 
Service to help develop a three step dispute resolution process, 
consisting of negotiation, mediation, and arbitration. Regardless of 
the process adopted by a transmission provider, affected parties of 
course would retain any rights they may have under FPA section 206 to 
file complaints with the Commission.
g. Regional Participation
    504. In addition to preparing a system plan for its own control 
area on an open and nondiscriminatory basis, the Commission proposed in 
the NOPR that each transmission provider be required to coordinate with 
interconnected systems to: (1) Share system plans to ensure that they 
are simultaneously feasible and otherwise use consistent

[[Page 12329]]

assumptions and data, and (2) identify system enhancements that could 
relieve ``significant and recurring'' transmission congestion (defined 
below). The Commission emphasized that such coordination should 
encompass as broad a region as possible, given the interconnected 
nature of the transmission grid and the efficiency of addressing these 
issues in a single forum. The Commission also recognized that, as in 
the West, it may be appropriate to organize regional planning efforts 
on both a sub-regional and regional level. The Commission sought 
comment on whether there are existing institutions (such as the NERC 
regional councils or sub-regional planning groups) that are well-
situated to perform or coordinate this function.
Comments
Regional Scope
    505. EEI agrees that regional planning should be encouraged, but 
urges the Commission not to be prescriptive about the size of the 
regions involved. According to EEI, the Commission should define 
regional planning as planning that involves more than one transmission 
provider and allow the regions to define themselves. CAISO believes the 
Commission should leave the determination of the sub-regional and 
regional boundaries to transmission providers. NC Transmission Planning 
Participants assert on reply that the participants in each regional 
process are in the best position determine the proper scope of the 
planning process for their region. NRECA argues that customers and 
other stakeholders should be allowed to participate in the discussion 
that leads to the delineation of regions. NRECA asserts that regions 
should be large enough to minimize the potential for seams problems for 
LSEs in multiple control areas. At a minimum, NRECA argues that the 
Commission should ensure that all public utility transmission providers 
coordinate with their adjoining systems to ensure that the needs of 
LSEs with loads and resources in different systems' areas are met.
    506. TDU Systems support mandatory regional planning and believe 
that the Commission should specify the criteria for determining 
regions, rather than prescribe regional boundaries. In TDU Systems' 
view, ``regional'' planning at a minimum means something more than 
planning on an individual control area basis.\295\ TDU Systems stress 
that the existence of sub-regional planning must not diminish the 
obligation to plan on a broader, more regional level. TDU Systems also 
believe that more than coordination is required; rather, transmission 
providers should be required to conduct planning on an integrated basis 
with, at a minimum, first-tier, adjacent interconnected systems. If a 
transmission provider refuses to do so, TDU Systems believe that should 
be considered an exercise of vertical market power and the transmission 
provider should lose its market-based rate authority. TDU Systems also 
urge the Commission to require regional planning for both reliability 
and economic upgrades, in order to ensure that competitive market 
development is not retarded by inappropriate seams at the borders of 
utility systems.\296\ In its reply, NRECA argues that regional 
participation must be mandatory, because uncoordinated, unilateral 
planning by transmission providers severely handicaps LSEs' assembly of 
competitive power suppliers for their customers.
---------------------------------------------------------------------------

    \295\ TAPS believes joint planning should include at least two 
transmission providers and be no smaller than a State. TAPS suggests 
that the transmission providers' compliance filings identify those 
other providers it proposes to include in its regular regional 
planning process.
    \296\ NRECA's comments on regional planning are consistent with 
those of TDU Systems.
---------------------------------------------------------------------------

    507. PJM states that transmission providers bordering RTOs should 
be required to participate in the RTO planning process, but MidAmerican 
opposes such a requirement and believes it already happens in MISO 
anyway. MAPP also opposes such mandatory participation, pointing out 
that comparability would then require that transmission providers in 
RTOs participate in the planning processes of non-RTO providers on 
their borders as well.\297\ MAPP believes that currently-existing 
regions should have the opportunity to adjust their planning processes 
to meet the Commission's guidelines for regional transmission planning.
---------------------------------------------------------------------------

    \297\ See also MidAmerican Reply.
---------------------------------------------------------------------------

    508. Indianapolis Power emphasizes that the regional scope of a 
transmission provider's planning process should consider grid topology 
and historical usage to avoid regions that are too broad or unwieldy. 
Indianapolis Power believes that the current MISO region may be an 
example of a region that is too large, but nevertheless asserts that 
MISO should have the primary role in coordination, with regional 
councils in supporting roles. AWEA recommends nine planning regions 
that coincide with the nine regions being established for Regional 
Triennial Reviews in the market-based rate rulemaking in Docket No. 
RM04-7-000: \298\ PJM, New York, New England, Midwest, SPP, Southeast, 
California, Northwest, and Southwest.
---------------------------------------------------------------------------

    \298\ See Market-Based Rates for Wholesale Sales of Electric 
Energy, Capacity and Ancillary Services by Public Utilities, Notice 
of Proposed Rulemaking, 71 FR 33102 (Jun. 7, 2006), FERC Stats. & 
Regs. ] 32,602 (2006).
---------------------------------------------------------------------------

    509. LDWP and Salt River suggest that continued participation in 
existing regional and sub-regional groups should satisfy the 
expectation that municipally-owned transmission providers participate 
in open and transparent regional planning processes. Other commenters 
express a similar concern that the Commission not mandate any 
procedures that would interfere with the processes the West has already 
established.\299\ New Mexico Attorney General believes that those 
already engaged in a planning process should be allowed a waiver.
---------------------------------------------------------------------------

    \299\ E.g., California Commission, Imperial, and Salt River.
---------------------------------------------------------------------------

    510. NARUC urges the Commission to clarify that planning proposals 
should not interfere with or undermine existing regional planning 
efforts, such as those conducted by RTOs and in non-RTO areas.\300\ 
Project for Sustainable FERC Energy Policy recommends that the 
Commission use the Bonneville and PJM planning processes as models for 
evaluating transmission provider compliance. Arkansas Commission 
believes that the active involvement of states can be a catalyst for 
regional planning.
---------------------------------------------------------------------------

    \300\ See also NC Transmission Planning Participants Reply and 
North Carolina Commission Reply. Also, in its reply, North Carolina 
Commission urges the Commission not to be overly prescriptive with 
respect to the details of regional transmission planning.
---------------------------------------------------------------------------

    511. National Grid believes the principles of coordination, 
openness, and transparency should extend to inter-regional planning and 
requests clarification that this is the Commission's intent for 
neighboring regions in a single interconnect.
Existing Institutions
    512. Regarding the Commission's request for comment on whether 
there are existing institutions that are well-situated to coordinate 
regional participation, commenters express differing views regarding 
the identity of the regional coordinator and the size of the region 
over which entities should be required to coordinate. Some transmission 
provider commenters cite NERC regions and regional councils as well-
suited for coordinating regional participation.\301\ Taking an opposite 
view, ISO/RTO Council maintains that RTOs and ISOs are the best models 
for

[[Page 12330]]

regional participation, because regional reliability organizations do 
not have mandates or authority to ensure that adequate system expansion 
occurs on a coordinated basis.
---------------------------------------------------------------------------

    \301\ E.g., Allegheny, Constellation, and Duke.
---------------------------------------------------------------------------

    513. MISO is concerned the Commission intends to shift transmission 
planning responsibility from RTOs to the Regional Entities under the 
ERO, arguing that these entities have neither a sufficient level of 
independence nor a track record in transmission planning. TDU Systems 
suggest that RTOs, where they exist, should perform the regional 
planning function, although in some other instances it may be the 
regional reliability organizations. Although CAISO states that a larger 
regional entity with the authority to order expansion has some appeal, 
it contends there are too many hurdles to creating such an entity in 
the West. TAPS suggests a ``Regional Joint Planning Committee'' that is 
not dominated by transmission providers, which would direct the study 
process and be responsible for the development of uniform planning 
criteria, assumptions for base and changed cases, and transmission 
plans.
Existing Regional Planning Processes
The West
    514. Transmission provider commenters in the West (outside 
California) generally recommend the Western Electricity Coordinating 
Council (WECC) \302\ as a successful institution and an appropriate 
model for designating regions and developing a plan for the 
interconnection.\303\ Many public power entities and others in the West 
also support WECC and suggest that it should be a primary focus when 
deciding which institution can provide independent regional review and 
coordination of grid planning in the West.\304\ For example, California 
Commission notes that WECC's Transmission Expansion Planning Policy 
Committee allows for the consolidated needs of all the system operators 
in the Western Interconnection to be considered in the planning process 
and considers both reliability and economic transmission planning. 
California Commission also stresses that the processes in the West have 
resulted in transmission being built. Utah Municipals, however, are 
critical of the WECC process, and in reply, assert that the WECC 
process does not allow for effective stakeholder input, but merely 
review of transmission plans once they are formed. Utah Municipals also 
believe that sub-regional groups in its area (e.g., the Southwest 
Transmission Expansion Plan (STEP)) are more effective and urges the 
Commission to focus on the effective implementation of joint 
plans.\305\
---------------------------------------------------------------------------

    \302\ In general, WECC and its sub-regional groups have adopted 
an overall division of labor whereby WECC has undertaken 
facilitation of interstate, commercial transmission projects and the 
sub-regional groups have facilitated the planning of their member 
providers.
    \303\ E.g., ColumbiaGrid, MidAmerican, Nevada Companies, 
NorthWestern, Pinnacle, and Xcel.
    \304\ E.g., Anaheim, APPA, California Commission, Imperial, 
LDWP, NCPA, PGP, Public Power Council, CREPC, Salt River, Santa 
Clara, Seattle, TANC, WAPA, and Western Governors. APPA notes, 
however, that not all of its members that support the WECC planning 
process support those within California.
    \305\ Public Power Council does not support expansion of WECC's 
role in coordinating planning beyond its current activities, as it 
believes WECC's strength lies in the area of reliability and not 
planning and, therefore, that WECC would be best served by focusing 
on reliability and standards enforcement, rather than as a 
participant (as a facilitator or otherwise) in commercial matters.
---------------------------------------------------------------------------

    515. Other commenters support the sub-regional planning processes 
in the West as well, and generally believe the Commission should look 
to each sub-region's existing processes and institutions.\306\ For 
example, commenters in the Southwest and California also support the 
sub-regional groups located in that region (e.g., STEP and the 
Southwest Area Transmission Expansion Planning group (SWAT)).\307\ 
California Commission also supports the CAISO planning process and 
states that CAISO works closely with stakeholders to proactively 
identify needed, cost effective transmission solutions through an open, 
non-discriminatory process that has resulted in $1.8 billion in 
transmission being constructed.\308\ In its reply, NCPA emphasizes that 
the Commission should not equate the CAISO planning process with a 
California-wide process, because not all transmission providers in 
California are members of CAISO. However, California Commission notes 
that California, with the support of WECC, has begun the work of 
creating a California-wide sub-regional planning group that includes 
the large, unregulated municipal utilities that do not participate in 
CAISO.
---------------------------------------------------------------------------

    \306\ WAPA points out that certain broad functions related to 
planning can be coordinated at the regional level, but that sub-
regional planning is necessary in an expansive regional area, such 
as WAPA's service territory, in order to provide focus and detail.
    \307\ E.g., LDWP, New Mexico Attorney General, and Salt River. 
LDWP also cites its involvement in the Public Power Initiative of 
the West, CAISO, and the Western Arizona Transmission System group.
    \308\ Anaheim believes that the CAISO process does not currently 
proactively evaluate the adequacy of the system or itself propose 
projects that will enhance reliability or efficiency and is based 
entirely upon plans presented to it by transmission owners. It 
notes, however, that CAISO has proposed reforms to address these 
issues. See also Anaheim Reply.
---------------------------------------------------------------------------

Northeast
    516. PJM, NYISO, and ISO New England all have transmission planning 
processes that have been approved by the Commission. ISO/RTO Council 
cites billions of dollars of transmission investment in the Northeast 
as an example of the success of these transmission planning processes 
and argues that these processes all satisfy the Commission's principles 
for coordinated, open, and transparent planning. PJM maintains that its 
Regional Transmission Expansion Planning Protocol is a successful and 
comprehensive regional planning paradigm. ISO New England also argues 
that its transmission planning meets the principles and further points 
to the Northeastern ISO/RTO Planning Coordination Protocol as providing 
coordinated planning across the entire Northeast region.
    517. Utilities in the Northeast are generally supportive of the 
transmission planning in the Northeast RTOs. Designated NY Transmission 
Owners contend that the NYISO Comprehensive Reliability Planning 
Process is fully open, coordinated, and transparent and meets or 
exceeds each of the eight principles in the NOPR. PSEG believes the PJM 
planning process embodies the NOPR principles. Constellation cites the 
planning processes in PJM and the NYISO as examples of planning 
processes that, while not perfect, should serve as models for 
compliance filings by others. Old Dominion, however, expresses concern 
over continuing domination of transmission planning by transmission 
owners, but nevertheless commends PJM for recent efforts to include 
more stakeholder input in the planning process. National Grid is 
generally supportive of ISO New England's planning process.
Northwest
    518. Several commenters in the Northwest generally support the 
Northwest Power Pool and the ColumbiaGrid process (which will provide 
for a biennial transmission expansion plan for certain entities in the 
Northwest).\309\ Also, two groups in the Northwest are forming to 
address sub-regional planning in that region--the ColumbiaGrid group 
and the Northern Tier Transmission Group--but it is not

[[Page 12331]]

yet clear how such groups intend to coordinate with each other.
---------------------------------------------------------------------------

    \309\ E.g., Bonneville, ColumbiaGrid, PGP, Public Power Council, 
and Seattle. APPA also notes its members' support for the sub-
regional processes in the Northwest.
---------------------------------------------------------------------------

Southeast
    519. The public power commenters in the Southeast were not as 
supportive of the existing regional and sub-regional planning processes 
in their region. TVA and Santee Cooper generally support the process 
conducted by the Southeast Electric Reliability Council (SERC), and 
Santee Cooper notes that it has had a formal joint planning process 
with its largest wholesale customer for more than 25 years. APPA, 
however, notes that its members did not generally endorse existing 
regional entities in the Southeast. APPA states that SERC, for example, 
just ``rolls up'' the transmission plans of the transmission providers, 
and some working groups currently exclude non-transmission owners.\310\
---------------------------------------------------------------------------

    \310\ See also TDU Systems Reply.
---------------------------------------------------------------------------

North Carolina
    520. NCEMC points to the North Carolina Transmission Planning 
Collaborative (NC Transmission Planning), a joint planning process with 
an independent facilitator, in North Carolina. NCEMC emphasizes that 
more than regional coordination is required and that regional planning 
needs to be more than mere stakeholder review and must allow for full 
participation of LSEs in planning. NCEMC stresses that effective 
regional planning requires participation on a sufficient scale to 
encompass all LSEs within a natural market area in order to properly 
address seams issues and impacts on neighboring systems. Fayetteville 
does not believe NC Transmission Planning complies with the planning 
principles outlined in the NOPR.
Midwest
    521. MISO believes its current transmission planning process 
represents industry best practices, arguing that it is open and 
inclusive and provides multiple opportunities for entities to 
participate. MISO Transmission Owners endorse the existing MISO 
transmission planning process and believe that the process already 
provides for regional planning and an open process with stakeholder 
involvement. Ohio Power Siting Board, however, claims that MISO's 
transmission planning process should not be regarded as best practices, 
stating that it is not sufficiently open and transparent. It also 
suggests that RTOs merely ``rubber stamp'' investor-owned utility 
plans. Additionally, FMPA \311\ notes that MidAmerican has recently 
made efforts to engage in more proactive planning and has offered joint 
transmission investment opportunities. FMPA also points to its 
membership in CAPX 2020, a consortium of Upper Midwest utilities, which 
are jointly studying and planning for the needs of regional 
transmission. However, FMPA makes clear that it believes smaller 
customers nevertheless need a tariff requirement for planning to ensure 
that their needs are addressed.
---------------------------------------------------------------------------

    \311\ We note that FMPA filed joint comments on behalf of itself 
and the Midwest Municipal Transmission Group.
---------------------------------------------------------------------------

Florida
    522. While the Florida Commission believes that the planning 
process conducted by the Florida Reliability Coordinating Council 
(FRCC) is adequate, others, such as FMPA, do not.\312\ Florida 
Commission states that the FRCC has instituted a transparent and 
inclusive planning process whereby utilities, generators, and marketers 
participate in joint transmission planning studies and evaluate 
impediments to transfer capability and determine solutions to 
congestion in order to enhance the reliability of the FRCC system.
---------------------------------------------------------------------------

    \312\ See also Seminole Reply.
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Commission Determination
    523. We adopt the NOPR's proposal to include a regional 
participation principle as a component of the Final Rule's transmission 
planning process. Accordingly, in addition to preparing a system plan 
for its own control area on an open and nondiscriminatory basis, each 
transmission provider will be required to coordinate with 
interconnected systems to (1) Share system plans to ensure that they 
are simultaneously feasible and otherwise use consistent assumptions 
and data and (2) identify system enhancements that could relieve 
congestion or integrate new resources (discussed further below).\313\
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    \313\ As provided for above, transmission providers will be 
required to file a ``strawman'' proposal for compliance with the 
Final Rule's planning process within 75 days after publication of 
the Final Rule in the Federal Register that includes, among other 
things, a specification of the broader region in which they propose 
to conduct coordinated regional planning. The Commission will then 
convene technical conferences in several broad regions around the 
country to assist the participants in developing the appropriate 
regional planning groups to the extent they do not already exist.
---------------------------------------------------------------------------

    524. As discussed earlier in this Final Rule, since the advent of 
open access, power markets have become regional in almost every area of 
the country. These regional markets provide opportunities for wholesale 
customers to access competitive sources of supply, rather than relying 
exclusively on local generation, including resources owned by their 
local transmission provider. However, as discussed above, it is not in 
the economic self-interest of transmission providers to expand the grid 
to permit access to competing sources of supply. A transmission 
provider has little incentive to upgrade its transmission capacity with 
its interconnected neighbors if doing so would allow competing 
suppliers to serve the customers of the transmission provider. We 
therefore find, as discussed in greater detail above, that greater 
coordination and openness in transmission planning is required, on both 
a local and regional level, to remedy undue discrimination. The 
coordination of planning on a regional basis will also increase 
efficiency through the coordination of transmission upgrades that have 
region-wide benefits, as opposed to pursuing transmission expansion on 
a piecemeal basis. The specific features of the regional planning 
effort should take account of and accommodate, where appropriate, 
existing institutions, as well as physical characteristics of the 
region and historical practices.
    525. The Commission is encouraged that a number of voluntary 
coordinated and regional planning efforts have been developed 
throughout the country, including those administered by RTOs and ISOs 
and in certain sub-regions of the West and Southeast. For example, each 
of the Commission-approved RTOs in the Northeast, Midwest, and 
Southwest, as well as CAISO, provide for a coordinated and regional 
planning process with stakeholder input from each industry segment. 
There are several other promising efforts to establish voluntary 
coordinated and regional planning efforts around the country as noted 
in our discussion above of existing regional planning processes.
    526. The Commission fully supports these existing efforts and 
believes some of them are consistent in significant respects with the 
nature of the reforms adopted in this Final Rule. In those regions and 
sub-regions that already have adopted significant reforms, the 
Commission's planning reforms may require only modest changes, while 
other regions and sub-regions may need to undertake more significant 
changes to the way in which transmission currently is planned. The 
Commission will not in this Final Rule opine on the characteristics of 
existing regional planning processes or their consistency with the 
reforms we adopt today.

[[Page 12332]]

Rather, each process will be addressed in the context of the relevant 
compliance filing. In general, however, the Commission urges 
participants in existing regional planning processes to closely examine 
whether improvements may be implemented to ensure that each regional 
planning process is fully consistent with the requirements of this 
Final Rule.
    527. Finally, the Commission acknowledges the importance of 
identifying the appropriate size and scope of the regions over which 
regional planning will be performed. We agree that transmission 
providers, customers, affected State authorities, and other 
stakeholders should be involved in developing those regions. We decline 
to mandate the geographic scope of particular planning regions at this 
time. The scope of a particular planning region should be governed by 
the integrated nature of the regional power grid and the particular 
reliability and resource issues affecting individual regions and sub-
regions. In very large regions, there may well be both sub-regional and 
regional processes. For example, in the West there are various sub-
regional processes in addition to a WECC regional planning process. We 
believe that such an approach can work, provided that there is adequate 
scope to the sub-regional processes and adequate coordination between 
sub-regions. We expect sub-regions to coordinate as necessary to share 
data, information and assumptions as necessary to maintain reliability 
and allow customers to consider resource options that span the sub-
regions.
    528. In response to the commenters that indicate that regional 
planning already occurs today as part of the NERC planning process, we 
support any such processes, but reiterate that, if they are to meet the 
requirements of the Final Rule, they must be open and inclusive and 
address both reliability and economic considerations. As we discuss 
elsewhere in this section, customers must be allowed to request that 
economic upgrades be studied and, therefore, we will require 
transmission providers to coordinate on these issues as necessary in 
sub-regional or regional planning processes. To the extent the NERC 
processes are not considered appropriate for such economic issues, 
individual regions or sub-regions may develop alternative processes.
h. Economic Planning Studies
    529. In the NOPR, the Commission proposed to require transmission 
providers to prepare studies identifying ``significant and recurring'' 
congestion and post such studies on their OASIS. The Commission 
explained that the studies should analyze and report on (1) The 
location and magnitude of the congestion, (2) possible remedies for the 
elimination of the congestion, in whole or in part, (3) the associated 
costs of congestion, and (4) the cost associated with relieving 
congestion through system enhancements (or other means). The Commission 
sought comment on how to define ``significant and recurring'' 
congestion, such as by reference to generation redispatch, repeated 
denials of service requests, zero ATC, frequent curtailments or a 
combination of these factors. The Commission noted that the required 
congestion studies would address both ``local'' congestion (i.e., 
within the transmission provider's system) and congestion between 
control areas and sub-regions. The Commission stated that the purpose 
of this requirement is to ensure that affected market participants, 
State commissions, and the Commission understand both the costs of 
recurring transmission congestion and the alternatives for relieving 
it. The Commission sought comment on how this information should be 
used by transmission providers and market participants to address 
significant and recurring congestion.
Comments
Need for Congestion Studies
    530. The Commission's proposal regarding congestion studies gave 
rise to a wide range of comments. Some commenters generally support 
requiring congestion studies.\314\ East Texas Cooperatives asserts that 
congestion studies will greatly assist in the development of 
transmission plans, enable planning participants to focus on key 
elements of the system and assist in the preparation of the congestion 
studies conducted by DOE. NRECA also supports requiring congestion 
studies, but urges the Commission not to be prescriptive.
---------------------------------------------------------------------------

    \314\ E.g., APPA, Arkansas Commission, California Commission, 
East Texas Cooperatives, Entegra, NCPA, CREPC, Southwestern Coop, 
TDU Systems, and WIRES.
---------------------------------------------------------------------------

    531. Other commenters recommend eliminating the requirement.\315\ 
Southern, for example, argues that congestion studies could be 
misleading because they can imply that all congestion needs to be 
remedied.\316\ Duke, South Carolina E&G, and Southern agree that 
separate studies of congestion, beyond studies performed to meet 
service requests, should not be required. Rather than mandating 
congestion studies, Southern argues that the Commission should allow 
participants to determine which types of transmission studies have 
merit. Other commenters believe that, if congestion studies are 
required, they should be performed at a regional level rather than by 
each transmission provider individually.\317\
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    \315\ E.g., American Transmission, EEI, Progress Energy, and 
Southern.
    \316\ Entegra, however, replied to Southern's assertion that 
congestion studies can be misleading, stating that congestion 
studies did not need to be misleading, and were, on the contrary, 
necessary for customers to assess the costs of managing versus 
eliminating congestion.
    \317\ E.g., Imperial, MidAmerican, Nevada Companies, 
NorthWestern, Pinnacle, Salt River, SWAT, WestConnect, and Xcel.
---------------------------------------------------------------------------

    532. The EEI position is representative of entities calling for 
elimination of the congestion study principle. EEI asserts that these 
studies in large part would be duplicative of the studies being 
performed by DOE pursuant to EPAct 2005.\318\ EEI also argues that 
these studies would be costly and time-consuming and that transmission 
providers generally do not have access to information needed for cost 
impact analysis and consequently cannot assess the cost of 
constraints.\319\ TDU Systems assert on reply that it is difficult to 
imagine that providers do not have the information needed or means to 
determine the location and magnitude of congestion on their systems, 
since they perform this function for themselves already. TDU Systems 
add that customers will readily provide any information needed for 
congestion studies, as it is in their interest to do so. APPA believes 
that customers should be expressly required to produce information to 
help determine the cost of congestion (e.g., the additional cost to 
them of running or purchasing more expensive generation). TDU Systems 
also argues that the distinction between economic and reliability 
upgrades is a fiction and should be disregarded.
---------------------------------------------------------------------------

    \318\ Others assert that the DOE studies will be useful but not 
necessarily duplicative of the congestion study principle. E.g., 
APPA and Salt River.
    \319\ Bonneville agrees that the costs of congestion itself are 
not readily available to transmission providers and that customers 
are better positioned to determine this.
---------------------------------------------------------------------------

    533. In the Western Interconnection, entities maintain that WECC 
will be performing congestion studies that should meet the requirement. 
As a result, they assert that this principle should not be applied to 
individual transmission providers in the West, but that these providers 
should be permitted to meet the principle through the interconnection-
wide congestion studies conducted by WECC. Tacoma notes that 
ColumbiaGrid is considering the

[[Page 12333]]

services it can offer in congestion assessment at the sub-regional 
level in the Northwest. Other commenters, such as California 
Commission, Salt River, and Seattle, support a congestion studies 
requirement but believe it should not be required annually but rather 
biennially or triennially.
    534. In the Eastern Interconnection, RTOs and ISOs, and entities in 
RTOs and ISOs, believe congestion studies are not needed where LMP 
markets are in place or are satisfied by RTO or ISO studies.\320\ 
Entergy argues that the congestion studies that will be performed by 
its independent coordinator of transmission should meet this 
requirement.
---------------------------------------------------------------------------

    \320\ E.g., Allegheny, FirstEnergy, Indianapolis Power, and 
PSEG.
---------------------------------------------------------------------------

Determining ``Significant and Recurring'' Congestion
    535. A variety of commenters provide suggestions as to what 
constitutes ``significant and recurring'' congestion. TDU Systems 
believe that there should be a presumption of congestion if a 
transmission provider posts zero ATC. TDU Systems, APPA, and Bonneville 
believe that other indications of significant and recurring congestion 
include the need for frequent generation redispatch, frequent 
curtailments for reasons other than force majeure, and repeated denials 
of requests for firm transmission service. California Commission and 
CREPC suggest a similar approach based on a comparison of ATC and 
schedules with historical flows and an assessment of denied requests, 
but emphasize that the process should be forward-looking as well.
    536. APPA suggests the use of metrics to measure congestion (e.g., 
reporting on all congestion costs that exceed five percent of base 
energy costs and five percent of the hours in a season). California 
Commission also suggests the use of metrics, but cautions that there 
may be East-West differences. Sacramento stresses that such metrics 
should depend on whether the system being studied uses LMP or physical 
rights. In its view, financial metrics are most useful in LMP markets, 
while congestion in physical markets should be determined by paths that 
have been derated by a material percent of their nominal rating over a 
certain number of hours in a season.
    537. Santa Clara suggests that significant and recurring congestion 
exists when congestion costs over a given path during the high use 
season approach or exceed the depreciation plus other fixed costs on 
the new facilities that would eliminate congestion on the path. 
Additionally, Santa Clara emphasizes that if, redispatch is necessary 
on an ongoing basis, this should be taken as an indication that new 
facilities need to be built.
    538. New York Commission urges the Commission to utilize NYISO's 
process for measuring historical congestion--defined as the short-run 
production (i.e., dispatch) costs that could be avoided by system 
enhancements, as this represents the savings to society compared to the 
cost to society of investing in the system enhancement. New York 
Commission also cautions the Commission against using analyses focused 
on the impacts of transmission investments on wholesale energy prices, 
because these energy price impacts may be temporary and offset by 
changes in generation investments. TDU Systems and Old Dominion stress 
that in PJM significant and recurring congestion should be based on 
total gross congestion and not the much smaller and unrealistic measure 
of unhedgeable congestion, as this masks the economic reality that 
congestion itself has an economic cost.\321\
---------------------------------------------------------------------------

    \321\ See also Indicated Parties Reply.
---------------------------------------------------------------------------

    539. The Organizations of MISO and PJM States do not believe the 
Final Rule should address criteria for determining significant and 
recurring congestion, but should require each transmission provider to 
file criteria for inclusion and cost responsibility for upgrades that 
are included in the transmission plan to remedy congestion.
    540. Seattle asserts that current OASIS standards do not support 
consistent tracking of service denials and that this inhibits the 
evaluation of congestion. Seattle also points out that the costs of 
congestion may be difficult to quantify because reliability dispatch is 
a reactive tool used only after service requests have been denied and 
prescheduled limits imposed and, therefore, foregone transactions will 
not be known to the transmission provider.
    541. Ohio Power Siting Board asserts that distributed generation, 
demand response, and new technologies should be available to relieve 
congestion until longer-term solutions can be implemented.
Commission Determination
    542. The Commission adopts the NOPR proposal and retains a 
congestion study principle as part of the Final Rule's transmission 
planning process; however, we modify and clarify the principle in 
certain important respects in response to the comments received. At the 
outset, we wish to clarify that our primary objective in adopting this 
principle is to ensure that the transmission planning process 
encompasses more than reliability considerations. Although planning to 
maintain reliability is a critical priority, it is not the only one. 
Planning involves both reliability and economic considerations. When 
planning to serve native load customers, a prudent vertically 
integrated transmission provider will plan not only to maintain 
reliability, but also consider whether transmission upgrades or other 
investments can reduce the overall costs of serving native load. Such 
upgrades can, for example, reduce congestion (redispatch) costs or 
integrate efficient new resources (including demand resources) and new 
or growing loads. Thus, to represent good utility practice and provide 
comparable service, the transmission planning process under the pro 
forma OATT must consider both reliability and economic considerations. 
The purpose of this principle is to ensure that the latter is 
considered adequately in the transmission planning process.
    543. Some commenters argue that economic upgrades should be 
considered only in the context of individual requests for service under 
the pro forma OATT. The Commission disagrees. The process for 
addressing individual requests for service under the pro forma OATT is 
adequate for customers who request specific transmission rights to 
purchase power from a particular resource in a particular location 
during a defined time period. However, it does not provide an 
opportunity for customers to consider whether potential upgrades or 
other investments could reduce congestion costs or otherwise integrate 
new resources on an aggregated or regional basis outside of a specific 
request for interconnection or transmission service. It thus limits, 
for example, groups of customers from considering more comprehensive 
solutions to transmission congestion, including investment in demand 
response. It also limits multiple LSEs from considering, on a more 
aggregated basis, whether particular upgrades may represent the most 
economic means of integrating new generation resources (e.g., wind 
resources) located in a common area that could be accessed by many 
customers. The Commission believes such coordinated studies can, for 
system planning purposes, be more beneficial than studies performed on 
a request-by-request basis. We also find that they are consistent with 
the requirement to provide comparable service.

[[Page 12334]]

Transmission providers are not limited, in serving native load 
customers, to studying potential transmission upgrades only in the 
context of specific requests for service under the pro forma OATT.
    544. Some transmission providers appear to object to this principle 
because they fear that an obligation to study potential upgrades is 
equivalent to an obligation to fund or build such upgrades. We clarify 
that this is not the intent of this principle. There is a difference 
between a planning process that is coordinated and open and one that 
dictates construction and cost responsibility. Both considerations are 
important, but, as we explain above, they are distinct. The purpose of 
this principle is to ensure that customers may request studies that 
evaluate potential upgrades or other investments that could reduce 
congestion or integrate new resources and loads on an aggregated or 
regional basis (e.g., wind developers), not to assign cost 
responsibility for those investments or otherwise determine whether 
they should be implemented. The issue of cost allocation is addressed 
in Principle No. 9 below.
    545. The Commission also disagrees with the contentions of certain 
RTOs or ISOs that they need not comply with this principle. Although 
RTO and ISO planning processes tend to be more open and coordinated 
than the processes used by vertically-integrated transmission 
providers, this does not mean that RTO or ISO processes adequately 
address, in all circumstances, investments that are primarily economic 
in nature. When many RTO and ISO planning processes were created, they 
focused primarily on system enhancements necessary to maintain 
reliability. However, in recent years, as congestion has increased and 
generation reserve margins have declined, many RTOs and ISOs have taken 
increasingly progressive steps to identify investments that could 
reduce congestion and/or integrate new resources. For example, we 
recently approved a proposal by PJM to significantly enhance its RTEP 
planning process.\322\ We applaud these efforts as consistent with the 
direction of the reforms adopted herein. However, we decline to provide 
a blanket exception for RTOs and ISOs. Each RTO or ISO must show that 
its planning process is consistent with or superior to the requirements 
of the Final Rule in all respects.
---------------------------------------------------------------------------

    \322\ See PJM Interconnection, L.L.C., 117 FERC ] 61,218 (2006), 
reh'g pending.
---------------------------------------------------------------------------

    546. Some commenters express concern that this principle may result 
in costly congestion studies that are of little interest or value to 
customers. Our intent is not to impose a costly study requirement that 
is unrelated to the real-world concerns of consumers. In the NOPR, we 
sought comment on whether specific metrics (e.g., zero ATC or TLR 
frequency) should be used to trigger the congestion study requirement. 
After considering the comments on this topic, we do not believe that 
any single metric, or group of metrics, is adequate for that purpose. 
Relying on discrete metrics in this instance would risk both over- and 
under-inclusiveness--i.e., triggering too many studies, thereby 
imposing cost burdens on transmission providers that are not 
appropriate, or triggering too few studies, thereby omitting important 
studies that could help customers identify cost-effective solutions to 
congestion. Additionally, we direct transmission providers, in 
consultation with their stakeholders during development of their 
Attachment K compliance filings (as discussed above), to develop a 
means to allow the transmission provider and stakeholders to cluster or 
batch requests for economic planning studies so that the transmission 
provider may perform the studies in the most efficient manner. We will 
also require the requests for economic planning studies, as well as the 
responses to the requests, be posted on the transmission provider's 
OASIS or Web site, subject to confidentiality requirements.
    547. The Commission will modify the principle to allow customers to 
choose the studies that are of the greatest value to them. 
Specifically, we are modifying the principle to require that 
stakeholders be given the right to request a defined number of high 
priority studies annually (e.g., five to ten studies) \323\ to address 
congestion and/or the integration of new resources or loads. The intent 
of this approach is to allow customers, not the transmission provider, 
to identify those portions of the transmission system where they have 
encountered transmission problems due to congestion or whether they 
believe upgrades and other investments may be necessary to reduce 
congestion and to integrate new resources. The customers should be able 
to request that the transmission provider study enhancements that could 
reduce such congestion or integrate new resources on an aggregated or 
regional basis without having to submit a specific request for service. 
This approach ensures that the economic studies required under this 
principle are focused on customer needs and concerns, not 
administratively determined metrics that may bear no necessary relation 
to those concerns. Once such studies are requested, the transmission 
provider would conduct the studies, including appropriate sensitivity 
analyses, in a manner that is open and coordinated with the affected 
stakeholders. The cost of the defined number of high priority studies 
would be recovered as part of the overall pro forma OATT cost of 
service.\324\ By limiting this principle to a defined number of high 
priority studies annually, we are not precluding stakeholders from 
requesting additional studies. However, to provide appropriate 
financial incentives, the stakeholder(s) requesting these additional 
studies would be responsible for paying the cost of such studies.
---------------------------------------------------------------------------

    \323\ The example of five to ten studies mentioned in this Final 
Rule is merely illustrative. We recognize that the facts of each 
case will be used to determine the number of high priority studies 
allowed under a transmission plan.
    \324\ This cost recovery mechanism is comparable and 
nondiscriminatory because the transmission provider already has the 
ability to include in its pro forma OATT rates the cost of service 
associated with studies performed on behalf of native load 
customers.
---------------------------------------------------------------------------

    548. We also will modify this principle with respect to the scope 
of the studies being performed. The Commission proposed in the NOPR 
that the studies address ``significant and recurring congestion.'' 
However, the Commission also sought comment on whether, in addition, 
the study process should address upgrades associated with new 
generation resources and provide information needed to proactively 
evaluate such resources. We discuss the comments on this proposal in 
more detail below, but, as described therein, we agree that the study 
process should incorporate such considerations. We therefore modify 
Principle No. 8 to encompass the study of upgrades to integrate new 
generation resources or loads on an aggregated or regional basis. This 
is appropriate because congestion can limit both the efficient dispatch 
of existing generation resources as well as inhibit the development of 
new supply and demand resources. Moreover, many regions of the country 
must make investments in the near future to meet load growth and, 
accordingly, studies of the most economic means of making such 
investments are critically important to consumers.
    549. By expanding the scope of this principle, we do not intend to 
supplant the existing process for individual customers to integrate new 
resources or loads through specific requests for

[[Page 12335]]

interconnection or transmission service under the pro forma OATT. 
Rather, we contemplate that any such studies conducted pursuant to this 
principle, as explained above, would be for purposes of planning for 
the alleviation of congestion through integration of new supply and 
demand resources into the regional transmission grid or expanding the 
regional transmission grid in a manner that can benefit large numbers 
of customers, such as by evaluating transmission upgrades necessary to 
connect major new areas of generation resources (such as areas that can 
support substantial wind generation). Specific requests for service 
would continue to be studied pursuant to existing pro forma OATT 
processes.
    550. With respect to studying the cost of congestion, several 
transmission providers argue that they do not have access to 
information regarding generation costs either from their merchant 
function or unaffiliated customers. We agree that the transmission 
provider should be obligated to study the cost of congestion only to 
the extent it has information to do so. We make clear, however, that if 
stakeholders request that a particular congested area be studied, they 
must supply relevant data within their possession to enable the 
transmission provider to calculate the level of congestion costs that 
is occurring or is likely to occur in the near future. To the extent 
that the transmission provider's merchant function possesses such 
information (e.g., redispatch cost information), it must provide that 
information to the extent necessary to conduct such studies. Providing 
for confidential treatment and application of the Standards of Conduct, 
as discussed above, will give assurance to customers that their cost 
and other information will not be used improperly. To that end, we 
direct transmission providers to clearly define the information sharing 
obligations placed on customers in the planning attachment to their pro 
forma OATT.
    551. In response to those commenters that argue that regional 
congestion studies should be sufficient, we agree that regional 
congestion studies can be used as part of regional transmission 
planning processes required by this Final Rule. For example, to the 
extent the DOE has extensively studied congestion in certain broad 
areas, it is not necessary or appropriate for transmission providers to 
duplicate these studies. However, regional studies typically provide 
broad information on overall regional power flows and may not provide 
sufficient detail on local system conditions and congestion, such as 
detail on congested local facilities that may limit customer supply 
options, or detail on local conditions where additional service could 
be provided through redispatch. Moreover, although the DOE may identify 
areas where congestion exists or new generation may be developed, the 
purpose of DOE congestion studies is not to develop specific 
transmission system plans to remedy such congestion or integrate such 
resources. The DOE studies are therefore not a substitute for a more 
open and coordinated planning process to address specific upgrades that 
could reduce congestion or integrate new resources and loads. We 
therefore require each transmission provider to comply with the revised 
economic planning studies principle in this Final Rule both as to its 
own transmission system and as to the regional planning process 
described above.
i. Cost Allocation for New Projects
    552. In the NOPR, the Commission asked for comment on whether there 
should be a requirement for public utilities to develop cost allocation 
principles to address the recovery of costs associated with new 
transmission projects. In particular, the Commission asked whether the 
development of specific cost allocation principles would provide 
greater certainty and hence support the construction of new 
infrastructure or whether cost allocation is better handled on a case-
by-case basis.
Comments
    553. Several commenters express concern that the Final Rule not 
reopen cost allocation principles in RTOs and ISOs or in the OATTs of 
vertically integrated transmission providers.\325\ Duke argues that the 
Final Rule should not address cost allocation for new transmission at 
all, stating that transmission pricing should be evaluated in a 
separate proceeding. Other commenters agree that cost allocation issues 
should be handled on a case-by-case basis.\326\
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    \325\ E.g., Duke, EEI, ELCON, ISO/RTO Council, MISO Transmission 
Owners, SCE, and Southern.
    \326\ E.g., APPA, Arkansas Commission, PGP, Santee Cooper, 
Southwestern Coop, and Sacramento.
---------------------------------------------------------------------------

    554. Some commenters urge the Commission to define cost allocation 
principles in this proceeding.\327\ For example, E.ON believes that the 
cost of upgrades should be directly allocated to parties benefiting 
from an expansion and proposes that the host transmission owner should 
coordinate and be responsible for obtaining funding. Many transmission 
customers, however, support rolled-in cost recovery for network 
upgrades.\328\ TDU Systems ask the Commission to clarify that direct 
assignment of facility upgrade costs only applies to point-to-point 
service, unless it is being used for the delivery of designated network 
resources to serve network load. If direct assignment is retained, TDU 
Systems suggest the Commission consider standardizing directly 
assignable facilities on a regional basis and stress that the critical 
factor is comparability. TAPS suggests ``regional'' cost-spreading for 
backbone high voltage facilities and criticizes participant funding 
because it encourages would-be beneficiaries to wait and hope that 
others will step forward first.
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    \327\ E.g., E.ON, National Grid and WIRES.
    \328\ E.g., AWEA, NCEMC, NCPA, NRECA, Seattle, and TDU Systems.
---------------------------------------------------------------------------

    555. Old Dominion emphasizes the need for cross-border transmission 
cost allocation mechanisms. In joint projects, Salt River emphasizes 
that it is inconsistent with an open season approach to assign benefits 
to a party and then assign cost responsibility beyond what the project 
participant would voluntarily assume based on the subscription rights 
received. Both Bonneville and TVA believe that cost allocation 
principles should be based on a determination of beneficiaries and cost 
causation. New Mexico Attorney General stresses that cost recovery for 
construction of transmission intended for wholesale or market 
transactions should not be allocated to native load. NCPA states that 
it would expect some Commission deference to recovery of costs of 
projects identified in a truly collaborative process.
    556. At the October 12 Technical Conference, PJM stated that the 
Commission should provide generic guidance on what would be acceptable 
regarding cost allocation, though Progress Energy did not favor putting 
a cost allocation approach in the pro forma OATT, as modified by the 
Final Rule. National Grid expressed the view that the Commission would 
need to address cost allocation generally, arguing that cost allocation 
solely on a project-by-project basis is inefficient.
Commission Determination
    557. The Commission finds, after considering the comments, that it 
is appropriate to include a specific principle regarding cost 
allocation. The manner in which the costs of new transmission are 
allocated is critical to the development of new infrastructure. 
Transmission providers and customers cannot be expected to support the

[[Page 12336]]

construction of new transmission unless they understand who will pay 
the associated costs. We therefore find that, for a planning process to 
comply with the Final Rule, it must address the allocation of costs of 
new facilities.
    558. The Commission emphasizes, however, that we are not modifying 
the existing mechanisms to allocate costs for projects that are 
constructed by a single transmission owner and billed under existing 
rate structures. Our intent is not to upset existing cost allocation 
methods applicable to specific requests for interconnection or 
transmission service under the pro forma OATT. The cost allocation 
principle discussed herein is intended to apply to projects that do not 
fit under the existing structure, such as regional projects involving 
several transmission owners or economic projects that are identified 
through the study process described above, rather than through 
individual requests for service. We will not impose a particular 
allocation method for such projects, but rather will permit 
transmission providers and stakeholders to determine their own specific 
criteria which best fit their own experience and regional needs. The 
proposal should identify the types of new projects that are not covered 
under existing cost allocation rules and, therefore, would be affected 
by this cost allocation principle.
    559. Although the Commission does not prescribe any specific cost 
allocation method in the Final Rule, we believe some overall guidance 
is appropriate. Our decisions regarding transmission cost allocation 
reflect the premise that ``[a]llocation of costs is not a matter for 
the slide-rule. It involves judgment on a myriad of facts. It has no 
claim to an exact science.'' \329\ We therefore allow regional 
flexibility in cost allocation and, when considering a dispute over 
cost allocation, exercise our judgment by weighing several factors. 
First, we consider whether a cost allocation proposal fairly assigns 
costs among participants, including those who cause them to be incurred 
and those who otherwise benefit from them. Second, we consider whether 
a cost allocation proposal provides adequate incentives to construct 
new transmission. Third, we consider whether the proposal is generally 
supported by State authorities and participants across the region.
---------------------------------------------------------------------------

    \329\ Colorado Interstate Gas Co. v. FPC, 324 U.S. 581, 589 
(1945).
---------------------------------------------------------------------------

    560. These three factors are interrelated. For example, a cost 
allocation proposal that has broad support across a region is more 
likely to provide adequate incentives to construct new infrastructure 
than one that does not. The states, which have primary transmission 
siting authority, may be reluctant to site regional transmission 
projects if they believe the costs are not being allocated fairly. 
Similarly, a proposal that allocates costs fairly to participants who 
benefit from them is more likely to support new investment than one 
that does not. Adequate financial support for major new transmission 
projects may not be obtained unless costs are assigned fairly to those 
who benefit from the project.
    561. These factors are particularly important as applied to the 
economic upgrades discussed above--e.g., upgrades to reduce congestion 
or enable groups of customers to access new generation. As a general 
matter, we believe that the beneficiaries of any such project should 
agree to support the costs of such projects. However, we recognize that 
there are free rider problems associated with new transmission 
investment, such that customers who do not agree to support a 
particular project may nonetheless receive substantial benefits from 
it. In the past, different regions have attempted to address such 
issues in a variety of ways, such as by assigning transmission rights 
only to those who financially support a project or spreading a portion 
of the cost of certain high-voltage projects more broadly than the 
immediate beneficiary/supporters of the project. We believe that a 
range of solutions to this problem are available. We therefore continue 
to believe that regional solutions that garner the support of 
stakeholders, including affected State authorities, are preferable. 
Moreover, it is important that each region address these issues up 
front, at least in principle, rather than having them relitigated each 
time a project is proposed. Participants seeking to support new 
transmission investment need some degree of certainty regarding cost 
allocation to pursue such investments.
3. Additional Issues Relating to Planning Reform
a. Independent Third Party Coordinator
    562. In the NOPR, the Commission acknowledged that an independent 
third party coordinator would provide benefits for transmission 
planning, but did not propose to require independence. Noting that 
independence could take many forms, the Commission sought comment on 
the level of independence that could provide benefits and the 
institutions that could offer such independence.
Comments
    563. Overall comments on the use of an independent third party to 
oversee or coordinate the planning process range from those who believe 
it is not needed to those who feel that it should be required rather 
than merely encouraged. Arguing against the need for an independent 
coordinator, South Carolina E&G does not believe an independent third 
party is either necessary or desirable. Arguing in favor of an 
independent coordinator, EPSA strongly supports independent oversight 
and believes that third party oversight will be necessary in non-RTO 
areas, particularly where transmission providers have conducted non-
transparent processes.\330\ Most commenters fall somewhere between 
these two positions, finding potential benefits in independence but 
concurring with the proposal not to mandate it.
---------------------------------------------------------------------------

    \330\ See also AWEA, Arkansas Commission, Old Dominion, and 
Project for Sustainable FERC Energy Policy. Old Dominion stresses 
that even in RTOs, the transmission owners may have the ability to 
exercise market power and, therefore, the market monitoring unit 
should have the requisite independence and authority to investigate 
and address undue influence.
---------------------------------------------------------------------------

    564. Several public utility commenters acknowledge the potential 
benefits of using an independent coordinator and believe the Commission 
should encourage it.\331\ National Grid, for example, finds it 
difficult to see how a non-independent transmission provider would be 
able to manage confidential information in a manner fair to all 
stakeholders and recommends finding independent administration of 
planning ``superior to'' non-independent administration. Other 
commenters note only that independence can be beneficial or suggest 
that the Commission be open to independent third parties when 
offered.\332\ Progress agrees there can be benefits, but does not 
believe an independent coordinator is needed to ensure confidence.
---------------------------------------------------------------------------

    \331\ E.g., National Grid, PPL, Constellation, and Tacoma.
    \332\ E.g., APPA, Bonneville, California Commission, Duke, 
Indianapolis Power, NCEMC, NorthWestern, Progress Energy, CREPC, 
Sacramento, Seattle, and TDU Systems. Some public power entities, 
such as APPA, NRECA, and TDU Systems are concerned with ensuring 
that the costs of an independent coordinator do not outweigh the 
benefits.
---------------------------------------------------------------------------

    565. EEI argues against an independence requirement, seeing no need 
to require non-RTO/ISO transmission providers to engage independent 
third parties to oversee the planning process.\333\ EEI believes the

[[Page 12337]]

planning processes proposed in the NOPR are adequate without third 
party oversight and maintains that requiring third party coordination 
could add another layer of administration, might encroach on State 
authority, and could create the possibility that the transmission 
provider would lose control of the transmission plan. EEI however also 
notes that the Commission could require independent oversight in 
circumstances where a transmission planner has failed to implement the 
principles or has engaged in undue discrimination in planning for 
customer needs.
---------------------------------------------------------------------------

    \333\ TVA believes that the levels of independence practiced in 
NERC and NAESB and the implementation and administration of those 
standards by the regional entitities (such as SERC) are adequate and 
appropriate.
---------------------------------------------------------------------------

    566. The consensus at the October 12 Technical Conference was 
generally supportive of the potential benefits of an independent 
facilitator, but not supportive of a mandate. There was general support 
for the idea that an independent facilitator can assist with handling 
sensitive information and provide confidence that analysis of 
information would be fair, although several participants stated that 
sufficient trust and confidence could be obtained without an 
independent facilitator.
Commission Determination
    567. The Commission adopts the NOPR proposal to not require the use 
of an independent third party coordinator at this time. We agree that 
there are benefits to be gained from independent third party oversight, 
as cited by commenters, such as the ability to manage confidential 
information and the ability to ensure equitable treatment of all 
viewpoints in planning. We therefore encourage transmission providers 
and their customers and other stakeholders to explore aspects of 
planning where the use of an independent coordinator would be 
beneficial and to incorporate those aspects in their planning process 
compliance filings.
    568. It is, however, possible to comply with the principles without 
the use of an independent third party. We expect the transmission plans 
themselves to be developed under an open process that includes 
coordination among each transmission provider, its customers, other 
stakeholders, and its neighbors. A transmission provider will need to 
demonstrate to us in a compliance filing that the plan meets the 
principles, including providing a dispute resolution process. We 
believe that an open, transparent planning process, with meaningful 
coordination and dispute resolution, will provide a sufficient basis 
for customers to identify and raise meaningful concerns if a plan does 
not treat similarly-situated customers in a comparable manner, where 
planning appears to be conducted in a discriminatory manner, or in 
other instances where the independence of planning may be in question. 
If disputes do arise in these areas and cannot be resolved 
consensually, we are available to either encourage a consensual 
resolution (e.g., by use of the Dispute Resolution Service) or resolve 
them ourselves if a complaint is filed.
b. State Commission Participation
    569. In the NOPR, the Commission strongly encouraged the 
participation of State commissions and other State agencies in the 
coordinated planning process, particularly with regard to regional 
planning. The Commission sought comment on how best to accommodate 
effective State participation.
Comments
    570. All commenters addressing the question of State participation 
agree that states have an important role in transmission planning, but 
there were only limited comments recommending specific processes to 
encourage State participation. Supporters of State participation 
generally believe that it can assist in obtaining siting approval and 
in cost recovery. ISO/RTO Council and individual RTOs and ISOs point to 
their current processes for including states in their region in the 
planning process. Noting the local benefits that can derive from 
interstate transmission projects, American Transmission supports 
collaborative efforts among states such as the Organization of MISO 
States. However, American Transmission and other commenters suggest 
that the Commission defer to the states to determine how they 
participate in the planning process.\334\
---------------------------------------------------------------------------

    \334\ E.g., American Transmission, Duke, and Progress Energy.
---------------------------------------------------------------------------

    571. Allegheny believes it should be the responsibility of the 
transmission provider to maintain good communication with State 
commissions. Nevada Companies assert that the real question the 
Commission should be posing is how to coordinate the State 
jurisdictional role in transmission planning and construction and the 
obligations imposed by the Commission on transmission providers, so 
that the system of coordination does not put transmission providers in 
the middle between conflicting State and Commission requirements. 
Moreover, Santa Clara notes that some State commissions do not 
represent all energy consumers, since they are charged only with 
regulating public utilities, and could be conflicted and disinclined to 
act in the best interests of entities not under their jurisdiction.
    572. NARUC supports active State commission participation in both 
RTO and non-RTO markets.\335\ NARUC asks that the Commission clarify 
that its planning proposals assume that the results of State commission 
planning decisions relating to retail load will be incorporated into 
the planning process rather than subject to further review. NARUC and 
New Mexico Attorney General also ask for clarification that joint 
planning will allow for communications between resource and 
transmission planners for the purpose of developing State-required 
resource plans and that this will not be considered a violation of the 
Standards of Conduct. PNM-TNMP and Southern support the NARUC position 
in their reply comments.
---------------------------------------------------------------------------

    \335\ Similar views are expressed by APPA, Arkansas Commission, 
Bonneville, California Commission, NCEMC, NYAPP, and CREPC. NYAPP, 
however, asks the Commission to be vigilant in not allowing State 
commissions improper control over the planning process.
---------------------------------------------------------------------------

    573. New York Commission wants to ensure that the Commission's 
planning responsibilities cover only transmission that serves a bulk 
power system function.\336\ Florida Commission believes that it already 
has direct oversight of grid planning and related issues, through among 
other things its participation in the FRCC planning process and review 
of the annual Ten Year Site Plan. Seattle does not believe that any 
additional requirements are needed for State commission participation. 
Other commenters are concerned that State policy goals, such as 
California's Renewable Portfolio Standard, be included in the 
coordinated planning required by the Final Rule.\337\ NARUC and 
California Commission also discuss State staff and fiscal constraints 
on participation, and California Commission suggests that the 
Commission consider a tariff rider to fund State participation.
---------------------------------------------------------------------------

    \336\ NYAPP, on the other hand, urges the Commission to require 
planning for all transmission facilities, not just bulk power 
facilities.
    \337\ E.g., AWEA, California Commission, and Project for 
Sustainable FERC Energy Policy.
---------------------------------------------------------------------------

Commission Determination
    574. The Commission strongly encourages State participation in the 
transmission planning process and expects that all transmission 
providers will respect states' concerns, such as retail resource needs, 
in the planning

[[Page 12338]]

process.\338\ As with any other interested stakeholder, we emphasize 
that planning must be coordinated with relevant State regulators 
(including city councils, local siting boards, and other agencies) that 
wish to participate in the transmission provider's planning process. We 
will not prescribe a particular level of State participation, but 
rather encourage states to determine their own level of participation, 
consistent with applicable State law.\339\ We stress that State 
determinations with respect to retail load will not be second-guessed, 
but that once those determinations are incorporated into the 
transmission plan, the transmission planning principles will apply 
(e.g., for purposes of determining whether similarly-situated customers 
are treated comparably).
---------------------------------------------------------------------------

    \338\ As noted above, we expect the concerns of NARUC and others 
that the application of the Commission's Standards of Conduct are 
inhibiting State resource planning will be addressed in the 
rulemaking proceeding on the Standards of Conduct in Docket No. 
RM01-7-000. See supra note 257.
    \339\ We also recognize that there are concerns about how State 
regulators and other agencies will recover the costs associated with 
their participation in the planning process. As discussed below, we 
direct transmission providers to propose a mechanism for cost 
recovery in their planning compliance filings. These proposals 
should include relevant cost recovery for State regulators, to the 
extent requested.
---------------------------------------------------------------------------

    575. Just as we intend to coordinate with State regulators and 
other agencies, we also encourage those parties to collaborate amongst 
themselves as well, particularly regionally, in order to reach 
agreement on how best to review and approve new transmission facilities 
that are the product of the coordinated and regional planning process 
required by this Final Rule. We intend to defer to such agreements 
between State regulators and other agencies in a given region as 
appropriate. We are, moreover, sensitive to concerns, such as 
Allegheny's, about the overlapping nature of regulatory jurisdiction 
over planning matters. We believe the planning principles in this Final 
Rule will help alleviate this concern by facilitating coordination 
through open, transparent planning and enhanced exchange of 
information. We also understand Santa Clara's concern that certain 
State regulators do not represent all energy consumers in some states; 
however, we do not believe this detracts from the significant interest 
that State regulators and other agencies have with regard to 
transmission planning for their State and region.
c. Flexibility in Implementation and Examples of Compliant Processes
    576. In the NOPR, the Commission sought comment on how much 
flexibility the transmission provider should be given in implementing 
the principles and requested examples of transmission planning 
processes that comply with the proposed principles.
Comments
    577. Commenters generally favor flexibility and urge the Commission 
not to be too prescriptive regarding how the planning processes must 
satisfy the planning principles. Many entities in the Western 
Interconnection cite the overall WECC process as largely compliant with 
the principles. Nevada Companies notes that the WECC process works well 
under the existing pro forma OATT, so that few changes should be 
required to implement the proposal. In the East, Progress Energy and 
Duke cite NC Transmission Planning as an example of an effective 
planning process that generally meets the principles.
    578. Constellation agrees with providing flexibility, but believes 
the Commission should strongly encourage transmission providers to 
model their compliance filings after existing processes, such as those 
in RTOs and ISOs. ISO/RTO Council and all individual RTOs and ISOs 
argue that their processes are generally compliant and should not be 
disturbed. Transmission providers in RTOs and ISOs generally support 
this position.\340\
---------------------------------------------------------------------------

    \340\ E.g., Allegheny, Duke, and National Grid.
---------------------------------------------------------------------------

    579. Some entities believe that flexibility should be permitted in 
order to deal with regional variations, but that individual 
transmission providers should have limited flexibility in implementing 
the planning process.\341\ Some commenters simply state that regional 
flexibility should be permitted, without further elaboration.\342\ 
Other commenters urge the Commission to limit both regional and local 
flexibility.\343\
---------------------------------------------------------------------------

    \341\ E.g., APPA, East Texas Cooperatives, Seattle, and TDU 
Systems.
    \342\ E.g., Bonneville, Salt River, PJM, and TVA.
    \343\ E.g., Arkansas Municipal, Project for Sustainable FERC 
Energy Policy, and Southwestern Coop.
---------------------------------------------------------------------------

    580. NRG argues that system planning models should reflect economic 
dispatch to facilitate efficient utilization and also argues in favor 
of requirements for specific criteria on the treatment of system 
overloads and contingencies. AWEA proposes a specific regional planning 
protocol patterned off the ``Collaborative Governance'' model developed 
during mediation for the Southeast RTO in Docket No. RT01-100.
    581. In reply to commenters arguing in favor of less flexibility, 
Indianapolis Power maintains that its experience in MISO shows that 
flexibility is needed, citing the wide variations within the MISO 
footprint and the difficulties experienced in planning for a single 
large region. MidAmerican opposes the NRG proposal for regional 
modeling standards, as well as the AWEA proposal for a regional 
planning protocol, as too burdensome. Exelon expresses general 
agreement with the EEI position on flexibility, but states that 
planning processes outside RTOs do not presently meet the NOPR's 
requirements. Exelon states planning processes outside RTOs should 
follow the planning direction of RTOs like PJM.
Commission Determination
    582. Although we allow flexibility in the development of a 
coordinated and regional planning process, the Commission will 
carefully review transmission planning compliance filings to ensure 
that each planning process is consistent with the planning principles 
and other requirements in this Final Rule. We encourage transmission 
providers to give consideration to existing planning processes, such as 
those already implemented by ISOs or RTOs, or those proposed by AWEA, 
as they work with their customers and other stakeholders to develop a 
transmission planning process that complies with the Final Rule. The 
Commission makes clear, however, that we do not endorse any specific 
existing process as a model for all transmission providers.
d. Recovery of Planning Costs
    583. In the NOPR, the Commission recognized that participants in 
the planning process must be assured of recovery of their costs 
incurred in the planning process, as well as assured that the costs 
will be borne equitably by all parties benefiting from the process. The 
Commission also sought comment on whether there should be a principle 
or requirement regarding cost recovery and allocation associated with 
funding the regional planning requirement.
Comments
    584. Public utility commenters generally support the principle that 
costs should be borne by the beneficiaries of the process. EEI agrees, 
but argues that the Commission should not establish a specific cost 
basis for recovery, and several other commenters concur.\344\ 
NorthWestern and PSEG support a cost causation principle for

[[Page 12339]]

allocation of costs of planning, and Southern argues that entities that 
request any transmission sensitivity studies should bear the costs of 
those studies.
---------------------------------------------------------------------------

    \344\ E.g., Duke, Indianapolis Power, MidAmerican, Progress 
Energy, PSEG, South Carolina E&G, and SPP.
---------------------------------------------------------------------------

    585. There is general agreement with the principle that costs 
should be recoverable, and some public utilities request that the 
Commission clarify that all planning costs not directly assigned are 
recoverable through transmission provider transmission rates.\345\ 
Other commenters believe that the parties in the planning process 
should determine how planning costs should be allocated and funded. 
APPA urges simplicity, the avoidance of double collecting (e.g., LSEs 
should not have to pay through both transmission rates and 
individually) and stresses the need to assess costs based on size and 
assets. Other comments are consistent with equitable allocation of 
planning costs.\346\
---------------------------------------------------------------------------

    \345\ E.g., Southern and South Carolina E&G.
    \346\ E.g., Bonneville, NRECA, and CREPC.
---------------------------------------------------------------------------

Commission Determination
    586. We will not propose a specific method for recovery and 
allocation of planning costs in this Final Rule. We recognize, however, 
the importance of planning cost recovery and will require transmission 
planning processes to provide a mechanism for recovery of costs. We 
direct transmission providers to work with other participants in the 
planning process, as part of the collaborative process described above, 
to develop their cost recovery proposals in order to determine whether 
all relevant parties, including State agencies, have the ability to 
recover the costs of participating in the planning process. 
Transmission providers should also consider whether mechanisms for 
regional cost recovery may be appropriate, such as through agreements 
(formal or informal) to incur and allocate costs jointly. The 
Commission will consider resulting cost recovery proposals, including 
special riders to transmission rates, with an eye toward encouraging 
the broadest participation in the planning process possible.
e. Open Season for Joint Ownership
    587. In the NOPR, the Commission expressed its belief that an open 
season to allow market participants to participate in joint ownership, 
particularly for large new transmission projects, could stimulate grid 
investment and ensure that all customers have the ability to 
participate in new projects on a nondiscriminatory basis. The 
Commission sought comment on whether to include such a requirement and, 
if so, what conditions or limitations should be associated with it.
Comments
    588. As a general matter, a number of commenters believe that the 
planning process should include a mandate to construct identified 
upgrades or otherwise hold transmission providers accountable for 
carrying out the plan.\347\ EEI and others argue that such a mandate 
would go beyond planning and result in providers giving up control of 
their systems. In their replies, LPPC and Sacramento assert that the 
decision to build facilities and to carry out transmission plans must 
rest with transmission providers and State authorities and that, in any 
event, it is unclear that the Commission has the authority to compel 
construction pursuant to regional transmission plans. At the October 12 
Technical Conference, there was considerable discussion of the 
obligation to build and its relationship to the planning process 
proposed in the NOPR.
---------------------------------------------------------------------------

    \347\ E.g., APPA, East Texas Cooperatives Reply, FMPA, NCPA, 
TAPS, TDU Systems, Utah Municipals, and WIRES.
---------------------------------------------------------------------------

    589. While not necessarily opposed to voluntary joint ownership 
arrangements in general, many commenters oppose the idea of mandated 
open seasons.\348\ EEI provides a representative summary of the 
arguments of those opposed to open seasons. First, EEI argues that the 
Commission does not have the authority to order joint ownership and 
that joint ownership could interfere with State siting authority. It 
maintains that the instances where the Commission can order 
transmission construction are very limited and do not extend to the 
authority to order joint ownership.\349\ Second, EEI argues that joint 
ownership will not provide the benefits cited by the Commission, 
stating that there is ample evidence that joint ownership of 
transmission lines is not needed to achieve economies of scale in 
construction. In its view, the level of transmission investment is 
currently increasing and joint ownership should not be expected to 
create additional sources of transmission investment. Third, EEI 
contends that prospective joint owners mistakenly believe they will not 
be subject to the same requirements as Commission-jurisdictional owners 
and urge the Commission to make clear that both jurisdictional and 
nonjurisdictional owners would be subject to the same requirements for 
service over jointly-owned facilities. If the Commission were to order 
joint ownership, Duke argues that it must condition such ownership by a 
nonjurisdictional entity on that entity filing a safe harbor OATT 
ensuring reciprocal open access by that joint owner.
---------------------------------------------------------------------------

    \348\ E.g., Allegheny, American Transmission, Constellation, New 
York Transmission Owners, MidAmerican, Duke, EEI, Entergy, 
FirstEnergy, MISO, National Grid, Northeast Utilities, NorthWestern, 
Progress Energy, PSEG, South Carolina E&G, SCE, Southern, SPP, 
Tacoma, Tucson, and Xcel.
    \349\ APPA, FMPA, TAPS, and TDU Systems, however, point to 
various sources of authority on which the Commission could rely to 
mandate open seasons and joint ownership, such as: To remedy undue 
discrimination under FPA sections 205 and 206; to carry out FPA 
section 214(b)(4)'s requirement to facilitate the planning and 
expansion of transmission facilities to satisfy the needs of load-
serving entities; as a condition of market-based rate authority, FPA 
section 203 approval, or transmission rate incentives under FPA 
section 219; and under the permitting regulations promulgated under 
FPA section 216(c)(2)(B) dealing with backstop siting authority.
---------------------------------------------------------------------------

    590. Tacoma notes that ColumbiaGrid includes a mechanism for small 
users to participate in transmission projects in the proposal it is 
considering for its planning process. Xcel supports adopting the open 
season concept as an option in joint planning requirements. Though it 
does not completely oppose the principle, MidAmerican sees significant 
practical problems in developing and implementing an open season 
proposal and regards the open season idea as premature. Others 
generally support allowing for open seasons and joint ownership, but 
also do not believe they should be mandated.\350\
---------------------------------------------------------------------------

    \350\ E.g., Bonneville, California Commission, and CREPC. 
Bonneville stresses that any jointly-owned facilities should have a 
single operator.
---------------------------------------------------------------------------

    591. A number of other commenters, however, support requiring open 
seasons as a method of ensuring that identified upgrades are 
constructed. ELCON is strongly in favor, stating that open seasons for 
joint ownership is an ``idea whose time has come'' and expressing 
frustration that the Commission has not already acted on this proposal. 
FMPA argues that joint ownership will aid in providing additional 
capital for transmission projects. TDU Systems urge the Commission to 
require transmission providers, including RTOs and ISOs, to hold open 
seasons.\351\ Joined by Arkansas Commission, TDU Systems argue that 
open seasons should not be limited to large projects. PGP supports open 
seasons when providers do not voluntarily agree to add capacity based 
on the results of the transmission plan. TDU Systems cite the Neptune 
and

[[Page 12340]]

Cross-Sound Cable projects, where regulated utilities failed to provide 
solutions despite the need for expansion of the system in those 
regions. Seattle argues that voluntary joint ownership of projects 
should not be contingent upon an open season requirement. TANC points 
to current joint ownership arrangements in the Western Interconnection. 
Sacramento likewise notes that the joint planning and ownership process 
in the Western Interconnection has been a success, but asks the 
Commission to make clear that physical rights set asides are available 
in CAISO to accommodate non-LMP co-owners.
---------------------------------------------------------------------------

    \351\ Similar comments were made by APPA, Arkansas Commission, 
FMPA (includes a legal analysis in an attachment), NCPA, MISO/PJM 
States, Santa Clara, Southwestern Coop, TANC, and TAPS.
---------------------------------------------------------------------------

    592. On reply, EEI, Entergy, and Southern repeat arguments against 
joint ownership and open seasons. EEI replies that FMPA's claim that 
joint ownership will result in increased investment is not based on 
fact and will not increase access. In its reply, TDU Systems states 
that joint ownership would not, as argued by EEI, infringe on State 
siting, as states would retain this authority over the jointly-
developed project. APPA also stresses that its members have fewer 
difficulties obtaining service where joint ownership is permitted. In 
their replies, Lassen, Santa Clara, and TANC argue that the Commission 
should not, as suggested by Duke, condition the participation of a 
nonjurisdictional entity in a jointly-owned project on that entity 
filing a safe harbor OATT, as public power entities use the capacity 
they need and sell the rest whether or not they have a safe harbor OATT 
on file. However, TAPS asks on reply that access to jointly-owned 
facilities be available through a pro forma OATT. Participants at the 
October 12 Technical Conference expressed both support for joint 
ownership, as well as caution. National Grid states that it has had 
good success with joint ownership, but that jointly-owned projects are 
more complicated and can take longer to develop.
Commission Determination
    593. The Commission believes there are benefits to joint ownership 
of transmission facilities, particularly large backbone facilities, 
both in terms of increasing opportunities for investment in the 
transmission grid, as well as ensuring nondiscriminatory access to the 
transmission grid by transmission customers. The comments received in 
response to the NOPR support the notion that joint ownership can 
provide these benefits in many cases. For example, as TDU Systems note, 
the Neptune and Cross-Sound Cable projects have resulted in significant 
amounts of new transmission capacity in regions facing chronic 
constraints. We encourage joint ownership for other large backbone 
transmission upgrades included in the transmission plan developed by 
the planning process required by this Final Rule.\352\
---------------------------------------------------------------------------

    \352\ As the Commission stated in Order No. 679-A, ``[t]he 
Commission will look favorably on incentive requests that include 
public power joint ownership.'' Order No. 679-A at P 102.
---------------------------------------------------------------------------

    594. We acknowledge, however, that joint ownership can increase the 
complexity of planning and developing a transmission project and are 
sensitive to concerns that formal open seasons can add to that 
complexity. We therefore do not mandate open season procedures to allow 
market participants to participate in joint ownership. We recognize 
that there may be reasons, given the complexity of the transmission 
grid and changing conditions of supply and demand for power, why any 
given facility identified in a transmission plan may not ultimately be 
constructed. Consequently, our planning reforms do not include an 
obligation to construct each facility identified in the plan, whether 
individually or through joint ownership mechanisms. At the same time, 
the Commission agrees that joint ownership may be useful in certain 
situations and encourages transmission providers and customers alike to 
consider the use of open seasons to realize construction of upgrades 
identified in the planning studies. If a transmission provider declines 
to construct an identified upgrade, we also encourage customers and 
third parties to consider, either individually or jointly, development 
and ownership of a project to the extent consistent with applicable 
State law.
f. Specific Study Processes Beyond Reliability and Congestion Reduction
    595. In the NOPR, the Commission sought comment on whether there 
should be a specific study process to identify opportunities to enhance 
the grid for purposes beyond maintaining reliability or reducing 
current congestion. Such a study process could allow interested 
entities, including State resource agencies and others, to request the 
transmission provider to model grid upgrades needed to accommodate the 
construction of new resources and provide information needed to 
proactively evaluate such resources. The Commission expected that such 
studies would not conflict with State prerogatives, but rather would 
provide states with better information to evaluate all relevant 
resource options.
Comments
    596. Most transmission provider commenters favor providing for 
study of some grid enhancement beyond reliability and congestion-
related needs, but believe the Final Rule should not mandate a specific 
study process. Various commenters argue that the Commission should 
allow planning participants to determine details such as the scope, 
number, and cost responsibility for the studies.\353\ MISO states that 
it is working on these issues, but enhancement beyond maintaining 
reliability or reducing congestion is a complicated subject best left 
to each RTO or ISO to decide.
---------------------------------------------------------------------------

    \353\ E.g., EEI, MISO, NorthWestern, PSEG, and Tacoma.
---------------------------------------------------------------------------

    597. Some commenters are more explicit or expansive in their 
recommendations. CAISO recommends that the Commission develop a policy 
to encourage construction of transmission lines necessary to connect 
renewable resources,\354\ and Suez Energy NA provides similar comments 
about new remote generation. PJM believes the planning process should 
look at future congestion and building for resources not yet announced. 
The New Jersey Board believes that demand-side management and other 
solutions, such as distributed renewable generation, also should be 
considered. WIRES and ELCON believe all credible proposals should be 
studied. TAPS asserts that planning should study grid enhancements 
needed for new potential resources.\355\ These views are consistent 
with the views of many of the commenters that support additional study 
processes.\356\ TDU Systems, however, point out that planning for 
reliability and economics should be incorporated into the open and 
inclusive planning process and, therefore, a special study process 
should not be needed.
---------------------------------------------------------------------------

    \354\ Related to this, California Commission asserts that 
regional planning processes need to be closely linked with the 
resource adequacy planning processes and renewable energy portfolio 
standards on the State level.
    \355\ EEI replies in opposition to TAPS' assertions that 
planning should address transmission for potential resources, 
arguing that such a requirement would be cost prohibitive and would 
harm users.
    \356\ E.g., APPA, Arkansas Commission, AWEA, CREPC, Sacramento, 
and Seattle.
---------------------------------------------------------------------------

    598. Other commenters are opposed to additional processes: South 
Carolina E&G does not see a need for additional studies; Southern 
believes additional study processes would be overly burdensome and 
would divert attention away from the fundamentals of prudent planning; 
and Bonneville notes that market participants often make requests

[[Page 12341]]

for expensive studies without following through on them. Santee Cooper 
cautions the Commission against giving license to those who would 
attempt to hijack the regional planning process in order to advance a 
generation-related agenda, and notes that the Commission's authority 
does not extend to generation resource adequacy.
Commission Determination
    599. We believe that development of a study process for identifying 
opportunities for grid enhancement beyond reliability and congestion 
reduction has the potential to provide useful information and would 
generally benefit development of the transmission grid. We therefore 
will include such study processes within the scope of Principle No. 8. 
In the NOPR, that principle concerned only congestion studies, but, as 
modified above, it now includes studies regarding upgrades that could 
integrate new generation resources. We note that various commenters 
argued for the consideration of demand resources in development of 
enhancements to the transmission grid.\357\ As we explain above, 
consideration of such resources falls within Principle No. 8, as 
modified by the Final Rule.
---------------------------------------------------------------------------

    \357\ E.g., New Jersey Board, Ohio Power Siting Board, and 
WIRES.
---------------------------------------------------------------------------

g. Level of Detail in the OATT
    600. In the NOPR, the Commission sought comment on the level of 
detail to be required to be in the transmission provider's OATT 
regarding its planning process.
Comments
    601. Several commenters argued that the details of the planning 
process should be included in the transmission providers' OATTs.\358\ 
Seattle noted that the OATT should balance the need for detailed 
planning requirements with the need for regional processes to evolve.
---------------------------------------------------------------------------

    \358\ E.g., APPA, NRECA, Old Dominion, and Seattle. APPA also 
suggests OASIS posting.
---------------------------------------------------------------------------

Commission Determination
    602. The Commission agrees that the transmission planning 
attachment to a transmission provider's OATT must include sufficient 
detail to enable transmission customers to understand the transmission 
provider's planning process. This new attachment must therefore 
include:
    (a) The process for consulting with customers and neighboring 
transmission providers;
    (b) The notice procedures and anticipated frequency of meetings or 
planning-related communications;
    (c) A written description of the methodology, criteria, and 
processes used to develop transmission plans;
    (d) The method of disclosure of transmission plans and related 
studies and the criteria, assumptions and data underlying those plans 
and studies;
    (e) The obligations of and methods for customers to submit data to 
the transmission provider;
    (f) The dispute resolution process;
    (g) The transmission provider's study procedures for economic 
upgrades to address congestion or the integration of new resources; and
    (h) the relevant cost allocation procedures or principles.
C. Transmission Pricing
1. General
    603. As the Commission explained in Order No. 888, the pro forma 
OATT was designed to include primarily non-rate terms and conditions of 
open access non-discriminatory transmission service. Transmission 
providers first were required to adopt the non-rate terms and 
conditions of the pro forma OATT and then, in a subsequent filing under 
FPA section 205, to propose corresponding rates for service provided 
under their OATTs. Consistent with the focus of Order No. 888 on the 
non-rate terms and conditions of open access, the Commission did not 
propose broad reform of transmission pricing policy through the NOPR. 
Rather, the Commission identified in the NOPR several discrete pricing 
rules that it considered part and parcel of OATT service that merit 
reform, which we discuss in more detail later in this section. The 
Commission also specifically noted in the NOPR that the purpose of this 
rulemaking is to strengthen the pro forma OATT to remedy undue 
discrimination and not to create new market structures.
    604. Despite the clear scope of this rulemaking, several commenters 
contend that broader ratemaking reforms should be implemented in order 
to remove obstacles to achieving competitive markets. Various 
commenters assert that rate pancaking must be eliminated in this 
reform, noting that the Commission has recognized in the past that 
pancaked rates inhibit the development of competitive markets.\359\ 
Arkansas Municipal and TDU Systems contend that pancaked rates are 
particularly burdensome for customers with loads and resources on 
multiple transmission providers systems and those that sit essentially 
at or on the boundaries. TDU Systems argue that the failure to 
eliminate pancaked rates has caused many of the TDU Systems to spend 
many millions of dollars to build transmission from generation to 
interconnect with multiple control areas in order to avoid paying 
multiple wheeling charges.
---------------------------------------------------------------------------

    \359\ E.g., Arkansas Municipal, AWEA, FMPA, and TDU Systems.
---------------------------------------------------------------------------

    605. Some of these commenters also advocate that the Commission 
should move towards joint rates.\360\ Arkansas Municipal Power argues 
that moving toward joint rates outside an RTO will not only eliminate 
competitive barriers outside RTOs, but would reduce the disincentive to 
formation of new and expanded RTOs. TAPS complains that the NOPR 
requires regional planning, but has no provision requiring transmission 
providers to build facilities to support regional needs, arguing that 
joint rates would ease this problem. TDU Systems argue, however, that 
any joint rate methodology should not shift costs to other network 
customers, especially where surcharges are sought that might open the 
door to potential over-recovery by transmission providers as argued in 
the PJM/MISO proceedings. Old Dominion also contends that the 
Commission should add a requirement in the pro forma OATT that regional 
transmission costs be recovered through a single regional transmission 
rate of a rolled-in nature. Relative to cost recovery, Old Dominion 
believes that rolled-in zonal rates work for local facilities within a 
single transmission owner footprint, but regional rolled-in rates would 
be necessary for larger footprints.
---------------------------------------------------------------------------

    \360\ E.g., Arkansas Municipal, TAPS, and TDU Systems.
---------------------------------------------------------------------------

    606. Old Dominion also contends that the lack of periodic review by 
the Commission of stated transmission rates sends a strong economic 
signal to transmission owners to not invest in new transmission. Old 
Dominion argues that the Commission should require periodic rate 
reviews at least every five years or implement formula rates which 
would remove economic incentives for failing to build transmission.
    607. EEI argues that the Commission should not address in this 
proceeding TDU Systems' proposal to require transmission providers to 
eliminate pancaked transmission rates in non-RTO regions because it 
involves complex issues that are not easily resolved. EEI contends that 
transmission providers should not be required to eliminate multiple 
transmission rates across multiple systems simply to allow TDU members 
to avoid the economic consequences of their decisions to

[[Page 12342]]

purchase energy from off-system resources.
    608. Other commenters ask the Commission to institute much broader 
market reforms in this rulemaking, arguing that the Commission will not 
be able to achieve its objectives of remedying undue discrimination and 
developing competitive wholesale markets without a fundamental change 
in market structures. Several commenters advocate changing the market 
structure in non-RTO markets to allow transmission customers to access 
the transmission provider's dispatch and redispatch options.\361\ Some 
commenters \362\ go further to assert that the Commission require the 
use of locational marginal pricing (LMP) as a part of OATT reform. 
Other commenters \363\ assert that the Commission would not need to 
adopt a full RTO market design to achieve its more limited objectives, 
but contend that eliminating the fundamental inconsistency between the 
OATT rules and actual operation of the grid would remove a major 
obstacle to other reforms. Several commenters \364\ contend that 
requiring use of a security constrained economic dispatch is a needed 
part of this reform.
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    \361\ E.g., Chandley-Hogan, Constellation, and PJM.
    \362\ E.g., Morgan Stanley and Steel Manufacturers Associations.
    \363\ E.g., Chandley-Hogan and PJM.
    \364\ E.g., EPSA and Chandley-Hogan.
---------------------------------------------------------------------------

    609. Chandley-Hogan contend that the key element to ensuring 
transmission services are provided on a just, reasonable and not unduly 
discriminatory basis is to provide open access to the security 
constrained economic dispatch and the associated imbalance pricing that 
arises from that dispatch. Chandley-Hogan state that using a security 
constrained economic dispatch would also substantially reduce the 
problems inherent in the pro forma OATT's reliance on contract paths 
and ATC for transmission service scheduling.
    610. Chandley-Hogan contend that a viable path to Order No. 888 
reform is to start from the premise that open access to the dispatch 
(and redispatch) and marginal cost pricing for imbalances and 
redispatch to accommodate transmission are keys to getting open, non-
discriminatory access to transmission. Chandley-Hogan argue that 
dispatch is the essential transmission service and providing open 
access to this dispatch is a path to achieving open, non-discriminatory 
access to transmission. Chandley-Hogan contend that a third party 
cannot effectively access the grid without accessing and closely 
interacting with the system operator's dispatch, including determining 
if transmission service is available, acquiring redispatch service to 
allow its schedule to proceed without curtailment, and settling 
imbalances from scheduled levels. Williams agrees with Chandley-Hogan 
that a system allowing non-RTO utilities to deny and curtail service 
requests whenever there is little ATC left and without offering 
redispatch to a third party is completely flawed. Williams argues that 
these same requests would be accommodated in an RTO through redispatch 
as long as the RTO has sufficient offers to arrange a security 
constrained economic dispatch.
    611. EPSA argues on reply that an all-inclusive, ``asset-blind'' 
administration of open dispatch is needed to fully eliminate undue 
discrimination. EPSA states that security constrained dispatch will 
provide reliable operation and efficient utilization of the 
transmission grid by promoting the use of newer, cleaner and less 
expensive power plants. EPSA urges that these issues should be explored 
further here or in another policy proceeding. Project for Sustainable 
FERC Energy Policy asserts that there is no assurance of non-
discriminatory access to transmission services and competitive 
wholesale markets unless load and potential competitors of the control 
area operators are treated comparably during dispatch. Project for 
Sustainable FERC Energy Policy supports additional provisions to the 
pro forma OATT requiring transparency and fairness in system dispatch 
and redispatch such as either an ``open dispatch'' requirement or a 
rule-based framework with standards of conduct and OASIS disclosure, as 
well as reporting and auditing requirement to eliminate anticompetitive 
incentives. Project for Sustainable FERC Energy Policy argues that 
sufficient data to establish marginal system costs and permit 
comparisons with the prices/costs of neighboring systems should be 
disclosed on OASIS.
    612. PJM proposes open dispatch consisting of control of the 
dispatch function by a disinterested entity and the institution of a 
spot or balancing market to allow for the formation of real-time 
prices. Project for Sustainable FERC Energy Policy encourages the 
further separation of the system operator's dispatch functions from its 
merchant functions, to include specific dispatch transparency and 
comparability mandates as per PJM's and Transparent Dispatch Advocates' 
request. Project for Sustainable FERC Energy Policy supports comparable 
dispatch services through an independent entity. In its reply comments, 
Williams supports the rules based dispatch service proposed by PJM and 
states that it will reduce the opportunity for transmission providers 
to levy unjust and unreasonable redispatch rates.
    613. PJM also contends that non-RTO/ISO systems have negative 
impacts on RTO systems because of the respective treatment of import 
transactions by non-RTOs/ISOs and RTOs/ISOs and the incidence of loop 
flows in market environments. PJM argues that entities scheduling flows 
through PJM that actually loop onto other systems nevertheless benefit 
financially because they collect the difference between the relatively 
high price at the interface where the energy is scheduled to enter the 
PJM footprint and the lower price at the interface where the energy is 
scheduled to leave the PJM footprint. When energy does not flow as 
scheduled, PJM states that the otherwise expected, beneficial impact on 
the transmission constraints are not realized, resulting in price 
differentials between the affected interfaces. As a result, PJM 
contends that such scheduled transactions only contribute to the FTR 
revenue adequacy issues PJM has experienced over the last 12 months.
    614. PJM asserts that it is unduly preferential for a non-RTO/ISO 
utility to take advantage of the benefits of the organized markets of a 
bordering RTO/ISO without any obligation to bear any of the costs of 
administering those markets. PJM contends that it is unduly 
discriminatory and an impediment to the development of competitive 
markets to permit a non-RTO/ISO utility adjacent to an RTO/ISO's 
organized, transparent markets to accept the benefits of those markets 
and the regional transmission planning process that sustains them, 
while the same utility relies on non-market-based congestion management 
and limits the access of its competitors, including those who are 
members of the relevant RTO/ISO, to its dispatch sequence and wholesale 
prices within its service area. PJM asks the Commission to declare that 
it would not be unduly discriminatory for an RTO/ISO to include in its 
tariff a provision that makes an external system operator's access to 
those markets contingent on the external operator providing reciprocal 
access to its dispatch and planning functions for RTO/ISO members, as 
well as access to the external system's real-time marginal system cost 
information.
    615. Transparent Dispatch Advocates propose on reply that the 
Commission require the industry to develop inter-

[[Page 12343]]

control area coordination agreements to provide for reciprocal 
redispatch to alleviate constraints at specified border flowgates. 
Transparent Dispatch Advocates argue that redispatch over a larger area 
provides transmission providers more options to extract the full 
efficiency of their systems by allowing import/export transactions and 
intra-control area flows to continue that would otherwise be curtailed 
by providing redispatch of generation across a border at a lower cost 
than would result had the transaction been curtailed. Transparent 
Dispatch Advocates further propose that the Commission establish 
principles in the Final Rule to guide the development of these 
coordination agreements and require filing of the agreements within 12 
months of the issuance of the Final Rule. Transparent Dispatch 
Advocates suggest that technical conferences may need to be scheduled 
to address any utility specific issues that arise.
    616. Morgan Stanley and Steel Manufacturers Association contend 
that every control area should be moving toward LMP and that facing an 
imbalance cost measured by full replacement value of redispatch 
measured under LMP is the correct incentive to follow a schedule. 
Entegra similarly argues that customers and State regulators would 
benefit from more transparency regarding congestion on the transmission 
system and that the most efficient way to provide this transparency is 
to require transmission providers to apply LMP models to their systems 
and to post the resulting modeled LMPs.
    617. Several commenters object to the proposal for a mandatory all-
inclusive redispatch using bid-based pricing.\365\ These commenters 
generally argue that such a proposal could not lawfully be adopted in 
the Final Rule because it dramatically departs from the scope of the 
NOPR. They also argue that the proposal is bad policy because there is 
no record showing that consumers would benefit from the costly and 
disruptive implementation required for the proposal and that adoption 
of the proposal would create controversy given that Congress and the 
Commission have already rejected an LMP-based model of industry 
restructuring. Sacramento adds that given the record of transmission 
investment in RTOs, open redispatch might not meet the transmission 
expansion goals of the NOPR.
---------------------------------------------------------------------------

    \365\ E.g., LPPC, Entergy, and Sacramento.
---------------------------------------------------------------------------

    618. Southern argues on reply that there is no legal basis for 
claims that a lack of open dispatch results in undue discrimination. 
Southern states that the entities at issue are not similarly situated 
and that open dispatch concerns resource procurement, an area beyond 
the scope of the Commission's jurisdiction. Southern further argues 
that the open dispatch remedy proposed by PJM and others would require 
radical restructuring and market reforms that are unfounded, lack a 
legal basis and would result in political discord. Southern states that 
open dispatch would violate FPA section 217 by threatening the ability 
of LSEs to maintain access to transmission rights to serve native load. 
In its reply comments, Entergy states that the open dispatch proposal 
should be rejected because it is unnecessary to ensure open access 
transmission service, is contrary to the Congressional intent in 
passing EPAct 2005, exceeds the scope of the Commission's jurisdiction 
by overriding State jurisdiction over sales to retail customers, and 
would result in opposition that will delay other reforms and distract 
the Commission with divisive litigation.
    619. Sacramento states that the proposals for mandatory redispatch, 
the control of the dispatch by a disinterested entity, and the 
institution of a spot or balancing market to allow for the formation of 
real-time prices would undermine customers' objectives to receive 
uninterrupted transmission service at a predictable price and ignore 
transmission system operational limitations. Sacramento states that the 
value of mandatory redispatch in the Western Grid is limited because 
constraints often overlap and change from thermal to voltage to 
stability constraints at differing load levels and redispatching large 
amounts of generation to relieve constraints because of the distance 
between loads and generation cannot be achieved in the timeframes 
required to maintain reliability. Sacramento is concerned that PJM's 
proposal would cause appropriation of generation built to serve a 
transmission provider's native load in order to effectuate third-party 
transmission transactions, strain the transmission provider's grid, and 
cause additional curtailment of native load and firm transactions when 
a force majeure event occurs.
    620. Entergy cites the approval of the ICT proposal as ample 
evidence that the incremental approach proposed in the NOPR is a better 
means of improving clarity, transparency and improvements in dispatch 
efficiency than the Transparent Dispatch Advocates and PJM seek to 
mandate. Entergy states that the arguments posed by PJM and Chandley-
Hogan do not target remedying discrimination or ensuring comparability, 
but rather focus on what they believe are mechanisms for more efficient 
use of the grid. Overall, Entergy does not support any changes to the 
basic nature of the services available under the pro forma OATT or the 
development of real-time markets to ensure comparable access.
    621. In its reply comments, Sacramento disagrees with PJM's claims 
that TLRs are a discriminatory substitute for real-time redispatch and 
PJM's proposal to eliminate such use of TLRs in favor of an expanded 
redispatch obligation. Sacramento argues that firm customers under the 
pro forma OATT do not expect TLRs, while those in Day 2 RTOs expect 
that generation will be redispatched. Sacramento adds that TLRs affect 
all loads, but that the nature of firm physical rights service is that 
it will not be interrupted except in very narrow defined circumstances.
    622. Southern argues that customers selling between RTO and non-RTO 
systems are treated equally since part of the transaction is under an 
LMP treatment and the other part is under OATT treatment. In response 
to PJM's allegations that loop flows are unduly discriminatory to its 
customers, Southern states that loop flows are unavoidable consequences 
of integrating electrical systems and that PJM itself imposes loop 
flows on non-RTO systems, the effects of which are not compensated by 
PJM. If PJM believes that entities are free-riding on its system or 
manipulating its system, Southern argues that PJM could seek to 
increase market participation charges or file a complaint with the 
Commission. Sacramento agrees that this rulemaking is the wrong forum 
for resolving seams issues given the stated scope of the NOPR. 
Sacramento adds that border utilities do not ``free ride'' on RTO 
markets because these markets impose significant costs on border 
entities. Sacramento also disagrees that open redispatch would resolve 
loop flow problems and suggests other mechanism for addressing loop 
flow. Finally, Sacramento states that TLRs are an Eastern 
Interconnection process that, although rare, occur in RTOs and non-RTO 
areas.
Commission Determination
    623. As the Commission explained in the NOPR, we do not intend to 
undertake a comprehensive overhaul of our transmission pricing policies 
in this rulemaking. Instead, the Commission proposed a number of 
specific reforms to discrete provisions in the pro forma OATT and a 
clarification to our ``higher of'' policy for pricing of transmission 
system expansions. Given the limited

[[Page 12344]]

scope of this proceeding, we do not believe it would be appropriate to 
adopt the broader ratemaking proposals suggested by commenters. Issues 
of rate pancaking, including joint rates, regional rolled-in rates and 
rate reviews are beyond the scope of this proceeding.
    624. Similarly, the Commission made clear in the NOPR that the 
purpose of the proposed rule is to strengthen the pro forma OATT to 
remedy undue discrimination and not to impose any particular market 
structure on the industry. The Commission's focus in this proceeding 
was and remains the development of competitive wholesale markets 
through the reduction of barriers to entry created through the control 
of transmission assets. We continue to believe that the appropriate 
focus of this rulemaking is to strengthen competitive wholesale markets 
by adopting reforms to address remaining areas of undue discrimination 
and issues of comparability rather than mandating a fundamental change 
in the market structure.
    625. We therefore reject requests to institute systems that require 
the real-time use of regional security constrained economic dispatch 
and LMP for granting real-time transmission service and for the 
settlement of imbalances or to otherwise require transmission providers 
to use LMP-based modeling. We believe that LMP market designs can 
provide significant benefits to customers through more efficient use of 
the grid, but do not believe that such market designs are the only way 
to remedy undue discrimination or achieve comparability. We continue to 
support regional flexibility in market development, provided that the 
market design implemented by the transmission providers provides other 
transmission customers with comparable service to that which the 
transmission providers provide to their own native loads and 
affiliates.
    626. We also reject arguments regarding seams issues creating an 
undue discrimination between market and non-market areas that must be 
resolved in this proceeding. We note that there are currently processes 
underway to address seams issues both in the Eastern and Western 
Interconnections.\366\ We believe that such seams issues are beyond the 
scope of this rule and are better addressed on a case-by-case basis or, 
as appropriate, in the proceeding on RTO Border Utility Issues.\367\
---------------------------------------------------------------------------

    \366\ See, e.g., RTO Border Utility Issues, Notice of Technical 
Conference on Seams Issues for RTOs and ISOs in the Eastern 
Interconnections, (Docket No. AD06-9-000) (issued Jan. 25, 2007).
    \367\ Id.
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2. Energy and Generation Imbalances
    627. In Order No. 888, the Commission concluded that six ancillary 
services must be included in an OATT.\368\ One of those ancillary 
services is energy imbalance service under Schedule 4 of the pro forma 
OATT.\369\ Energy imbalance service is provided when the transmission 
provider makes up for any difference that occurs over a single hour 
between the scheduled and the actual delivery of energy to a load 
located within its control area.\370\ The Commission recognized, in 
general, that the amount of energy taken by load in an hour is variable 
and not subject to the control of either a wholesale seller or a 
wholesale requirements buyer.\371\
---------------------------------------------------------------------------

    \368\ Order No. 888 at 31,703.
    \369\ Id.
    \370\ See Id. at 31,960.
    \371\ Order No. 888-A at 30,230.
---------------------------------------------------------------------------

    628. The Commission found that energy imbalance service should have 
an energy deviation band appropriate for load variations and a price 
for exceeding the deviation band that is appropriate for excessive load 
variations.\372\ The Commission established an hourly deviation band of 
+/-1.5 percent (with a minimum of 2 MW) for energy imbalance. The 
Commission explained that this deviation band promotes good scheduling 
practices by transmission customers, which ensures that the 
implementation of one scheduled transaction does not overly burden 
another.\373\
---------------------------------------------------------------------------

    \372\ Id.
    \373\ Id. at 30,232.
---------------------------------------------------------------------------

    629. With respect to compensation associated with the hourly energy 
deviation band, the Commission explained that, for energy imbalances 
within the deviation band, the transmission customer may make up the 
difference within 30 days (or other reasonable period generally 
accepted in the region) by adjusting its energy deliveries to eliminate 
the imbalance (i.e., return energy in kind within 30 days).\374\ In 
addition, the Commission explained that the transmission customer must 
compensate the transmission provider for each imbalance that exceeds 
the hourly deviation band and for accumulated minor imbalances that are 
not made-up within 30 days.\375\ With respect to the price of energy 
imbalance service, the Commission explained that it intentionally did 
not provide detailed pricing requirements.\376\ Instead, the Commission 
required transmission providers to propose rates for energy imbalance 
service.\377\
---------------------------------------------------------------------------

    \374\ Id. at 30,229.
    \375\ Id. The Commission further stated that the pro forma OATT 
permits schedule changes up to twenty minutes before the hour at no 
charge, and that it would allow the transmission provider and the 
customer to negotiate and file another deviation band more flexible 
to the customer, if the same deviation band is made available on a 
not unduly discriminatory basis. Id. at 30,232-33.
    \376\ Id. at 30,234
    \377\ Id.
---------------------------------------------------------------------------

    630. Although transmission providers have different energy 
imbalance charges, they typically require customers to correct energy 
imbalances within the deviation band through return in kind or a 
financial settlement that requires payment for underdeliveries of 
energy equal to 100 percent of the transmission provider's system 
incremental cost for the hour the deviation occurred. For energy 
overdeliveries, the transmission customer would receive a payment equal 
to 100 percent of the transmission provider's decremental cost for the 
hour the deviation occurred.\378\ Outside the deviation band, 
transmission providers either charge the transmission customer (1) A 
percentage of the utility's system cost, such as 110 percent of 
incremental costs for underscheduling or 90 percent of decremental 
costs for overscheduling or (2) the greater of a percentage of system 
costs or a fixed charge, such as $100 per MWh.\379\
---------------------------------------------------------------------------

    \378\ See, e.g., Arizona Public Service Co., FERC Electric 
Tariff, Twelfth Revised Volume No. 2, Schedule 4 (Energy Imbalance 
Charge), accepted in Arizona Public Service Co., Docket No. ER04-
442-003 (Sep. 30, 2004) (unpublished letter order); Public Service 
Company of New Mexico, FERC Electric Tariff, Second Revised Volume 
No. 4., Schedule 4 (Energy Imbalance Charge), accepted in Public 
Service Co. of New Mexico, Docket No. ER04-416-002 (Sep. 30, 2004) 
(unpublished letter order).
    \379\ See Idaho Power Co., 102 FERC ] 61,351 (2003); Duke 
Electric Transmission FERC Electric Tariff, Third Revised Volume 4, 
Original Sheet No. 120 accepted in Duke Energy Corp., Docket No. 
ER04-812-001 (Jul. 2, 2004) (unpublished letter order).
---------------------------------------------------------------------------

    631. While the Commission found in Order No. 888 that energy 
imbalance was an ancillary service, it also recognized that another 
imbalance may arise for differences between energy scheduled for 
delivery from a generator and the amount of energy actually generated 
in an hour,\380\ commonly called generator imbalance. The Commission 
concluded, however, that a generator should be able to deliver its 
scheduled hourly energy with precision and expressed concern that 
allowing a generator to deviate from its schedule by 1.5 percent 
without penalty, so long as

[[Page 12345]]

it returned the energy in kind at another time, would discourage good 
generator operating practices.\381\ The Commission stated that a 
generator's interconnection agreement with its transmission provider or 
control area operator should specify the requirements for the generator 
to meet its schedule and any consequence for persistent failure to meet 
its schedule.\382 \
---------------------------------------------------------------------------

    \380\ Order No. 888-A at 30,230.
    \381\ Id.
    \382\ Id.
---------------------------------------------------------------------------

    632. The Commission subsequently accepted in a number of cases 
modifications to a transmission provider's OATT to include generator 
imbalance provisions.\383\ Moreover, in Order No. 2003-B, the 
Commission permitted the transmission provider to include a provision 
for generator balancing service arrangements in individual 
interconnection agreements.\384\ Further, in a NOPR concerning 
generator imbalance provisions for intermittent resources, the 
Commission proposed to establish a standardized schedule under the pro 
forma OATT to address generator imbalances created by intermittent 
resources and to clarify the application of the current energy 
imbalance provision of the pro forma OATT.\385\ In particular, the 
Commission proposed that generator imbalance provisions for 
intermittent resources would reflect a deviation band of +/-10 percent 
(with a minimum of 2 MW) and allow net hourly intermittent generator 
imbalances within the deviation band to be settled at the system 
incremental cost at the time of the imbalance.\386 \The Commission also 
reiterated its policy that a transmission provider may only charge the 
transmission customer for either hourly generator imbalances or hourly 
energy imbalances for the same imbalance, but not both.\387\
---------------------------------------------------------------------------

    \383\ See, e.g., Niagara Mohawk Power Corp., 86 FERC ] 61,009, 
order on reh'g, 87 FERC ] 61,148 (1999) (Niagara Mohawk); 
PacifiCorp, 95 FERC ] 61,145, order on reh'g and clarification, 95 
FERC ] 61,467 (2001); Alliant Energy Corporate Services, Inc., 93 
FERC ] 61,340 (2000); Wolverine Power Supply Coop., 93 FERC ] 61,330 
(2000); Commonwealth Edison Co., 93 FERC ] 61,021 (2000); 
FirstEnergy Operating Cos., 93 FERC ] 61,200 (2000), order denying 
reh'g & granting clarification, 94 FERC ] 61,184 (2001); Tampa 
Electric Co., 90 FERC ] 61,330 (2000), reh'g denied, 95 FERC ] 
61,101 (2001); Florida Power Corp., 89 FERC ] 61,263 (1999); 
Consumers Energy Co., 87 FERC ] 61,170 (1999) (Consumers).
    \384\ Order No. 2003-B at P 74-75.
    \385\ Imbalance Provisions for Intermittent Resources; Assessing 
the State of Wind Energy in Wholesale Electricity Markets, Notice of 
Proposed Rulemaking, 70 FR 21349 (Apr. 26, 2005), FERC Stats. & 
Regs. ] 32,581 at P 9 (2005) (Imbalance Provisions Proceeding).
    \386\ The Commission defined incremental cost as ``the 
transmission provider's actual average hourly cost of the last 10 MW 
dispatched to supply the transmission provider's native load, based 
on the replacement cost of fuel, unit heat rates, start-up costs, 
incremental operation and maintenance costs, and purchased and 
interchange power costs and taxes.'' Id. at P 9 n.17 (citing 
Consumers, 87 FERC ] 61,170 at 61,179 (1999)).
    \387\ Under existing Commission policy, a transmission provider 
may only charge a transmission customer for the penalty percent 
adder to the incremental cost for either hourly generator imbalances 
or hourly energy imbalances for the same imbalance. For example, if 
a transmission customer has a 100 MWh point-to-point schedule in a 
control area, but produces 105 MWh and consumes 105 MWh, the 
transmission provider may charge the transmission customer 110% of 
its incremental cost for the 5 MWh of energy imbalance, but then 
must pay the transmission customer its incremental cost for the 5 
MWh generator imbalance.
---------------------------------------------------------------------------

    633. A variety of different deviation bands and pricing methods are 
on file for generator imbalances. Rates for generator imbalance 
underdeliveries range from the greater of $100/MWh or 110 percent of 
system incremental cost to the greater of $150/MWh or 200 percent of 
the incremental cost.\388\ Generator imbalance rates for overdeliveries 
range from 90 percent \389\ of system decremental cost to 50 percent 
\390\ of the decremental cost.
---------------------------------------------------------------------------

    \388\ See Duke Energy Corp., Docket No. ER05-855-000 (Dec. 20, 
2005) (unpublished letter order) (accepting Duke Electric 
Transmission's Large Generator Interconnection Agreement with Power 
Ventures Group, LLC (Duke Delegated Letter Order)).
    \389\ See Entergy Services, Inc., 90 FERC ] 61,272 (2000) 
(concerning various generator imbalance agreements).
    \390\  See Duke Delegated Letter Order.
---------------------------------------------------------------------------

a. Tiered Approach to Imbalance Penalties in the OATT
NOPR Proposal
    634. In the NOPR, the Commission noted that the existing energy 
imbalance charges described in Order No. 2003 are the subject of 
significant concern and confusion in the industry. The Commission 
expressed concern about the variety of different methodologies used for 
determining imbalance charges and whether the level of the charges 
provides the proper incentive to keep schedules accurate without being 
excessive. The Commission therefore proposed to modify the current pro 
forma OATT Schedule 4 treatment of energy imbalances and to adopt a 
separate pro forma OATT schedule for the treatment of generator 
imbalances.
    635. The Commission proposed to create new energy and generator 
imbalance schedules based on the following three principles: (1) The 
charges must be based on incremental cost or some multiple thereof; (2) 
the charges must provide an incentive for accurate scheduling, such as 
by increasing the percentage of the adder above (and below) incremental 
cost as the deviations become larger; and (3) the provisions must 
account for the special circumstances presented by intermittent 
generators and their limited ability to precisely forecast or control 
generation levels, such as waiving the more punitive adders associated 
with higher deviations.
    636. The Commission noted that Bonneville has adopted an energy 
imbalance pricing approach based on a three-tiered deviation band that 
appears workable for both energy imbalance service and generation 
imbalance service. Under this approach, imbalances of less than or 
equal to 1.5 percent of the scheduled energy (or two megawatts, 
whichever is larger) would be netted on a monthly basis and settled 
financially at 100 percent of incremental or decremental cost at the 
end of each month. Imbalances between 1.5 and 7.5 percent of the 
scheduled amounts (or two to ten megawatts, whichever is larger) would 
be settled financially at 90 percent of the transmission provider's 
system decremental cost for overscheduling imbalances that require the 
transmission provider to decrease generation or 110 percent of the 
incremental cost for underscheduling imbalances that require increased 
generation in the control area. Imbalances greater than 7.5 percent of 
the scheduled amounts (or 10 megawatts, whichever is larger) would be 
settled at 75 percent of the system decremental cost for overscheduling 
imbalances or 125 percent of the incremental cost for underscheduling 
imbalances. Intermittent resources are exempt from the third-tier 
deviation band and pay the second-tier deviation band charges for all 
deviations greater than the larger of 1.5 percent or two megawatts.
    637. The Commission sought comment regarding whether this tiered 
approach should be adopted for inclusion in the pro forma OATT for 
energy and generator imbalances. The Commission specifically asked 
whether this approach provides sufficient incentives to ensure that 
transmission systems can be operated in a reliable manner and ensure 
that customers are treated in a just and reasonable manner.
Comments
    638. A number of entities generally support a tiered approach to 
imbalance penalties that progressively increases the penalties for 
imbalances, as implemented by Bonneville.\391\ These

[[Page 12346]]

commenters generally state that a graduated bandwidth approach 
recognizes the link between escalating deviations and potential 
reliability impacts on the system. Other entities, however, take issue 
with aspects of the Commission's proposal or propose a different 
approach to resolving imbalances. For example, Entegra submits that the 
Commission should require transmission providers to establish, or 
permit market participants to establish, markets or pools for the 
netting and settlement of imbalances. Steel Manufacturers Association 
argues for the Commission to require real-time balancing markets.
---------------------------------------------------------------------------

    \391\ E.g., Ameren, Northwest IOUs, Progress Energy, Suez Energy 
NA, Public Power Council, Sacramento, South Carolina E&G, Pinnacle, 
Allegheny, TDU Systems, Constellation, Imperial, and Morgan Stanley.
---------------------------------------------------------------------------

    639. Among those supporting the Commission's proposal, Ameren 
asserts that the tiered approach properly allows for higher penalties 
for imbalances that have a greater impact on the system and thus have a 
greater potential to affect reliability. NorthWestern is not opposed to 
the generation imbalance provisions applying to all generators, arguing 
that imbalance charges must be based upon incremental cost and must 
provide an incentive for accurate scheduling. Morgan Stanley contends 
that basing the imbalance charge on incremental cost should be a 
bedrock principle for developing methods to financially settle 
imbalances.
    640. Progress Energy, Sacramento, and Entergy encourage the 
Commission to allow each transmission provider to have the flexibility 
to craft penalty provisions that provide the right incentives to 
encourage their transmission customers to act responsibly. Grant 
similarly contends that the transmission provider must be able to 
decide what to charge for imbalance services and must consider the 
incentives for resource development and the potential for cross-
subsidies paid by other customers associated with such pricing. Grant 
argues that transmission providers should have an ability to ``opt 
out'' if they can demonstrate an inability to provide the service 
without creating an undue burden on other ratepayers.
    641. Constellation, while supporting the Commission's proposal, 
asks that transmission providers be required to utilize a security-
constrained economic dispatch to procure and settle imbalances at least 
cost, which would ensure that least cost is determined on the most 
efficient basis. Constellation contends that imbalance charges should 
be based on the transmission provider's actual cost of meeting a 
positive imbalance or liquidating a negative imbalance, which costs can 
include required ancillary services and redispatch costs. Morgan 
Stanley states that facing an imbalance cost measured by full 
replacement value of redispatch measured under LMP would be an 
appropriate incentive. Morgan Stanley contends that the pro forma OATT 
should specify using opportunity cost principles to charge for 
imbalance solutions in those areas without LMP and come as close to 
mimicking the result under LMP as possible. In reply comments, Mark 
Lively suggests the Commission make the price for imbalances a function 
of the size of Area Control Error. Public Power Council recommends that 
transmission providers not assess penalties against loads or resources 
when their deviations from the schedule help the system in a given 
delivery hour. TDU Systems argue that inadvertent scheduling errors 
that do not threaten system integrity or reliability should not be 
penalized through charges for imbalances that exceed incremental cost 
in the upper tiers of imbalance bandwidths.
    642. Although FirstEnergy states that the Bonneville approach for 
generator imbalances is appropriate, it argues that the current pro 
forma OATT methodology for calculating and assessing energy imbalances 
should be retained. FirstEnergy argues that it is more appropriate and 
fair to apply a graduated penalty structure to generation imbalances 
since greater deviations usually occur from generation. Ameren, 
however, believes that generators are generally better able to control 
their imbalances than transmission customers who take energy off of the 
system and that the use of a narrower deviation band may be appropriate 
for generator imbalances. Nonetheless, Ameren states that it does not 
oppose the Commission's proposal to use the same deviation bandwidths 
for both energy imbalances and generator imbalances.
    643. Ameren contends that developing standardized provisions for 
generator imbalances in the OATT would eliminate the plethora of 
penalties that now exist. Ameren asserts that moving to a tariff 
approach would increase transparency and would help address the 
situation where such provisions may appear either in the relevant OATT 
or in specific interconnection agreements (at least for interconnection 
agreements entered into as of the date of the revised tariff 
provisions). Progress Energy and South Carolina E&G support separate 
tariff (or Generator Interconnection Agreement) provisions for these 
services, suggesting that generator and energy imbalance provisions 
could be tailored for generators and LSEs. NorthWestern states that it 
has long been an advocate of the inclusion of a generation imbalance 
OATT mechanism. TDU Systems contend that the Commission should require 
that the specific bandwidths and the basis for the charges be spelled 
out in detail in the revisions to the pro forma OATT and in each 
transmission provider's tariff. Allegheny argues that changing Energy 
Imbalance Service from Schedule 4 to Schedule 4a, adding a new Schedule 
4b for Generator Imbalance Service, and eliminating proposed Schedule 9 
would call attention to the fact that a transmission provider may only 
charge a transmission customer either an hourly generator imbalance 
charge or an hourly energy imbalance charge, but not both for the same 
imbalance.
    644. Other entities contend that the Commission's imbalance 
proposal will not do enough to protect reliability and prevent entities 
from deviating from their schedules. Entergy states that the Commission 
should recognize that a system with significant hydro resources, such 
as the Bonneville system, faces different challenges in matching 
generation and load than a system with predominantly thermal 
generation. Unlike the fast ramping capability of hydro units, Entergy 
asserts that thermal units have a more limited ability to adjust and 
compensate for imbalances. Entergy adds that the Bonneville model may 
not provide sufficient incentives in those areas with large amounts of 
independent generation. In reply comments, some APPA members noted that 
wind variability may pose significant operational concerns that could 
increase regulating reserve requirements, particularly on smaller 
transmission systems.
    645. Steel Manufacturers Association asks the Commission to delete 
any further reference to charges based on some multiple of incremental 
costs, which applies to scheduling incentives, not cost recovery. It 
believes that charges based on multiples of incremental costs are not 
necessary and do not produce rates that are just and reasonable. Steel 
Manufacturers Association asserts that balancing mechanisms based on 
real time market-clearing prices provide full compensation and adequate 
scheduling incentives in the organized markets and there is no reason 
to apply a deadband/penalty mechanism for individual OATT providers 
unless there is a demonstrated need, i.e., a showing that excessive 
gaming by LSEs or generators has been a problem.
    646. Steel Manufacturers Association also contends that the current 
imbalance mechanism is a losing proposition for loads that cannot 
control energy

[[Page 12347]]

consumption to match an hourly schedule of energy deliveries, with 
transmission providers receiving windfall revenues. It argues that the 
mechanism is unfair to smaller transmission systems that are not 
control areas (and therefore may not settle all of their imbalances 
through return-in-kind energy) and certain retail customers that take 
unbundled retail transmission service. Steel Manufacturers Association 
asks the Commission to institute a larger bandwidth of, at minimum, 10 
percent for small wholesale customers and discrete retail loads. It 
contends that large utilities and wholesale transmission customers that 
acquire power for many discretely operated loads with varying load 
stages and load factors and averaging those loads creates an overall 
predictability to load curves that permits the practical use of a 1.5 
percent bandwidth for large utilities and wholesale customers.
    647. Utah Municipals assert that the Commission is wrong to believe 
that imbalances tend to result from carelessness or intentional conduct 
rather than unavoidable uncertainties and error. Utah Municipals 
contend that, while technology that permits perfectly accurate 
scheduling (i.e., namely the AGC equipment used by control area 
operators) is theoretically available, it is prohibitively expensive 
for many transmission customers and unavailable to those who do not own 
generation. Utah Municipals argue that financial incentives for 
accurate scheduling do not alter scheduling behavior or actual 
imbalances, but only result in a potential windfall for the 
transmission provider and a potentially significant competitive 
advantage for the transmission provider's market function, which 
(because of the AGC equipment that all transmission customers pay for 
through rates) will not be subject to the charges. Utah Municipals 
suggest that the Commission limit the imbalance charges for 
unintentional deviations by applying the third deviation band only to 
intentional imbalances.
    648. Imperial argues that the Bonneville approach would not provide 
appropriate incentives for small geothermal generating units on its 
system to control their scheduled output, especially if imbalances are 
recorded on an hourly basis rather than on a cumulative basis over the 
course of a month. Under the Bonneville approach, Imperial asserts that 
it would have to pay its generators 100 percent of its incremental cost 
for overgeneration because such imbalances are usually less than 2 MW 
in any given hour. It states that using a 100 percent credit for net 
overgeneration would result in crediting the generator more than 
$28,500.
    649. WECC states that it is very important to differentiate between 
the kind of behavior that the Commission is worried about and 
appropriate practices that support system reliability. WECC is 
concerned that inflexible generator imbalance provisions in the pro 
forma OATT may create incentives for generators in the West to restrict 
governor action on their generators in ways that degrade system 
reliability. WECC notes that the number of rotating machines connected 
to the grid in the Eastern Interconnection is much greater than in the 
Western Interconnection, which impacts the ability of generators to 
respond to maintain frequency when a system's load-resource balance 
changes. WECC explains that a sudden change in load-resource balance of 
a particular magnitude (for example, the loss of a 1,000 MW generating 
plant) will require a proportionately greater response from each 
generating unit in the West as compared to the Eastern Interconnection. 
WECC contends that in the West a significant frequency decline could 
cause responding generators to exceed a 1.5 percent deviation threshold 
applied under current pro forma Tariff imbalance schedules.
    650. If the manner of implementing generator imbalance charges in 
the West does not consider the need for generators to respond to 
frequency deviations, WECC worries that these charges could produce 
perverse incentives that will undermine reliability. WECC argues that 
generators that use set-point controllers to override governor action 
will be less likely to incur imbalance charges and penalties, while 
those with properly operating governors may be punished for deviating 
from scheduled output to respond to system reliability needs. WECC 
believes that this has in fact been happening in the West and is one of 
the reasons that frequency response in the Western Interconnection has 
deteriorated in recent years. WECC urges the Commission to consider how 
generators can be given appropriate incentives to meet their 
obligations to supply energy to load but also to support system 
reliability by effectively responding to frequency deviations. WECC 
explains that the Commission could adopt a policy that set-point 
controllers should not be allowed to override governor response. WECC 
suggests that deviations from scheduled generator output needed to 
correct frequency decay could be excused from imbalance penalties under 
the pro forma OATT.
    651. Indianapolis Power contends on reply that variation should be 
allowed to account for the individual facts and circumstances 
associated with a specific region as well as specific types of 
intermittent resources. A number of entities agree with providing 
flexibility to intermittent generators, but suggest different ways of 
doing so.\392\ Fertilizer Institute agrees that intermittent resources 
should be exempt from any penalties beyond the 90 percent/110 percent 
``second tier.'' However, Fertilizer Institute also believes that 
intermittent resources should receive greater tolerance before they run 
into the 90 percent/110 percent penalty level in the first place. 
Fertilizer Institute urges the Commission to relax the first-tier 
tolerance band from 2MW to 20MW (or 40 percent of nameplate capacity, 
whichever is greater) for intermittent generators only. It asserts that 
this action is consistent with the Commission's recognition that 
intermittent generators can undergo sudden changes of conditions for 
which they cannot fairly be held responsible. Fertilizer Institute 
argues that a broader first-tier tolerance band for these generators 
will present no threat to the transmission grid, because intermittent 
generation facilities are limited both in size and in number.
    652. Geothermal Producers supports a first-tier deviation band of 
+/-5 percent for intermittent resources, rather than the 1.5 percent 
threshold proposed by Bonneville. Geothermal Producers believes a 5 
percent band is appropriate for intermittent resources, since a five 
percent band more accurately recognizes that intermittent resources are 
less capable of controlling deviations from schedules than are 
conventional resources. For over- or under-deliveries in excess of five 
percent, Geothermal Producers contends that intermittent resources 
should be charged no more than the control area's cost of supplying 
energy to correct the imbalance. Geothermal Producers also supports 
Bonneville's position that intermittent resources should be exempt from 
the third-tier deviation band and instead should pay the second-tier 
deviation band charges for all deviations greater than the second-tier 
deviation band.
---------------------------------------------------------------------------

    \392\ E.g., NorthWestern, Fertilizer Institute, and Geothermal 
Producers.
---------------------------------------------------------------------------

    653. Other commenters, however, do not support providing exceptions 
for

[[Page 12348]]

intermittent resources.\393\ If society decides to provide incentives 
for intermittent resources, Morgan Stanley states that this is better 
done in a direct fashion, such as a certification program akin to 
resource adequacy rules that require LSEs to source a proportion of 
supply from such resources. Morgan Stanley asserts that this would 
motivate developers to mitigate imbalance costs through other market or 
technical means to the full extent of the economic signal imbedded in 
the imbalance price and thereby optimize the design and operation of 
such resources. MidAmerican argues on reply that special treatment of 
intermittent resources and loads has the effect of penalizing those 
resources and loads that have made investments to manage scheduling and 
enhance reliability. TDU Systems believe that the NOPR's third 
principle, which requires transmission providers to accord special 
treatment to intermittent generators, is contrary to the principle of 
comparability.
---------------------------------------------------------------------------

    \393\ E.g., Morgan Stanley, Northwest IOUs, Steel Manufacturers 
Association, and TDU Systems.
---------------------------------------------------------------------------

    654. Northwest IOUs argue that the transmission provider should 
have the option to elect whether to exempt intermittent resources from 
the third-tier deviation band and instead charge, in a not unduly 
discriminatory or preferential manner, the second-tier deviation band 
charge for all deviations greater than the larger of 1.5 percent or 2 
megawatts.
    655. Several commenters suggested that the Commission include a 
definition of intermittent resource in the final rule. Fertilizer 
Institute and South Carolina E&G contend that it is essential for the 
Commission to provide a clear definition of ``intermittent generation'' 
or ``intermittent resource'' to avoid disputes. Fertilizer Institute 
argues that the question of whether a given generator is 
``intermittent''--and thereby entitled to the special provisions--is 
likely to become a source of contention. Fertilizer Institute suggests 
that an intermittent resource be defined as ``an electric generator 
that (1) Cannot store its fuel sources and (2) has limited capability 
to be dispatched and to respond to changes in system demand and 
transmission security constraints.'' EEI, however, suggests that the 
definition apply only to weather-driven units. Fertilizer Institute 
argues on reply that restricting the definition in this way would be 
unduly discriminatory. Fertilizer Institute argues that the definition 
should include the most common forms of intermittent generation--wind 
and solar power--as well as the less common but equally valuable forms, 
such as generation with ocean energy or ``waste heat'' from an 
industrial process. Fertilizer Institute asserts that the Commission 
should not broaden the definition of intermittent resource to encompass 
generators who are not truly ``intermittent'' and should not narrow the 
definition to exclude some intermittent generators in favor of others. 
Fertilizer Institute contends on reply that a generator should not have 
to be ``weather-driven'' to qualify as ``intermittent.'' Geothermal 
Producers supports the inclusion of geothermal energy as an 
intermittent resource. Geothermal Resources contends that geothermal 
resources satisfy both the Commission's proposed definition and the EEI 
proposal.
    656. Ameren and Entergy ask the Commission to clarify that it does 
not intend to amend any existing interconnection agreements to require 
the use of any pro forma imbalance penalties. Entergy believes that the 
present form of its Generation Interconnection Agreement is absolutely 
critical to managing imbalances on its system and maintaining 
reliability. Entergy states that it has developed specialized software 
to monitor and manage generator imbalances and employs six system 
operators (one per shift) to monitor and manage generator imbalances.
    657. Although Entergy supports the ``grandfathering'' of existing 
generator imbalance arrangements, it does not believe that it would be 
appropriate to require the prospective use of a different methodology 
while simultaneously maintaining the grandfathered arrangements. 
Entergy contends that administering two different generator imbalance 
arrangements would not be consistent with the comparability principles 
of Order No. 888 and would be difficult and costly from an operational 
perspective.
    658. Several commenters \394\ argue on reply that it would be 
inappropriate for the Commission to grandfather existing imbalance 
provisions. In its reply comments, Entegra argues that prior 
arrangements should remain in place only if a transmission provider can 
demonstrate that its existing imbalance arrangements are consistent 
with or superior to the provisions of the pro forma OATT as modified by 
the Final Rule in this proceeding.
---------------------------------------------------------------------------

    \394\ E.g., Fertilizer Institute, Entegra, and TAPS.
---------------------------------------------------------------------------

    659. EEI and Exelon contend that the transmission provider may not 
be able to charge a generator under its OATT if the generator is not 
the transmission customer and, therefore, generators should be able to 
include standardized imbalance terms in agreements with eligible 
customers prior to providing service. Exelon suggests that the 
Commission both adopt in the pro forma OATT a standard imbalance 
penalty structure and direct transmission providers to include the same 
terms and conditions in their interconnection agreements with 
generators. TAPS suggests on reply that each generator could simply be 
required to sign a service agreement that requires it to comply with 
the generator imbalance provisions of the transmission provider's OATT. 
Unless the pro forma OATT governs both generator and load imbalances, 
TAPS argues that it would be impossible to implement and enforce the 
Commission's prohibition against charging both energy and generator 
imbalances for a single transaction.
    660. ICNU argues on reply that the Commission should adopt less 
restrictive imbalance charges for retail access customers or, at a 
minimum, continue to recognize that the standard energy imbalance 
charge needs to be modified to accommodate direct access customers. 
ICNU asks the Commission to modify its proposed imbalance provision to 
reflect the unique characteristics of direct access customers by 
adopting wider imbalance bandwidths and/or waiving the more punitive 
adders associated with higher deviations.
    661. Several entities assert that the proposed imbalance reform 
should not apply to RTOs. Exelon requests that the Commission 
explicitly state that these rules do not apply in regions that have 
organized markets, such as PJM, that obviate the need for imbalance 
penalties. They contend that within organized markets, an imbalance 
penalty rule is not necessary, as the independent transmission 
operators have effectively addressed the concerns that the proposed 
imbalance schedules are intended to address. Indicated New York 
Transmission Owners contend that the Commission should grant the NYISO 
a regional variation from the revised pro forma OATT with respect to 
imbalance charges. It contends that the existing mechanisms in ISO/RTO 
markets with LMP are consistent with the Commission's objectives in its 
NOPR and that the Commission should permit a regional variation to the 
NYISO. SPP states that the Commission should state that it does not 
intend to affect its effort to implement a real-time energy imbalance 
market by any final rule. SPP further contends that the Commission 
should clarify that its energy imbalance changes do not apply to ISOs 
and RTOs with organized

[[Page 12349]]

markets providing for real-time energy imbalance markets. SPP believes 
that the Commission should view the existence of a spot energy price in 
organized markets as superior to penalties based on incremental costs 
or some multiple thereof.
    662. Entegra suggests that, since many RTOs have (or are 
developing) separate markets for commitment costs, it may not be 
necessary to incorporate such costs into imbalance prices in certain 
RTO markets. Organizations of MISO and PJM States contend that this 
proposed change to Schedule 4 is not applicable in the RTO context and 
argue that, to the extent that the Commission's suggestions regarding 
the special circumstances presented by intermittent generators are 
applicable to RTOs, those issues are best addressed in a context other 
than the instant rulemaking proceeding.
Commission Determination
    663. In order to increase consistency among transmission providers 
in the application of imbalance charges, and to ensure that the level 
of the charges provides appropriate incentives to keep schedules 
accurate without being excessive, the Commission adopts in the pro 
forma OATT imbalance provisions similar to those implemented by 
Bonneville. We agree with commenters that a graduated bandwidth 
approach recognizes the link between escalating deviations and 
potential reliability impacts on the system. Furthermore, we conclude 
that these provisions adhere to the three principles discussed in the 
NOPR, which we also adopt here: (1) The charges must be based on 
incremental cost or some multiple thereof; (2) the charges must provide 
an incentive for accurate scheduling, such as by increasing the 
percentage of the adder above (and below) incremental cost as the 
deviations become larger; and (3) the provisions must account for the 
special circumstances presented by intermittent generators and their 
limited ability to precisely forecast or control generation levels, 
such as waiving the more punitive adders associated with higher 
deviations.
    664. Specifically, imbalances of less than or equal to 1.5 percent 
of the scheduled energy (or two megawatts, whichever is larger) will be 
netted on a monthly basis and settled financially at 100 percent of 
incremental or decremental cost at the end of each month. Imbalances 
between 1.5 and 7.5 percent of the scheduled amounts (or two to ten 
megawatts, whichever is larger) will be settled financially at 90 
percent of the transmission provider's system decremental cost for 
overscheduling imbalances that require the transmission provider to 
decrease generation or 110 percent of the incremental cost for 
underscheduling imbalances that require increased generation in the 
control area. Imbalances greater than 7.5 percent of the scheduled 
amounts (or 10 megawatts, whichever is larger) will be settled at 75 
percent of the system decremental cost for overscheduling imbalances or 
125 percent of the incremental cost for underscheduling imbalances.
    665. The Commission adopts Bonneville's tariff provisions that 
provide that intermittent resources are exempt from the third-tier 
deviation band and would pay the second-tier deviation band charges for 
all deviations greater than the larger of 1.5 percent or two megawatts. 
We believe this is consistent with the fact that intermittent 
generators cannot always accurately follow their schedules and that 
high penalties will not lessen the incentive to deviate from their 
schedules.
    666. Several commenters argue that the Commission should adopt a 
standard definition of intermittent resource. In order to clarify 
application of imbalance charges, we define an intermittent resource 
for this limited purpose as ``an electric generator that is not 
dispatchable and cannot store its fuel source and therefore cannot 
respond to changes in system demand or respond to transmission security 
constraints.'' \395\ We conclude that this definition of intermittent 
resource properly limits the exemption from imbalance charges, without 
excluding certain classes of intermittent generators for which the 
exemption is appropriate (e.g., non-weather driven intermittent 
resources).
---------------------------------------------------------------------------

    \395\ See Docket No. RM05-10-000. We note that this definition 
was proposed by the Commission in the NOPR on Imbalance Provisions 
for Intermittent Resources. See Imbalance Provisions for 
Intermittent Resources; Assessing the State of Wind Energy in 
Wholesale Electricity Markets, Notice of Proposed Rulemaking, 70 FR 
21349 (Apr. 26, 2005), FERC Stats. & Regs. ] 32,581 (2005).
---------------------------------------------------------------------------

    667. The Commission believes that adopting a tiered approach for 
both energy and generation imbalances will best balance the needs of 
transmission providers to operate their transmission systems in a 
reliable manner with the needs of transmission customers to have 
reasonable access to those systems at just and reasonable rates. 
Furthermore, we conclude that the partial exemption from imbalance 
charges for intermittent resources appropriately reflects the special 
circumstances faced by such resources and, consequently, is not unduly 
discriminatory. Moreover, formalizing generator imbalance provisions in 
the pro forma OATT will standardize the future treatment of such 
imbalances from the wide variety of generator imbalance provisions that 
exist today in various generator interconnection agreements. 
Standardizing generator imbalances should lessen the potential for 
undue discrimination, increase transparency and reduce confusion in the 
industry that results from the current plethora of different 
approaches.
    668. Several commenters debate whether the imbalance provisions 
adopted here should be applied to energy imbalances, generation 
imbalances, or both. The Commission concludes that subjecting both 
energy and generation imbalances to the same charges is appropriate. 
Energy and generation imbalances have the same net effects on the 
transmission system in requiring other generation to be ramped up or 
down to make up for the imbalance. As such, the Commission will modify 
the current pro forma OATT Schedule 4 treatment of energy imbalances 
and adopt a new separate pro forma OATT Schedule 9 for the treatment of 
generator imbalances, each based on the tiered structure described 
above. To the extent a transmission provider wishes to deviate from 
these revised pro forma provisions, it may demonstrate in an FPA 
section 205 proceeding that the proposed changes are consistent with or 
superior to the pro forma OATT as modified by this Final Rule. However, 
we note that proposed alternative provisions must comply with the three 
imbalance charge principles addressed in the NOPR and adopted in this 
Final Rule and be consistent with or superior to the specific imbalance 
charges set forth in the pro forma OATT (and discussed above).
    669. Some commenters stated that the Commission should require 
transmission providers to establish, or permit market participants to 
establish, markets or pools for the netting and settlement of 
imbalances. As explained previously, the purpose of this rule is to 
strengthen the pro forma OATT to remedy undue discrimination and not to 
impose any particular market structure. If transmission providers offer 
to modify their OATTs to allow such pools, we will consider such 
proposals. But, imposing such requirements goes beyond the scope of 
this proceeding. The Commission therefore declines, for all these 
reasons, to impose the structural reforms requested by some commenters.
    670. The Commission instead adopts the three-tiered approach in the 
pro

[[Page 12350]]

forma OATT. As with other reforms adopted in this Final Rule, all 
transmission providers must submit compliance filings containing these 
pro forma tariff provisions. Transmission providers with previously-
approved tariff provisions governing imbalances that no longer conform 
to the pro forma OATT, as revised in this Final Rule, may seek renewed 
approval of those tariff deviations in accordance with the procedures 
described in section IV.C above, demonstrating that the alternative 
imbalance charge structures are consistent with or superior to the 
reformed pro forma OATT. With respect to the concerns raised by ISOs 
and RTOs, we agree that LMP-based markets can provide an efficient and 
nondiscriminatory means of settling imbalances and, as indicated in the 
NOPR, we are not proposing to redesign ISO/RTO markets in this 
rulemaking. Nevertheless, ISOs and RTOs must follow the procedures 
described in the Applicability section for seeking approval of 
deviations that are consistent with or superior to the pro forma OATT.
    671. We do not, however, abrogate existing generator imbalance 
agreements between transmission providers and their customers. These 
agreements have been negotiated between willing parties, and the 
Commission will not re-open them generically in this proceeding. To the 
extent a particular party desires to amend an existing generator 
imbalance agreement in light of the reforms we adopt in this Final 
Rule, that party may exercise whatever rights it may have under the 
agreement or FPA section 206.
    672. With regard to WECC's frequency-response concerns, we agree 
that a generator should be excused from imbalance penalties that occur 
due to directed reliability actions by generators to correct frequency. 
It would not be appropriate to assess imbalance charges on generator 
deviations that are associated with supporting system reliability by 
responding to frequency deviations as directed by the transmission 
provider or general reliability requirements. As such, if a response 
from a generator (particularly in the West) is required to prevent 
frequency decay and the corresponding deviations from the generator's 
schedule would cause additional imbalance penalties, the transmission 
provider should exempt the generator from those penalty charges.
b. Intentional Deviations
NOPR Proposal
    673. In the NOPR, the Commission noted that the Bonneville 
imbalance provision allows for greater charges when a customer has an 
``intentional deviation.'' \396\ The Commission sought comment on 
whether the pro forma OATT imbalance provision should provide for 
similar penalties for behavior that represents deliberate reliance on 
the transmission provider's generation resources, as opposed to 
scheduling errors, with such penalties being subject to prior notice 
and approval by the Commission and based on the facts and circumstances 
of the individual transmission provider.
---------------------------------------------------------------------------

    \396\ See 2006 Transmission and Ancillary Service Rate 
Schedules, approved in United States Dep't of Energy--Bonneville 
Power Administration, 112 FERC ] 62,258 (2005). The Bonneville 
tariff provides that ``For any hour(s) that an imbalance is 
determined by [Bonneville] to be an Intentional Deviation: (1) No 
credit is given when energy taken is less than the scheduled energy, 
(2) When energy taken exceeds the scheduled energy, the charge is 
the greater of: (i) 125% of [Bonneville's] highest incremental cost 
that occurs during that day, or (ii) 100 mills per kilowatthour.'' 
An ``Intentional Deviation'' is defined as ``a deviation that is 
persistent during multiple consecutive hours or at specific times of 
the day,'' a ``pattern of under-delivery or over-use of energy,'' or 
``persistent over-generation or under-use during Light Load Hours, 
particularly when the customer does not respond by adjusting 
schedules for future days to correct these patterns.'' Id. at 46.
---------------------------------------------------------------------------

Comments
    674. Several entities contend that higher imbalance charges and 
penalties for deliberately leaning on the grid can be appropriate.\397\ 
Imperial supports an imbalance provision that allows for greater 
charges for persistent or patterned deviations. Pinnacle agrees that 
deliberate reliance on the transmission provider's generation resources 
is inappropriate and could adversely affect the reliability of the 
transmission system, but they are unsure if such an intentional 
deviation could be proven. Imperial also expresses concern that the 
burden to prove the intent of the generator will fall on transmission 
providers and that, in reality, transmission providers may face an 
uphill battle to prove a generator's deviation was intended. South 
Carolina E&G and Imperial request that the Commission provide a 
specific process for imposing such penalties, including what procedures 
should be followed if a transmission provider seeks to have the 
Commission impose such penalties.
---------------------------------------------------------------------------

    \397\ E.g., Imperial District Irrigation, Progress Energy and 
Ameren.
---------------------------------------------------------------------------

    675. Several entities oppose penalties for intentional deviations 
or suggest modifications. Constellation supports an elimination of the 
separate penalty structure for customers deliberately leaning on the 
system. Constellation and Grant believe that a graduated percentage 
adder/discount will provide the right incentives and disincentives 
without the need for an intentional deviation provision. If deviation 
costs are properly calculated, Morgan Stanley contends that requiring 
those who deviate to pay the full marginal cost of that deviation would 
result in fair allocation of cost responsibility and sufficient 
stability of system operations as a result of both cost and risk 
avoidance by participants. TDU Systems argue that the Commission should 
eliminate the 100 mill per kWh floor for penalties for intentional 
deviations.
Commission Determination
    676. The Commission recognizes the need to provide transmission 
customers with the appropriate incentives not to intentionally dump 
power on the system or lean on other generation. We do not believe, 
however, that separate penalties for intentional deviations need to be 
generically imposed in the pro forma OATT. The tiered imbalance 
penalties adopted in this Final Rule generally provide a sufficient 
incentive not to engage in such behavior. Proposals to assess 
additional penalties for intentional deviations will continue to be 
considered on a case-by-case basis, subject to a showing that they are 
necessary under the circumstances. We note that any such tariff 
provisions must include clearly defined processes for identifying 
intentional deviations and the associated penalties.
c. Calculation of Incremental Cost
NOPR Proposal
    677. With respect to the pricing of energy and generation 
imbalances, the Commission stated in the NOPR its belief that charges 
based on incremental costs or multiples of incremental costs would 
provide the proper incentive to keep schedules accurate without being 
excessive. The Commission proposed that incremental cost be defined to 
include both energy and commitment \398\ costs, to the extent 
additional commitments are needed.\399\

[[Page 12351]]

The Commission sought comment on how such charges should be calculated, 
as well as how they would be applied to transmission customers. The 
Commission sought further comment as to how additional demand and 
energy costs, if incurred in responding to imbalances, such as 
redispatch, commitment, or additional regulation reserves, should be 
appropriately reflected in the calculation of imbalance charges and 
which customers should be charged for such costs.
---------------------------------------------------------------------------

    \398\ The Commission noted that ``capacity commitment'' is 
generally defined as the generating capacity committed by a utility 
to provide capability for another utility to attain its reserve 
level. See, e.g., Central & South West Services, Inc., 48 FERC 
61,197 at 61,731 n.9 (1989).
    \399\ The Commission proposed defining incremental cost, based 
on its decision in Consumers, as the transmission provider's actual 
average hourly cost of the last 10 MW dispatched to supply the 
transmission provider's native load, based on the replacement cost 
of fuel, unit heat rates, start-up costs, incremental operation and 
maintenance costs, and purchased and interchange power costs and 
taxes.
---------------------------------------------------------------------------

Comments
    678. Several entities argue that incremental pricing for both 
energy imbalances and generator imbalances should reflect the full 
incremental costs incurred by the transmission provider (e.g., such as 
redispatch costs, capacity commitment costs or additional regulation 
reserve costs) resulting from the imbalance.\400\ Allegheny questions 
whether the Consumer's definition is appropriate because ``the last 10 
MW'' requirement is independent of the time of the scheduling 
deviation. Allegheny contends that the definition should be modified 
such that it specifically addresses the incremental dispatch to supply 
the transmission provider's load ``in the hour in which the imbalance 
occurs.''
---------------------------------------------------------------------------

    \400\ E.g., Allegheny, Ameren, Indicated New York Transmission 
Owners, and FirstEnergy.
---------------------------------------------------------------------------

    679. Entergy argues that imbalance pricing on an hourly basis does 
not capture all of the costs and reliability risk to the transmission 
provider of over- and under-deliveries. Entergy states that the real-
time regulation burden imposed by IPPs is similar to the real-time 
regulation burden imposed by loads, and loads are charged for this cost 
through a transmission provider's Schedule 3 Regulation and Frequency 
Response Service. Entergy asserts that the NOPR does not propose any 
recovery mechanism for the regulation burden imposed by IPPs, 
recognizing that Bonneville may not face significant generator 
regulation costs due to the rapid ramping rate and relatively low cost 
of hydroelectric resources. Entergy submits that its regional 
experience has demonstrated that generator regulation service is a 
necessity. Entergy states that its generator regulation service 
recovers charges for the generating capacity that Entergy must maintain 
on-line in order to respond to the moment-to-moment deviations between 
scheduled output and actual generation. Entergy explains that the 
charge compensates Entergy on a cost-basis for the generation capacity 
used by IPPs, while at the same time sending the appropriate economic 
signal that encourages generators to match their generation with their 
schedules.
    680. In its reply comments, EEI argues that a transmission provider 
should be entitled to recover the cost of additional reserves needed to 
meet the increased reliability requirements resulting from the 
provision of the imbalance energy if the transmission provider 
generates additional energy to compensate for a load that schedules 
less energy than it takes or a generator that produces less energy than 
it schedules. EEI further contends that transmission providers should 
be permitted to include in their calculation of imbalance charges any 
other costs associated with committing a unit that is not on-line such 
as minimum run times, losses, etc.
    681. Entergy opposes a single price for settling over-deliveries 
and under-deliveries. For transmission providers who choose to base 
energy and generator imbalance charges on incremental and decremental 
costs, Entergy requests that the Commission not adopt standardized 
definitions of incremental cost and decremental cost in the pro forma 
OATT. In its reply comments, Entergy further argues that a requirement 
that the transmission provider post incremental and decremental cost 
information is unfair and harmful to the market, placing the 
transmission provider at an unfair competitive disadvantage in the 
market. Duke on reply proposes that System Incremental Cost (SIC) be 
used to price both over-deliveries and under-deliveries. Duke defines 
SIC to mean the incremental expense, measured in dollars per megawatt 
hour, incurred by the utility to produce or procure the next megawatt 
hour (MWh) of energy, after serving all of the utility's electric 
energy and/or capacity sales. Duke proposes that SIC shall include but 
not be limited to: The replacement cost of fuel; incremental operating 
and maintenance costs; emissions allowance replacement costs and other 
environmental compliance costs; the cost of starting and operating any 
generating units, (including costs incurred due to minimum runtimes or 
loading levels); purchase and interchange power costs; and all 
applicable taxes or assessments based on the revenues received or 
quantities sold.
    682. Allegheny states that the Commission should clarify that the 
definition of incremental cost is equally applicable to intermittent 
generator imbalance service as well as non-intermittent generator 
imbalance service.
    683. Pinnacle and Utah Municipals request that the Commission allow 
the use of alternative pricing methodologies, such as market proxy 
pricing methodology based on trading hubs in or adjacent to their 
respective control areas, where appropriate. Utah Municipals urge the 
Commission to make clear in the final rule that market-based pricing 
may be acceptable in some circumstances and to amend Schedule 4 of the 
pro forma OATT to ensure that imbalance charges are designed not only 
to provide legitimate incentives for accurate scheduling, but also to 
avoid unjustified penalties (masquerading as ``incentives''), to 
minimize the discriminatory impact of such charges, and to avoid 
penalizing behavior or results that in fact help to keep the system as 
a whole in balance.
    684. TDU Systems believe the Commission should disallow recovery of 
demand charges or capacity commitment costs in any charges approved for 
imbalances. TAPS and TDU Systems argue that capacity required to follow 
load is already paid for by charges for regulation and reserves under 
Schedules 3, 5 and 6. TDU Systems also support that the Commission 
continue to apply its existing policy of imposing a heavy burden on 
transmission providers to justify such demand or capacity commitment 
charges in the context of a full base rate case, and of requiring 
transmission providers to develop alternative solutions for balancing 
schedules and loads.
    685. To the extent transmission providers are permitted to include 
commitment costs in negative imbalance charges, Entegra believes that 
additional monitoring would be needed, to include posting of hourly 
imbalance charges, even if with a lag of a day or so. Suez Energy NA 
contends that the Commission should require a transmission owner to 
support its incremental cost filing on the basis of Form No. 423 data 
and actual operations of the selected units, based on operational data 
as reported in utilities Continuous Emission Monitoring reports.
    686. EEI argues that since Schedule 3, 5 and 6 charges recover the 
costs of capacity based on test year data, they would not recover the 
additional costs of reserves that transmission providers incur to 
compensate for their customers' failures to match their schedules and 
their loads or generator output, and they also do not recover other 
commitment costs such as start-up costs or minimum run times. EEI 
argues that if transmission providers could not recover such costs 
through imbalance

[[Page 12352]]

charges, they would not be able to recover them at all.
Commission Determination
    687. The Commission concludes that it is appropriate to define 
incremental cost, for purposes of the tiered imbalance provisions 
adopted above, as the transmission provider's actual average hourly 
cost of the last 10 MW dispatched to supply the transmission provider's 
native load, based on the replacement cost of fuel, unit heat rates, 
start-up costs, incremental operation and maintenance costs, and 
purchased and interchange power costs and taxes, as applicable.
    688. In deriving such charges, we note that the Commission proposed 
in paragraph 244 of the NOPR that incremental cost be defined to 
include both additional energy and commitment costs. The Commission 
also sought comment on how additional demand and energy costs, such as 
redispatch, commitment, or additional regulation reserves, would be 
appropriately recovered if incurred in responding to imbalances.
    689. The Commission finds that it is appropriate, through the 
definition of incremental cost, to allow for recovery of both 
commitment and redispatch costs while excluding the cost recovery of 
additional regulation reserve costs. Commitment and redispatch costs 
shall be accommodated as a part of the hourly cost of the last 10 MW 
dispatch and in the start up cost portion of the definition. The 
Commission concludes that excluding additional regulation costs as a 
general matter is appropriate since much of those costs would be demand 
costs.\401\ We believe including charges for unit commitment costs 
(e.g., start-up and minimum load costs) and O&M costs is necessary to 
ensure that both energy and generation imbalance charges reflect the 
full incremental costs incurred by the transmission provider. We 
emphasize, however, that such costs should only be the additional costs 
incurred by the transmission provider due to the imbalance. If 
applicable, start-up costs should be allocated pro rata to the 
offending transmission customers based on cost causation principles.
---------------------------------------------------------------------------

    \401\ To the extent a transmission provider wishes to recover 
costs of additional regulation reserves associated with providing 
imbalance service, it must do so via a separate FPA section 205 
filing demonstrating that these costs were incurred correcting or 
accommodating a particular entity's imbalances.
---------------------------------------------------------------------------

    690. If the transmission provider elects to have separate demand 
charges assigned to customers for the purpose of recovering the cost of 
holding additional reserves for meeting imbalances, the transmission 
provider should file a rate schedule and demonstrate that these charges 
do not allow for double recovery of such costs. To address Entergy's 
concern that the real-time regulation burden imposed by IPPs is similar 
to the real-time regulation burden imposed by loads, we will allow 
transmission providers to propose separate regulation charges for 
generation resources selling out of the control area and consider such 
proposals on a case-by-case basis. We believe that the other demand 
costs of providing imbalance service are already being provided under 
Schedule 3, 5, and 6 charges.
    691. In responding to Allegheny's comments, we clarify that the 
definition of incremental cost is equally applicable to intermittent 
generator imbalance service as well as non-intermittent generator 
imbalance service.
    692. We do not believe it appropriate to require transmission 
providers to use market proxy pricing to calculate incremental costs in 
the pro forma OATT. The feasibility of using market proxies must be 
considered on a case-by-case basis, given the characteristics of each 
market. If proposed, the proxy price must represent a valid alternative 
to the incremental cost calculation, reflecting competitive, 
transparent and liquid conditions similar to those that would exist in 
the seller's market.\402\
---------------------------------------------------------------------------

    \402\ See RockGen Energy, LLC, 100 FERC ] 61,261 (2002) (setting 
for hearing, inter alia, whether proposed market proxy price is 
reliable, verifiable, and also indicative of the prevailing price in 
liquid non-redispatch markets in the region).
---------------------------------------------------------------------------

d. Inadvertent Energy Treatment
NOPR Proposal
    693. The Commission proposed in the NOPR to continue to allow 
inadvertent energy to be treated differently from energy and generator 
imbalances, explaining that these two types of service are not 
comparable. The Commission noted that, given the nature of inadvertent 
energy and historical practices, transmission providers pay back 
inadvertent energy imbalances and that the Commission has accepted this 
practice as just and reasonable. The Commission sought comment on 
whether the current return-in-kind approach to inadvertent energy 
encourages leaning on the grid in times of shortage and, therefore, 
whether any reforms in this area are appropriate. The Commission asked 
whether pricing inadvertent energy at incremental cost (or some variant 
thereof) would be an appropriate disincentive and, if any reforms in 
this area are appropriate, whether they should be pursued under FPA 
section 215 as part of the review of reliability standards.
Comments
    694. A number of commenters support continuing to allow inadvertent 
energy to be treated differently from energy and generator imbalances, 
agreeing that these two types of services are not comparable.\403\ 
Allegheny argues that this historical practice makes sense because the 
variables germane to inadvertent interchange are beyond the control of 
individual transmission providers and, therefore, are best addressed in 
the context of reliability. Entergy notes that transmission customers 
have some flexibility to mitigate the deviations between their 
schedules and the operation of their load in real-time, while control 
area interchange imbalances may involve the failure of control areas to 
match their scheduled inflows and outflows due to contingencies 
occurring even in a third control area.
---------------------------------------------------------------------------

    \403\ E.g., Entergy, Allegheny, Progress Energy, Public Power 
Council, South Carolina E&G, PGP, and Ameren.
---------------------------------------------------------------------------

    695. Northwest IOUs argue that there is no reason to think that 
there is abuse of one system leaning on another in regards to 
inadvertent energy, particularly in light of Control Performance 
Standards 1 and 2 and other protocols for balancing flows across 
interconnections. Public Power Council states that in-kind return of 
inadvertent energy between Balancing Authorities is governed by 
numerous agreements and tariffs that are designed to limit the ability 
of one system to lean on another.
    696. Sacramento states that the Commission expressed concern in 
other settings that generators may intentionally undergenerate during 
high-cost hours and make it up by overgenerating during low-cost hours 
under a return-in-kind approach. Sacramento contends that in kind means 
not only a return of energy, but a return of energy at like times and 
conditions and does not believe that this results in leaning. In its 
reply comments, Exelon requests that the Commission's imbalance penalty 
rules explicitly prohibit the local utility Balancing Authority 
operator from relying on inadvertent energy to balance its affiliated 
generators' schedules and thus obtaining a competitive advantage.
    697. Other commenters disagree that inadvertent energy should 
continue to be treated differently. Exelon expresses concern that in 
regions without organized markets there is the potential

[[Page 12353]]

for local utility balancing authority operators to seek to avoid paying 
deviation charges by favoring their own generators over merchant 
generators or by using inadvertent energy to balance their schedule. 
Exelon argues that a balancing authority operator could maintain system 
balance by choosing to order its affiliated generators to deviate from 
the schedule and thereby allow its affiliated generator to avoid 
deviation charges that the merchant generator could not avoid. If the 
local utility balancing authority operator relies on inadvertent energy 
to balance its affiliated generators' schedules, Exelon contends it is 
using an option that is unavailable to other generation resources and 
obtains a competitive advantage.
    698. TDU Systems argue that energy imbalances and inadvertent 
interchange may occur for many of the same reasons, e.g., telemetry 
failure, meter error, generator governor response to system problems, 
human error, and under- or over-supply of generation. TDU Systems state 
that deviations between load and supply, whether in the form of energy 
imbalances or inadvertent interchange, require adjustment or 
compensation, but there is no reason why the form of that adjustment or 
compensation should be different among transmission users. TDU systems 
explain that NERC's Final Report of the Control Area Criteria Task 
Force describes inadvertent interchange as one of the ``strong 
incentives'' driving the newer market participants, such as independent 
generators, to become control areas, and driving existing control area 
operators to retain their functions.
    699. TDU Systems explain that as the Commission acknowledged in 
Order No. 2000, for transmission providers in RTO regions, unequal 
access to balancing options can lead to unequal access in the quality 
of transmission service. TDU Systems oppose deferring consideration of 
inadvertent interchange issues until the Commission's order in the 
Mandatory Reliability Standards rulemaking proceeding in Docket No. 
RM06-16-000. TDU Systems argue that the Commission should place energy 
imbalance service on a footing as nearly comparable to inadvertent 
interchange as feasible by allowing like-kind exchanges of energy, at 
the incremental cost of their own supply portfolio, to remedy 
imbalances in lieu of the present paradigm of punitive charges.
    700. TDU Systems also argue that the Commission should require 
comparability between transmission providers and transmission customers 
by imposing charges for inadvertent interchange at the suppliers' 
incremental cost. FirstEnergy believes that the Commission should 
establish a tiered penalty structure that, similar to the Bonneville 
method discussed by the Commission, levies penalties based on the 
severity of the inadvertent energy violation. TDU Systems state that 
currently there are no penalties for under-supply even when one control 
area could be deemed to be intentionally ``leaning'' on the grid to 
arbitrage energy market prices; but there should be.
    701. FirstEnergy argues that a nationwide process should be 
established by the Commission to eliminate regional differences in the 
treatment of inadvertent energy. Constellation asks the Commission to 
require that transmission providers specifically separate imbalances 
from inadvertent energy and closely track and report the two.
Commission Determination
    702. As stated in the NOPR, the Commission finds that inadvertent 
energy is not comparable to energy and generation imbalances and, 
therefore, we will continue to allow inadvertent energy to be treated 
differently from energy and generation imbalances. Inadvertent energy 
represents the difference between a control area's net actual 
interchange and the net scheduled interchange. It is caused by the 
combined effects of all the generation and loads in the control area 
and generation and loads outside of the control area. Variables 
affecting inadvertent interchange often depend on the actions or the 
omissions of utilities other than the individual transmission providers 
and are distinct from those resulting in energy and generation 
imbalances.
    703. We also note that management of inadvertent energy is needed 
to adhere to NAESB standards. Historically, transmission providers have 
paid back inadvertent interchange imbalances in kind, which has not, as 
a general matter, proven to be problematic. Our primary concern with 
respect to inadvertent energy is to avoid incentives that could degrade 
reliability. To date, the return-in-kind approach has proven to be 
adequate as a general matter. However, if there is evidence that it is 
no longer sufficient to maintain reliability, or is allowing certain 
entities to lean on the grid to the detriment of other entities, the 
Commission has authority under FPA section 215 to direct the ERO to 
develop a new or modified standard to address the matter.
e. Netting/Crediting of Energy and Generator Imbalances
NOPR Proposal
    704. In the NOPR, the Commission sought comment on whether or not 
it is appropriate to allow a transmission customer to net energy and 
generator imbalances for a particular transaction within a single 
control area to the extent they offset.\404\ The Commission asked 
whether the potential to allow netting for offsetting imbalances 
contradicts the principle of encouraging good scheduling practices. The 
Commission sought further comment on what would be a reasonable 
percentage to net without concerns that allowing such netting would 
lead to reliability concerns from using unscheduled transmission or 
would cause redispatch costs by the transmission provider.
---------------------------------------------------------------------------

    \404\ For example, the Commission noted that a transmission 
customer scheduling 100 MWh over an hour, but with a load of 120 
MWh, would face an imbalance of 20 MW. The Commission questioned 
whether there should be a net charge if the customer also dispatched 
its generation to the same 120 MWh. Similarly, what if a 
transmission customer schedules 100 MWh, but has a load of 80 MWh 
and dispatches its generation to 80 MWh?
---------------------------------------------------------------------------

    705. The Commission also proposed to add provisions to schedule 4--
Energy Imbalance Service and schedule 9--Generator Imbalance Service of 
the pro forma OATT to reflect the Commission's policy that a 
transmission provider may only charge a transmission customer for 
either hourly generator imbalances or hourly energy imbalances for the 
same imbalance, but not both.\405\ The Commission explained that this 
policy only applies to a transmission customer that otherwise would be 
charged for both generator imbalances and energy imbalances for the 
same imbalance occurring within the same control area.
---------------------------------------------------------------------------

    \405\ Imbalance Provisions Proceeding at 32,123 note 19 (citing 
Niagara Mohawk, 86 FERC ] 61,009 at 61,028).
---------------------------------------------------------------------------

Comments
    706. A number of entities believe that transmission customers 
should be permitted to net energy and generator imbalances to the 
extent that such imbalances offset.\406\ Ameren and FirstEnergy assert 
that netting better reflects the impact of imbalances. Morgan Stanley 
argues that allowing such netting provides a clear competitive benefit 
because it would allow competitive suppliers to offer a load following 
service in competition with the transmission provider. Sacramento 
agrees that netting of offsetting imbalances should be allowed

[[Page 12354]]

provided the transmission customer relies on reasonable load forecasts.
---------------------------------------------------------------------------

    \406\ E.g., Ameren, FirstEnergy, Xcel, Suez Energy NA, Morgan 
Stanley, Sacramento, TDU Systems, and Utah Municipals.
---------------------------------------------------------------------------

    707. Utah Municipals and Steel Manufacturers Association argue that 
the Commission should impose charges based on netted imbalances, both 
for each customer and across the system as a whole. PGP contends that 
there is no reason to charge for both imbalances if a generator 
overruns during the same hour when a load overruns, so long as the 
overruns cancel out within a given control area. Steel Manufacturers 
Association contends that the Commission should incorporate control 
area-wide netting of imbalances to ensure that penalties are only 
assessed on significant imbalances and energy imbalance charges do not 
become a windfall profit center for utilities. Utah Municipals suggest 
that the Commission provide that all imbalances be netted for each hour 
and that penalties (charges above or credits below actual costs) be 
imposed only when the system as a whole is out of balance by more than 
a de minimis amount and, even then, only on those customers whose 
imbalances fall in the same direction as the system imbalance. Utah 
Municipals note that Sierra Pacific has established a similar imbalance 
mechanism, which appears to be working well in its control area.
    708. TDU Systems argue that the netting rules should be 
sufficiently flexible to allow individual customers to net their 
transactions within an hour, a day, a week or a month, so long as the 
results keep the transmission provider economically whole. TDU Systems 
state that the Commission should not impose a cap on the quantity of 
netting allowed unless the transmission provider is able to demonstrate 
that good system performance requires such a cap. Ameren suggests that 
the Commission use a tiered system for determining when imbalances can 
be netted, but argues that a transmission customer should not be 
allowed to net offsetting imbalances elsewhere on the system if the 
imbalance has the potential to have a significant reliability impact.
    709. FirstEnergy and Utah Municipals contend that both point-to-
point and network transactions should be eligible for netting. Utah 
Municipals and NRECA in their reply comments note that the Commission's 
reference to ``a particular transaction'' does not mesh with the needs 
and practices of network customers, who do not attempt to match 
portions of their total hourly loads with particular resources or 
``transactions.'' Utah Municipals argue that the Commission's proposal 
should be modified to make clear that such customers should be 
permitted to net energy and generator imbalances within a single 
control area to the extent they offset, with no requirement that the 
imbalances be part of a single ``transaction.''
    710. Other commenters, however, contend that transmission customers 
should not be permitted to net energy and generator imbalances.\407\ 
For example, Entergy and Pinnacle believe that to permit netting of 
energy and generator imbalances is to undercut the very purpose of the 
imbalance provisions, which is to provide adequate incentives to 
schedule correctly and in accordance with good utility practice. 
Pinnacle asserts that, depending upon the location, energy or generator 
imbalances could create reliability or economic problems for specific 
areas of the system and it is important that the transmission operator 
know what is happening on its system and for the customer to adhere to 
accurate scheduling. SPP argues that allowing netting of imbalance 
energy between generation and load would allow price arbitrage that 
would be unjust and unreasonable. Indicated New York Transmission 
Owners assert that positive and negative imbalances do not actually 
offset, as the NOPR would suggest, but rather each imbalance 
independently places stress on the transmission system. Duke states on 
reply that, although several commenters support netting imbalances, not 
one entity supporting such netting has put forth a workable proposal 
for how to implement such netting where multiple generators are serving 
multiple loads.
---------------------------------------------------------------------------

    \407\ E.g., Entergy, Pinnacle, Indianapolis Power, and Indicated 
New York Transmission Owners.
---------------------------------------------------------------------------

    711. Entergy believes that independent generators must take full 
responsibility for meeting their own schedules, including making 
adjustments to their schedules to conform them to their operation in 
real-time. Entergy argues that a netting approach, however, would 
provide an incentive for a generator to over-generate above its 
schedule if its load proves to be greater than expected in real-time. 
Entergy argues that allowing the netting of these imbalances will 
result in the virtual elimination of transmission schedules.
    712. In instances in which transmission customers intentionally 
game the transmission system through netting, FirstEnergy contends that 
the transmission provider should have the ability to apply punitive 
measures through a Commission-mandated penalty process. FirstEnergy 
states that there appears to be no clear cut number which defines the 
boundary between ``good'' netting and ``bad'' netting associated with 
reliability issues and additional redispatch cost. During periods when 
transmission constraints exist, Entergy contends that it may in fact be 
ramping up some generators to respond to imbalances while ramping down 
other generation to respond to other imbalances at exactly the same 
time and, therefore, it is incorrect to assume that over-generation 
supplied by one IPP accompanied by under-generation from another IPP, 
even simultaneously, will have no operational effect or impose no costs 
on a transmission provider.
    713. Allegheny believes that allowing netting of hourly deviations 
inside the first deviation band on a monthly basis would not allow for 
full recovery of imbalance costs because balances that occur in on-peak 
periods cost more than imbalances that occur during off-peak periods. 
Allegheny contends that deviations within the first band should be 
measured and settled financially on an hourly or, at least, an on-peak/
off-peak basis, rather than allowing deviations during one part of the 
month to be offset by deviations in another part of the month. 
Indianapolis Power & Light Company argues that the imbalance volume 
could be within the allowed bandwidth tolerance, but still be 
significant enough to allow for the energy market participant to make 
money off of the price difference.
    714. Entergy also contends that a crediting mechanism for generator 
imbalances would be not appropriate. Entergy asserts that such a credit 
would result in indifference by generators by largely immunizing them 
from the costs resulting from their imbalances and, as a consequence, 
produce economic inefficiencies and a potential threat to system 
reliability. Entergy argues that the current method, which provides an 
incentive to generators to control their own imbalances, is appropriate 
because generators have a desire to accurately schedule to avoid 
imbalances. Entergy argues that a non-offending generator in one hour 
can be an offending generator in the next hour and that the credit will 
bankroll generators so that penalty payments in one hour will be offset 
and paid for by penalty receipts in another hour.
Commission Determination
    715. The Commission recognizes that there is a trade off between 
the competitive benefits of reducing imbalance charges, including 
allowing transmission customers to net energy and generation 
imbalances, and the reliability implications of the transmission 
provider needing to plan to accommodate such imbalances.

[[Page 12355]]

Allowing transmission customers to net imbalances would further 
comparability between the transmission provider's dispatch and the 
transmission customers serving load. However, netting and crediting 
could lessen the incentive for accurate scheduling and resulting energy 
or generator imbalances could create reliability or economic issues for 
specific areas of the system if the transmission provider cannot 
adequately plan for such imbalances.
    716. In weighing these tradeoffs, the Commission concludes that for 
both energy and generator imbalance services it is not appropriate to 
require transmission providers to allow netting of imbalances outside 
of the tier one band. We agree that netting can cause problems because 
netting would lessen the incentive for transmission customers to 
schedule accurately, and inaccurate schedules, in turn, could require 
actions by the transmission provider even when the imbalances offset. 
Where transmission constraints exist, a transmission customer whose 
load and generation was on net equal could still have an effect on the 
transmission system if, as Entergy contends, some generation is ramping 
up to respond to some imbalances while other generation is ramping down 
at exactly the same time. Similarly, where transmission constraints 
exist, if one IPP has a positive deviation from its schedule while 
another IPP has a corresponding negative deviation from its schedule, 
the transmission provider could need to ramp up generation in one area 
while simultaneously ramping down generation in another area. Further, 
we believe that flexible scheduling deadlines should allow transmission 
customers to change their schedules such that their loads can be 
accurately met and implementation of the tiered imbalance bands will 
ensure that charges corresponding to imbalances are just and 
reasonable.
f. Intra Hour Netting
NOPR Proposal
    717. Under the current pro forma OATT, energy imbalances occur when 
there is a difference between the scheduled and the actual delivery of 
energy to a load located within a control area aggregated over a single 
hour. As a result, if a transmission customer is under its scheduled 
level for the first half of a given hour, but over its schedule the 
second half of the hour, there would be no imbalance charge. The 
Commission did not address intra hour netting in the NOPR.
Comments
    718. Several commenters argue that the Final Rule should address 
within-hour deviations that occur when generator imbalances are 
calculated on an integrated hour basis.\408\ If the generator imbalance 
is measured over an integrated hour, as is typical of the current 
practice, TVA asserts that significant intra-hour swings may be masked.
---------------------------------------------------------------------------

    \408\ E.g., TVA, South Carolina E&G, and International 
Transmission.
---------------------------------------------------------------------------

    719. South Carolina E&G states that generators, unable to ramp 
precisely to the 15-minute schedules, often undergenerate in the 
initial part of the hour, then overgenerate in later parts of the hour, 
in order to integrate closer to the schedule when settled over the 
entire hour. South Carolina E&G contends these intentional swings 
burden the balancing authorities who are charged with continuously 
keeping Area Control Error within predefined limits. International 
Transmission argues that intentional swings in output can be quite 
severe, imposing operational strains on the system, negatively 
impacting the control area's ability to meet NERC Control Performance 
Standards, and potentially jeopardizing reliability.\409\ Entergy 
agrees that settling hourly energy imbalances with generators does not 
provide adequate incentives for generators to schedule and dispatch 
accurately within the hour. Entergy asserts that generators have 
imposed significant moment to moment swings within the hour requiring 
it to deploy its regulating reserves in response. Entergy states that 
it has been increasingly difficult to meet NERC's operating criteria 
for control area performance without committing, and incurring the 
costs for, additional regulating reserves. TVA contends that all 
generators should be required to ensure that the instantaneous 
generation level equals the scheduled output. International 
Transmission asks that the imbalance provisions in the Final Rule 
address this situation by either specifying penalties that may be 
assessed for within-hour variations or advising that transmission 
providers may implement their own penalties to the extent that within-
hour variations cause operational difficulties.
---------------------------------------------------------------------------

    \409\ International Transmission provides the example that a 
large generator with scheduled output of 100 MW for an hour might 
stay at zero for the first 50 minutes of the hour and then generate 
600 MW during the last ten minutes.
---------------------------------------------------------------------------

    720. South Carolina E&G contends that allowing generator imbalance 
settlements over a shorter period, such as at 15-minute intervals, 
together with the proposed tiered charges for imbalances, would provide 
better, more refined incentives for generators to more closely match 
their scheduled deliveries and would help balancing authorities reduce 
Area Control Error excursions. TVA suggests generator imbalances be 
measured on ten-minute intervals rather than integrated over an hour. 
These ten-minute imbalances would not be netted against other imbalance 
intervals, so as to avoid the problem of encouraging undergeneration 
followed by overgeneration and vice versa. In addition to having 
generator imbalance charges for generation outside the operating bands, 
TVA argues that there should be a separate charge assessed based on the 
peak generator imbalance between the scheduled and actual generation 
recorded instantaneously during the clock hour to provide a further 
incentive for proper generator scheduling.
    721. Pinnacle and Utah Municipals assert that a transmission 
provider should only charge hourly generator imbalances or hourly 
energy imbalances for the same imbalance. PGP argues that customers 
should pay only one charge for the net imbalance that occurs within a 
single control area, either energy or generation, unless congestion 
occurs inside a control area that requires redispatch.
Commission Determination
    722. The Commission concludes that it is appropriate to maintain 
the status quo of aggregating net generation over the hour in the pro 
forma OATT. Requests by transmission providers to adopt a shorter 
interval will continue to be considered on a case-by-case basis.\410\ 
The Commission acknowledges that shorter intervals may be appropriate 
in particular circumstances and, for this reason, declined to use a 
clock-hour interval in the Large Generator Interconnection Final 
Rule.\411\ There, the Commission permitted use of an interval 
``consistent with the scheduling requirements of the Transmission 
Provider's Commission-approved Tariff and any applicable Commission-
approved market structure.'' \412\ Allowing transmission providers to 
continue to propose alternative intervals for purposes of the pro forma 
OATT imbalance provisions is therefore appropriate provided that such 
proposals are consistent with relevant market structures.
---------------------------------------------------------------------------

    \410\ See Entergy Services, Inc., 102 FERC ] 61,014 (2003) and 
Entergy Services, Inc., 111 FERC ] 61,314 (2005).
    \411\ See Order No. 2003 at P 335.
    \412\ See pro forma LGIA Article 4.3.1

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[[Page 12356]]

g. Distribution of Penalty Revenues Above Incremental Cost
NOPR Proposal
    723. The Commission also sought comment in the NOPR regarding the 
treatment of revenues the transmission provider receives above the cost 
of providing the imbalance service.
Comments
    724. Various commenters state that the transmission provider should 
retain any amounts above the incremental cost of providing imbalance 
service. Ameren and Constellation argue such revenues should serve as a 
contribution towards the fixed costs of providing this service. Entergy 
argues that premium charges would compensate it for the administrative 
costs of maintaining an organization capable of providing this purchase 
and sales function and provide generators with an incentive to avoid 
mismatches between scheduled quantities and actual deliveries to 
Entergy. Entergy states that the Commission has previously recognized 
that these generator imbalance charges are analogous to the economy 
power rates that have historically included a percentage adder for out-
of-pocket costs to recover difficult-to-quantify costs.
    725. On the other hand, FirstEnergy states that the additional 
revenue derived from charges above incremental costs should be provided 
to generators and/or customers able to regulate load that provided the 
redispatch, commitment, or additional regulation reserves. Utah 
Municipals contend that the Commission should credit revenues from 
charges above incremental costs to accurately-scheduling customers, 
rather than to the transmission provider. Utah Municipals argue that 
the penalty portion of incremental and decremental charges and rates 
could be credited back to all transmission customers who incur 
imbalance charges and whose schedules fell within the first deviation 
band for that hour. Progress Energy suggests that all imbalance 
revenues above the cost of providing the imbalance should be 
distributed to all non-offending transmission customers, based on the 
weighted amount of each non-offending transmission customer's usage of 
the transmission provider's transmission system. TAPS and TDU Systems 
ask on reply that penalty revenues not be earmarked for retail 
customers.
    726. Morgan Stanley believes that imbalance charges should be 
``keep whole'' charges calculated and designed to reimburse whoever 
remedied whatever problem the imbalance caused while leaving the 
transmission provider financially indifferent.
Commission Determination
    727. In this Final Rule, the Commission has reformed existing 
imbalance provisions to reduce the variety of different methodologies 
used for determining imbalance charges and ensure that the level of the 
charges provide appropriate incentives to keep schedules accurate 
without being excessive. We also believe that transmission providers 
should have a consistent method of treating revenues received through 
imbalance penalties or charges that are in excess of incremental cost. 
The Commission has previously required transmission providers with 
significant imbalance penalties to develop a mechanism to credit 
penalty revenues to non-offending transmission customers.\413\ This was 
intended to remove the incentive of the transmission provider to hinder 
the development of other imbalance services that do not rely on 
penalties.\414\ We believe it is appropriate to maintain the 
requirement that transmission providers credit revenues in excess of 
incremental costs. Therefore, as part of their compliance filings in 
this proceeding, transmission providers are required to develop a 
mechanism for crediting such revenues to all non-offending transmission 
customers (including affiliated transmission customers) and the 
transmission provider on behalf of its own customers. Such a 
distribution of penalty revenues recognizes that transmission providers 
bear the responsibility to correct imbalances and often use their own 
facilities to do so.
---------------------------------------------------------------------------

    \413\ See Carolina Power & Light Co., 103 FERC ] 61,209 at P 25 
(2003) (CP&L); Entergy Svcs., 105 FERC ] 61,319, reh'g denied, 109 
FERC ] 61,095 at P 65-66 (2004).
    \414\ See Carolina Power & Light Co., 97 FERC ] 61,048 at 61,279 
(2001).
---------------------------------------------------------------------------

    728. We acknowledge that in the CP&L decision, the Commission 
declined to allow the transmission provider to allocate a share of 
imbalance penalty revenues to itself as a user of the transmission 
system on behalf retail customers. Given the reforms to the pro forma 
OATT imbalance provisions adopted in this Final Rule, we believe the 
circumstances presented in that case are no longer applicable. There, 
the Commission based its holding on its understanding that the high 
imbalance penalties imposed by the transmission provider were an 
interim measure that were intended to be in place only until an 
imbalance market was developed.\415\ In this Final Rule, we are 
adopting imbalance charges that are closely related to incremental cost 
and therefore minimize any incentive on the part of the transmission 
provider to rely on penalty revenues rather than seeking other methods 
of encouraging accurate scheduling. Under these circumstances, there 
remains no reason to exclude the transmission provider from receiving 
an appropriate share of penalty revenues.
---------------------------------------------------------------------------

    \415\ Id.
---------------------------------------------------------------------------

3. Credits for Network Customers
    729. In Order No. 888, the Commission established that network 
customers should be eligible for credits for customer-owned 
transmission facilities under certain circumstances. Specifically, 
section 30.9 of the pro forma OATT states that a network customer 
owning existing transmission facilities that are integrated with the 
transmission provider's transmission system may be eligible to receive 
cost credits against its transmission service charges if the network 
customer can demonstrate that its transmission facilities are 
integrated into the plans or operations of the transmission provider to 
serve its power and transmission customers. Section 30.9 also states 
that new facilities are eligible for credits when the facilities are 
jointly planned and installed in coordination with the transmission 
provider.
NOPR Proposal
    730. In the NOPR, the Commission proposed severing the link in the 
pro forma OATT between joint planning and credits for new facilities 
owned by network customers because such linkage can act as a 
disincentive to coordinated planning. The Commission proposed deleting 
from section 30.9 the language that permits transmission providers to 
refuse crediting for new network customer-owned facilities that are not 
part of its planning process, and adding language that puts a greater 
emphasis on comparability. Specifically, the Commission proposed that 
the network customer shall receive credit for transmission facilities 
added subsequent to the effective date of the Final Rule in this 
proceeding provided that such facilities are integrated into the 
operations of the transmission provider's facilities and if the 
transmission facilities were owned by the transmission provider, they 
would be eligible for inclusion in the transmission provider's annual 
transmission revenue requirement as specified in Attachment H of the 
pro forma OATT.
    731. In the NOPR, the Commission also declined to allow 
transmission providers as part of this proceeding to automatically add 
costs of credits to the transmission provider's cost of service. 
However, the Commission stated that a

[[Page 12357]]

transmission provider may propose to add an automatic adjustment clause 
to its rates in a filing submitted under section 205 of the FPA. The 
Commission also explained that it would not propose to make credits 
generically available to point-to-point customers that own transmission 
facilities, but clarified that if some facilities owned by a point-to-
point customer meet all the criteria for credits, consistent with the 
Commission's statement in Order No. 888, the Commission would address 
such situations on a fact-specific, case-by-case basis.\416\
---------------------------------------------------------------------------

    \416\ Order No. 888 at 31,742; Order No. 888-A at 30,271.
---------------------------------------------------------------------------

a. Severance of Credits and Planning
Comments
    732. The NOPR proposal to sever the link between transmission 
credits and joint planning by eliminating the joint-planning 
requirement for credits for new facilities constructed by network 
customers is supported by a cross-section of the industry.\417\ Exelon 
asserts that linking credits to network customers with coordinated 
planning simply creates an incentive for the transmission provider to 
avoid coordinated planning with the network customers so that the 
provider can avoid providing credits. In addition, the criterion of 
``jointly planned'' with the transmission provider provides little or 
no value for discerning what facilities should qualify for crediting 
treatment. Further, Exelon argues, tying credits to joint planning is 
no longer necessary because the Commission's regional planning 
initiatives will insure that most, if not all, newly constructed 
facilities will be jointly planned. While EEI disagrees that the joint 
planning provision has acted as a disincentive to joint planning, it 
agrees that the coordinated planning initiatives in the NOPR has made 
the link unnecessary.
---------------------------------------------------------------------------

    \417\ E.g., Allegheny, East Texas Cooperatives, ELCON, Exelon, 
FMPA, MDEA, MidAmerican, MISO, Suez Energy NA, Tacoma, TAPS, and 
Utah Municipals.
---------------------------------------------------------------------------

    733. FMPA also argues that the link between credits and planning 
discourages joint planning because companies can avoid transmission 
rate credits, often for competitors, by simply refusing to jointly 
plan. FMPA asserts that it makes no sense to create economic 
disincentives to joint planning. According to these commenters, 
transmission lines cannot be built without some exchange of 
information; the joint planning link may discourage the most productive 
exchange and can create needless and non-productive disputation over 
whether joint planning did or should have taken place.
    734. PGP points out, however, that credits for new facilities can 
only result from joint planning, because new facilities must be 
interconnected with the existing grid, and planning studies are 
necessary for that to happen. NorthWestern requests that the Commission 
reconsider its proposal to allow crediting of customer-owned facilities 
that have not been jointly planned with the transmission provider. 
NorthWestern contends that allowing the construction of network 
facilities and making a judgment after the fact is inefficient and will 
result in protracted litigation and facilities that do not serve the 
overall grid as efficiently as planned facilities. PNM-TNMP contends 
that the Commission's proposed action to ``sever the link'' will excuse 
the network customer from the coordinated planning process and can only 
operate at cross-purposes with the coordinated transmission planning 
goal that is addressed in the planning sections of the NOPR.
Commission Determination
    735. The Commission adopts the NOPR proposal to sever the link in 
the pro forma OATT between joint planning and credits for new 
facilities owned by network customers. The proposal received broad 
industry support, and we agree with these commenters that the link 
between credits for new facilities and the requirement for joint 
planning can act as a disincentive to coordinated planning, which is 
contrary to the Commission's original objective in adopting the 
provision. A transmission provider has an incentive to deny coordinated 
planning in order to avoid granting credits for customer-owned 
transmission facilities.
    736. We find that arguments against the proposal are largely 
theoretical and do not adequately take into account the coordinated 
planning provisions proposed in the NOPR. The coordinated planning 
initiatives that the Commission is adopting in the Final Rule will 
ensure that most, if not all, transmission facilities are planned on a 
coordinated basis, making it unnecessary to retain this provision of 
section 30.9.
b. The New Test to Determine Eligibility for Credits
    737. Comments support the test for new facilities proposed in the 
NOPR.\418\ Some argue that the test for network customer credits should 
continue to be whether the network customer's facilities provide 
capability and reliability benefits to the grid--the same standard that 
would apply to inclusion of the facilities in the transmission 
provider's cost of service if the transmission provider constructed the 
facilities.\419\ MidAmerican states that further clarification of this 
point in the Final Rule would be beneficial in minimizing disputes over 
this issue. Likewise, MidAmerican asks the Commission to clarify in the 
Final Rule that such credit can be applied only to network customers 
taking OATT service and not to transmission customers that are under 
non-OATT (i.e., grandfathered bundled agreements) contracts. PGP 
supports the new rules for granting credits to network customers, but 
argues implementation details should be left up to individual 
transmission providers.
---------------------------------------------------------------------------

    \418\ E.g., Allegheny, EEI, Exelon, MISO, Nevada Companies, 
South Carolina E&G, Suez Energy NA, and Tacoma.
    \419\ E.g., Allegheny, Ameren, and MidAmerican.
---------------------------------------------------------------------------

    738. Although several transmission providers support the continued 
use of the integration test,\420\ other commenters representing 
municipal and public power interests ask that the Commission reconsider 
or clarify its application.\421\ Some commenters argue that given the 
Commission's current interpretation of ``integration'' for transmission 
credit purposes and the historical application of the test, retaining 
any integration requirement for existing or new facilities conflicts 
with comparability or constitutes undue discrimination.\422\ TDU 
Systems argue that the integration standard has encouraged 
discriminatory behavior by allowing transmission providers to charge 
network customers for transmission provider facilities constructed to 
serve the transmission provider's native load, while refusing to pay 
the network customer for comparable customer-owned transmission 
facilities. TDU Systems further argue that the integration test has 
resulted in a form of ``and'' pricing since the TDU Systems, as network 
transmission service customers, remain obligated to pay their load 
ratio share of the full transmission revenue requirement of the 
transmission provider's system, including the cost of transmission 
facilities built to serve the transmission provider's own loads.
---------------------------------------------------------------------------

    \420\ E.g., EEI, MidAmerican, and Nevada Companies.
    \421\ E.g., FMPA, NRECA, and TAPS.
    \422\ E.g., East Texas Cooperatives, NRECA, TAPS, and TDU 
Systems.
---------------------------------------------------------------------------

    739. NRECA questions the Commission's statement in the NOPR that, 
in order to satisfy the integration

[[Page 12358]]

standard, a customer ``must demonstrate that its facilities not only 
are integrated with the transmission provider's system, but also 
provide additional benefits to the transmission grid in terms of 
capability and reliability and can be relied on by the transmission 
provider for the coordinated operation of the grid.'' \423\ According 
to NRECA, that statement identifies three nominal requirements for 
customer facilities--integration, benefits and ``relied upon''--as 
compared to the one nominal requirement for transmission provider 
facilities--integration. This is fundamentally inconsistent with 
comparability, NRECA continues, as the Commission seems to recognize in 
its rationale for adding the comparability requirement to new 
facilities.
---------------------------------------------------------------------------

    \423\ NRECA further notes that proposed OATT section 30.9 does 
not include these additional ``benefits'' and ``relied upon'' 
requirements. NRECA argues that these requirements cannot be part of 
the section 30.9, since regulatory preambles cannot vary the words 
of the rule, citing Wyoming Outdoor Council v. U.S. Forest Service, 
165 F.3d 43, 53 (D.C. Cir. 1999) (``[L]anguage in the preamble of a 
regulation is not controlling over the language of the regulation 
itself'').
---------------------------------------------------------------------------

    740. NRECA further argues that the NOPR failed to distinguish the 
proposed new standard in revised section 30.9 from the Commission's 
recent decision in North East Texas Electric Cooperative, Inc.,\424\ 
which found transmission provider facilities integrated on the grounds 
that a showing of any degree of integration is sufficient, rejected a 
``benefits'' requirement, and did not consider a ``relied upon'' 
requirement. East Texas Cooperatives argues that the Commission's 
decision in East Texas Electric Cooperative, Inc. v. Central and South 
West Services, Inc.,\425\ applied an integration requirement for 
customer facility credits that was different and stricter than the 
standard applied to a transmission provider's facilities.
---------------------------------------------------------------------------

    \424\ 108 FERC ] 61,084 (2004), reh'g denied, 111 FERC ] 61,189 
(2005).
    \425\ 114 FERC ] 61,027 at P 42 (2006), appeal docketed, No. 06-
1090 (D.C. Cir. Mar. 10, 2006).
---------------------------------------------------------------------------

    741. Regarding the application of the integration component, FMPA 
argues that, in order to avoid continued discrimination, it is 
important that the Commission reaffirm that ``additional benefits to 
the transmission grid in terms of capability, delivery options, and 
reliability'' \426\ are benefits, regardless whether the transmission 
customers or the transmission provider (or others) benefit. Similarly, 
FMPA continues, the requirement that facilities must ``be relied upon 
for the coordinated operation of the grid'' \427\ must equally include 
operations that serve transmission providers, customers or others.
---------------------------------------------------------------------------

    \426\ NOPR at P 256.
    \427\ Id.
---------------------------------------------------------------------------

    742. Comments on the comparability component of the proposed 
credits test for new facilities range from several requesting that the 
Commission adopt a comparability-driven analysis \428\ to one asking 
the Commission to eliminate the comparability component in favor of an 
integration-only analysis.\429\
---------------------------------------------------------------------------

    \428\ E.g., APPA, FMPA, and NRECA.
    \429\ Entergy.
---------------------------------------------------------------------------

    743. Some commenters argue that eligibility for credits should turn 
in the first instance on the comparability standard set forth in the 
NOPR, otherwise the proposal does not eliminate undue 
discrimination.\430\ NRECA argues that this requirement does not 
abandon integration because current Commission policy requires a 
Transmission Provider's facilities to be integrated for their cost to 
be rolled in to the transmission provider's annual transmission revenue 
requirement.\431\ APPA would apply an integration test only if the 
transmission facilities for which the customer seeks credits are found 
not to be eligible under this comparability standard.
---------------------------------------------------------------------------

    \430\ E.g., APPA, East Texas Cooperatives, FMPA, and NRECA.
    \431\ NRECA compares North East Texas Electric Cooperative, 
Inc., 108 FERC ] 61,084 (2004), reh'g denied, 111 FERC ] 61,189 
(2005) (finding transmission provider facilities integrated and 
rolling in their cost over transmission provider objection) with 
Mansfield Municipal Electric Department v. New England Power Co., 97 
FERC ] 61,134 (2001), reh'g denied, 98 FERC ] 61,115 (2002) (finding 
transmission provider facilities not integrated and rolling out 
their cost over transmission provider objection).
---------------------------------------------------------------------------

    744. TAPS states that, by eliminating the integration test and 
simply providing that customer-owned facilities would be eligible for 
credits to the extent they would be included in the transmission 
provider's rate base if they were owned by the transmission provider 
(i.e.comparability test), the Commission would avoid litigation over 
what (if anything) the separate ``integration'' requirement adds in the 
proposed formulation. If the integration terminology is retained in 
section 30.9, TAPS argues that the Commission at least should clarify 
that the new integration test is truly different from the old 
integration test and cannot properly be read as limiting the 
comparability requirement and that the Commission will not follow 
precedents developed in credits cases decided under the original 
section 30.9.
    745. To provide a comparability baseline and eliminate the need for 
an integration test, APPA recommends that transmission providers 
provide a detailed inventory of the existing facilities owned by 
transmission provider and network transmission customers that are 
included in their annual transmission revenue requirement. Network 
transmission customers could use the inventory, which would be updated 
annually, to assess whether they currently own transmission facilities 
comparable to those included in the transmission provider's 
transmission rate base, or to third-party transmission facilities for 
which credits are being provided.
    746. MDEA argues that proposed section 30.9 appears contrary to 
comparability principles by imposing a standard for transmission 
facilities owned by customers that is more stringent than the one 
applied to the transmission provider's own facilities. In MDEA's view, 
the NOPR proposal is inconsistent with prior Commission precedent to 
the extent comparability is not required in evaluating eligibility of 
existing facilities owned by transmission providers for cost 
recovery.\432\
---------------------------------------------------------------------------

    \432\ MDEA cites Florida Power and Light Co., 116 FERC ] 61,013 
(2006), and notes that the Commission applied principles of 
comparability to a transmission provider's existing facilities.
---------------------------------------------------------------------------

    747. TDU Systems ask that the Commission clarify that the 
comparability prong will be aggressively enforced. For example, TDU 
Systems request that the Commission consider a bright-line voltage 
criterion to address comparability, rather than leaving it to the 
transmission provider's discretion as to whether the facilities would 
be eligible for inclusion in the transmission provider's annual 
transmission revenue requirement.
    748. Arguing against the use of the comparability component, 
Entergy contends that it could cause significant confusion, and should 
in no way change the basic requirements needed to show integration of 
network customer facilities. According to Entergy, a network customer 
should be entitled to credits only when the transmission provider 
cannot meet the transmission provider's firm obligations without the 
customer's transmission facilities.
    749. On reply, MDEA states that the principle of comparability 
requires that there be no distinction based on ownership or between 
existing and new facilities. It further asserts that Entergy attempts 
to draw a distinction between customer-owned transmission facilities 
needed by the transmission provider to meet the transmission provider's 
obligations to native load and firm transmission customers (for which 
credits should be available) and

[[Page 12359]]

facilities that a network customer decides that it needs to meet its 
obligations. Entergy argues that credits should be available only for 
the former type of facility. According to MDEA, there is no 
justification for the distinction Entergy seeks to draw or the standard 
it proposes to apply. Network customers pay a full load ratio share of 
the embedded costs of the transmission grid, based on the premise that 
the entire grid is available and required to support network loads. In 
this regard, there is no difference between Entergy's native load and 
network customer loads. Transmission facilities required to meet 
network customer needs by definition are required to meet grid needs, 
provided that such facilities are integrated with the transmission 
network.
    750. Several commenters ask the Commission to consider crediting 
mechanisms other than the NOPR proposal.\433\ For example, Entergy and 
Exelon contend that new facilities should be eligible for credit only 
if determined through the regional planning process that such new 
facilities are needed, i.e., that a measurable system capability or 
reliability benefit is provided. In their view, this will avoid 
litigation of cases addressing questions of integration. Utah 
Municipals argue that the Commission should not discount the potential 
evidentiary value of joint planning in assessing eligibility for 
customer credits. Taking a more expansive view, APPA argues that 
network transmission customers also should be able to obtain credits 
for transmission facilities they build pursuant to an open and 
collaborative transmission planning process in their region or sub-
region. This additional opportunity for credits, according to APPA, 
would spur participation in the transmission planning process and would 
be superior to litigating the proper application of the integration 
standard.
---------------------------------------------------------------------------

    \433\ E.g., Entergy, Exelon, and Utah Municipals.
---------------------------------------------------------------------------

    751. Entegra argues that the Commission should make the crediting 
policy for network customers consistent with the Commission's policies 
for generator interconnection facilities, and require credits to be 
available for facilities that are integrated with the transmission 
grid, without any showing of additional benefits and irrespective of 
whether the service in question is interconnection service, network 
service, or point-to-point service. Entegra further argues that the 
Commission should allow customers to sell transmission credits to 
obtain transmission service elsewhere on the transmission provider's 
system. By allowing the development of a more liquid market for such 
credits, Entegra reasons, the Commission could increase the willingness 
of market participants to fund upgrades to the transmission system.
    752. TDU Systems request that the Commission recognize that 
inequities have occurred and, if any upgrades are required to make 
network customers' facilities comparable (or comparably integrated), 
the costs of such network upgrades should be rolled into the 
transmission providers' rates.
Commission Determination
    753. The Commission declines to adopt the credits test for new 
facilities proposed in the NOPR. The intent underlying that proposal 
was to prevent application of the integration test in a manner that 
exclusively benefits the transmission provider.\434\ After reviewing 
the comments, we conclude that the proposed test may not in fact 
accomplish this objective. The test proposed in the NOPR may not 
effectively set forth the relationship of the integration standard to 
the comparability requirement. We therefore revise the test as follows, 
to more accurately reflect the Commission's intent as expressed in the 
NOPR: A network customer shall receive credit for transmission 
facilities added subsequent to the effective date of the Final Rule if 
such facilities are integrated into the operations of the transmission 
provider's facilities; provided however, the customer's transmission 
facilities shall be presumed to be integrated if the transmission 
facilities, if owned by the transmission provider, would be eligible 
for inclusion in the transmission provider's annual transmission 
revenue requirement as specified in Attachment H of the pro forma OATT.
---------------------------------------------------------------------------

    \434\ See NOPR at P 256.
---------------------------------------------------------------------------

    754. Under our precedent, a transmission provider's facilities are 
presumed to provide benefits to the transmission grid, whereas a 
transmission customer must make an affirmative showing that its 
facilities provide benefits in order to qualify for credits.\435\ Under 
the test we adopt in this Final Rule, a transmission customer will be 
required to meet the integration standard under pro forma OATT section 
30.9 in order to receive a credit for its facilities.\436\ Because 
joint planning will no longer be required in order to obtain credits, 
we find that it is particularly important in this context to require a 
showing that a network customer's facilities provide benefits to the 
transmission provider's grid, i.e., a transmission customer should not 
be eligible for credits for facilities that the network customer may 
use to provide service for itself but that the transmission provider 
does not need to use to provide transmission service to any other 
customer. However, to ensure comparability, a presumption of 
integration will be afforded to transmission customer facilities if it 
is shown that, if owned by the transmission provider, such facilities 
would be eligible for inclusion in the transmission provider's rate 
base.
---------------------------------------------------------------------------

    \435\ See e.g., North East Texas Electric Cooperative, Inc., 108 
FERC ] 61,084; East Texas Electric Cooperative, Inc. v. Central and 
South West Services, Inc., 114 FERC ] 61,027.
    \436\ The integration standard, in brief, requires that to be 
eligible for credits under pro forma OATT section 30.9, the customer 
must demonstrate that its facilities not only are integrated with 
the transmission provider's system, but also provide additional 
benefits to the transmission grid in terms of capability and 
reliability and can be relied on by the transmission provider for 
the coordinated operation of the grid. Southwest Power Pool, Inc., 
108 FERC ] 61,078 at P 17 (2004) (citing Order No. 888-A at 30,271), 
reh'g denied, 114 FERC ] 61,028 (2006). This policy is premised on 
the principle that ``just as the transmission provider cannot charge 
the customer for facilities not used to provide transmission 
service, the customer cannot get credits for facilities not used by 
the transmission provider to provide service.'' Id. at P 20 (citing 
Order No. 888-A at 30,271 & n. 277); accord East Texas Coop., Inc. 
v. Central & South West Services, Inc., 108 FERC ] 61,079 at P 28 
(2004), reh'g denied, 114 FERC ] 61,027 (2006); Southern California 
Edison Co., 108 FERC ] 61,085 at P 10 (2004); Northern States Power 
Co., 87 FERC ] 61,121 at 61,488 (1999); Florida Municipal Power 
Agency v. Florida Power & Light Co., 74 FERC ] 61,006 at 61,010 
(1996), reh'g denied, 96 FERC ] 61,130 at 61,544-45 (2001), aff'd 
sub nom. Florida Municipal Power Agency v. FERC, 315 F.3d 362 (D.C. 
Cir. 2003).
---------------------------------------------------------------------------

c. Application of the New Test to Existing Facilities
Comments
    755. Several commenters object to the Commission's proposal to 
apply the new comparability test in section 30.9 to new facilities, and 
not to existing facilities.\437\ If the Commission requires the same 
integration standard for both existing and new facilities, East Texas 
Cooperatives ask us to specify which integration standard--the pre-
existing integration standard, or the new standard that applies the 
integration standard comparably--applies and explain the difference and 
the basis for that choice. MDEA, FMPA and TAPS argue that no 
distinction is warranted between the treatment of new and

[[Page 12360]]

existing facilities and that the same standard should apply.
---------------------------------------------------------------------------

    \437\ E.g., APPA, FMPA, MDEA, NRECA, and TAPS.
---------------------------------------------------------------------------

    756. TAPS clarifies that it is not suggesting that the standard be 
applied retroactively to past uses, but rather prospectively to 
existing facilities, with the key consideration being when the claim 
for credits is brought and not when the facilities are constructed. 
TAPS argues that it cannot be claimed that the revised standard should 
apply only to new facilities because the comparability requirement is 
new. To the contrary, TAPS contends that comparability has been the 
theme and bedrock foundation of the Commission's transmission open-
access requirement since its inception.
    757. APPA argues that the Commission effectively acknowledges in 
the NOPR that transmission providers have failed to plan new facilities 
jointly with their transmission customers for the last ten years under 
the current section 30.9, but offers no redress for this past 
discrimination.
Commission Determination
    758. We conclude that the new test for determining credits will 
apply only to transmission facilities added subsequent to the effective 
date of this Final Rule. A number of customer-owned transmission 
facilities have been developed, and resulting credits negotiated and 
litigated, under the prior test which the Commission determined to be 
just and reasonable at the time.\438\ We find no basis for revisiting 
the Commission's determinations in those cases in this Final Rule. On a 
prospective basis, however, given the increased planning and 
coordination we require in the Final Rule, we believe it appropriate to 
apply the new test for determining credits.
---------------------------------------------------------------------------

    \438\ See East Texas Electric Cooperative v. Central and South 
West Services, Inc., 114 FERC ] 61,027 (2006).
---------------------------------------------------------------------------

d. Cost of Customer Facilities Automatically Included in Transmission 
Provider Cost of Service Without a Rate Filing
Comments
    759. Several transmission providers argue that, contrary to the 
Commission's proposal, credits should be added automatically to the 
transmission provider's cost of service.\439\
---------------------------------------------------------------------------

    \439\ E.g., Allegheny, EEI, MidAmerican, and Nevada Companies.
---------------------------------------------------------------------------

    760. MidAmerican argues that requiring the transmission provider to 
defer including the cost of the transmission credit until its next 
filed transmission rate case penalizes the transmission provider's 
shareholders who must unfairly bear the cost of providing the credit 
until the next rate case. If the Commission does not allow automatic 
rate recovery of the incremental cost of credits, MidAmerican 
continues, the Commission should clarify that the customer will not be 
allowed transmission facility credits until the rate adjustments are 
filed and accepted by the Commission. MidAmerican explains that such 
filings would examine only the new revenue requirements to be added and 
should not require a general rate case for the transmission provider's 
entire revenue requirement. Nevada Companies likewise argues that 
credits should not be granted to network customers if the recovery of 
those credits is not provided for in the revenue requirement.
    761. TAPS agrees with the Commission's conclusion that it would not 
be appropriate in this rulemaking to allow transmission providers to 
automatically add costs of credits to their cost of service, and that 
such costs should continue to be evaluated as part of a regular 
transmission rate case (or recovered through an approved formula rate). 
APPA expresses concern that transmission providers may attempt to use 
the Commission's decision not to allow them to add the costs of credits 
associated with customer-owned transmission facilities automatically to 
their costs of service as a pretext for not granting such credits in 
the first instance (at least until they decide to file a new rate 
case). APPA continues that a transmission provider's decision not to 
exercise the option to file under FPA section 205 a new rate case or an 
automatic adjustment clause should not serve as a reason to allow it to 
decline to provide credits.
    762. EEI explains that the customary basis for not allowing single-
issue rate adjustments for new transmission facilities is that while 
one aspect of the transmission provider's costs may have increased, 
others may have decreased or load may have increased. This is not the 
case with respect to the inclusion of the transmission costs related to 
customer-owned facilities, EEI continues, since the existence of 
customer-owned facilities does not have any impact on the transmission 
provider's own cost of service. EEI concludes that a transmission 
provider should not be forced into what is essentially re-justifying 
its transmission cost of service simply because a customer receives a 
credit for the integration of its own facilities.
    763. Some commenters also address the option currently open to 
transmission providers to add an automatic adjustment clause to their 
rates through a rate filing with the Commission.\440\ EEI argues that 
if the concept of an automatic adjustment clause is just and reasonable 
for one transmission provider, it is equally just and reasonable for 
all transmission providers, and there is no need to adopt a case-by-
case approach. EEI further requests that the Commission clarify that 
its policy is to accept rate adjustments that incorporate the costs 
that transmission providers incur to provide credits related to 
customer-owned facilities, provided that the rate adjustment 
methodology is just and reasonable. MidAmerican contends that the 
revenue requirement of the transmission provider and those of 
transmission customers should not be co-mingled, rather, consistent 
with Commission precedent, the burden is on the transmission-owning 
customer to demonstrate to the Commission that its cost of service and 
revenue requirement used to establish the amount of the credit are just 
and reasonable before it can receive credits. As for nonjurisdictional 
entities, MidAmerican explains that they may file for a declaratory 
ruling from the Commission regarding their revenue requirement.
---------------------------------------------------------------------------

    \440\ E.g., Allegheny, EEI, Exelon, and MidAmerican.
---------------------------------------------------------------------------

    764. Allegheny argues that if the Commission continues to deny 
transmission providers an automatic adjustment clause for these 
credits, it should, at a minimum, assure transmission providers that 
transmission credits will be recognized as a cost of service in FPA 
section 205 rate proceedings.
    765. Entergy argues that the Commission should recognize that any 
filed agreement providing for payments of credits would be subject to 
the filed-rate doctrine.
Commission Determination
    766. We are not persuaded to generically allow automatic recovery 
of the costs of credits associated with integrated transmission 
facilities to the transmission provider's cost of service. These costs 
typically are considered and evaluated as part of a regular cost of 
service review process. Automatic recovery of the costs of credits 
would be contrary to our long-standing policy concerning single-issue 
rate adjustments, a policy we decline to modify here.\441\ 
Nevertheless, transmission providers continue to have the option to 
propose an automatic adjustment clause in their rates under

[[Page 12361]]

FPA section 205 to address the time lag between incurring costs 
associated with credits and the transmission provider's next rate case.
---------------------------------------------------------------------------

    \441\ See, e.g., City of Westerville, Ohio v. Columbus Southern 
Power Co., 111 FERC ] 61,307 (2005).
---------------------------------------------------------------------------

    767. Contrary to EEI's assertions, customer credits do not warrant 
an exception to the Commission's general policy regarding single-issue 
rate adjustments. EEI argues that customer credits should be treated 
differently because the existence of customer owned facilities, in 
EEI's view, does not have any impact on the transmission providers' own 
cost of service. Even if true, this fact would not obviate the 
Commission's policy. Regardless of whether the customer credit is 
deemed to impact the transmission provider's own cost of service, the 
costs it imposes may be offset by cost decreases in other areas, by 
load growth, or both. Allowing single-issue rate adjustments would 
enable a utility to increase the total rate charged by focusing solely 
on a single cost element, while avoiding scrutiny of all other 
determinants of the rate. The Commission has an obligation to ensure 
the justness and reasonableness of the total rate and it would be 
improper to allow a utility to raise rates by selectively focusing only 
on particular elements of its costs, while avoiding scrutiny of other 
rate inputs. The Commission has refused to allow such rate treatment 
except in the most limited of circumstances and we find no basis for 
deviating from that policy in this context. As explained above, a 
transmission provider that wishes to add an automatic adjustment clause 
to its rates may seek Commission approval for its methodology in a 
filing submitted under FPA section 205.
e. Point-to-Point Customers Not Eligible for Credits on Generic Basis
Comments
    768. Several commenters support the Commission proposal to not make 
credits generically available to point-to-point customers that own 
transmission facilities.\442\ APPA argues that if the frequency of 
cases seeking credits for facilities owned by point-to-point customers 
is high, then the Commission should reconsider its decision to use a 
case-by-case approach.
---------------------------------------------------------------------------

    \442\ E.g., APPA, Bonneville, EEI, Exelon, FirstEnergy, Nevada 
Companies, and TAPS.
---------------------------------------------------------------------------

    769. Some commenters encourage the Commission to clarify that 
point-to-point transmission customers that pay for upgrades should be 
compensated if such upgrades benefit the system.\443\ PGP argues that 
customers be given credits if they meet the same conditions as network 
customers who would qualify. Additionally, Entegra contends that 
denying credits for upgrades funded by point-to-point customers would 
overlook the Commission's past warnings that a customer funding any new 
facilities integrated with the grid should be entitled to credits 
because a transmission system ``cannot be dismembered'' or examined 
piecemeal.\444\
---------------------------------------------------------------------------

    \443\ E.g., FirstEnergy, Seattle, and Suez Energy NA.
    \444\ Citing Nevada Power Co., 101 FERC ] 61,036 at P 8 (2002).
---------------------------------------------------------------------------

Commission Determination
    770. The Commission adopts the NOPR proposal not to make credits 
generically available for point-to-point customers that own 
transmission facilities. As the Commission explained in the NOPR, a 
network customer takes a usage-based service which integrates its 
resources and loads and pays on the basis of its total load on an 
ongoing basis. The transmission provider includes the network 
customer's resources and loads in its long-term planning horizon and 
the two parties coordinate operations of their facilities through a 
network operating agreement. In this way, network service is comparable 
to the service that the transmission provider uses to serve its own 
retail native load, and credits for certain integrated network 
facilities are appropriate. The point-to-point customer, however, does 
not purchase integration service, nor does it sign a network operating 
agreement with the transmission provider. Because of the inherent 
differences between point-to-point and network service, we therefore 
decline to require that transmission providers make credits generically 
available to point-to-point customers that own transmission facilities. 
If a particular facility owned by a point-to-point customer meets all 
the criteria for credits, we will continue to address such situations 
on a fact-specific, case-by-case basis consistent with the Commission's 
statement in Order No. 888.\445\
---------------------------------------------------------------------------

    \445\ Order No. 888 at 31,742; Order No. 888-A at 30,271.
---------------------------------------------------------------------------

f. RTO and ISO Issues
Comments
    771. Several RTOs or ISOs assert that they should not be required 
to comply with the crediting provisions because their respective 
planning processes and procedures are superior to or obviate the need 
for those set forth in the NOPR.\446\ CAISO states that it does not 
oppose the Commission's proposal, provided that the Commission confirms 
that facilities cannot be integrated into CAISO's operations unless 
they are under CAISO's operational control, consistent with the 
Commission's prior rulings.
---------------------------------------------------------------------------

    \446\ E.g., Indicated New York Transmission Owners, ISO New 
England, PJM, and SPP.
---------------------------------------------------------------------------

    772. In Xcel's view, an RTO has no incentive to refuse to jointly 
plan to avoid paying a credit and there is thus good cause to allow an 
RTO to deviate from the language in the pro forma OATT relating to 
joint planning of new facilities in order to be considered for a 
facility credit. Xcel and International Transmission argue that RTOs 
should be allowed to incorporate network customer-owned facilities into 
RTO rates in the same manner as if they were constructed by a 
transmission owner, while ensuring against double recovery of both 
revenue requirements and network credits.
Commission Determination
    773. The Commission concludes that it would not be appropriate at 
this time to generically exempt all ISOs and RTOs from the Final Rule 
requirements regarding credits for network transmission customers. We 
will address issues relating to network transmission customers credits 
in the RTO and ISO context in orders addressing OATT reform compliance 
filings submitted by each RTO and ISO. The Commission determined 
previously that the existing tariffs of certain RTOs and ISOs provide 
opportunities for transmission customers to receive credit or the 
equivalent (e.g., Transmission Congestion Contracts, Firm Transmission 
Rights or Auction Revenue Rights) for building facilities or upgrades 
that are consistent with or superior to Order No. 888 
requirements.\447\ Each RTO and ISO will have the opportunity to show 
on compliance that this continues to be the case given the reforms 
adopted in this Final Rule.
---------------------------------------------------------------------------

    \447\ For example, NYISO's tariff provides that a facilities 
study will contain a non-binding estimate as to the feasible 
Transmission Congestion Contracts (TCCs) resulting from the 
construction of new facilities. There, upon completion of the 
transmission upgrade and the first subsequent centralized TCC 
auction, the NYISO will determine the incremental TCCs associated 
with the upgrade. See section 19.4 ``Facilities Study Procedures'' 
of NYISO's tariff. Similarly, PJM's tariff provides that an 
interconnection customer that undertakes responsibility for 
constructing or completing network upgrades and/or local upgrades to 
accommodate its interconnection request will be entitled to receive 
the incremental Auction Revenue Rights associated with such 
facilities and upgrades subject to conditions. See section 46.1 
``Right of Interconnection Customer to Incremental Auction Revenue 
Rights'' of PJM's tariff.

---------------------------------------------------------------------------

[[Page 12362]]

Other issues
Comments
    774. East Texas Cooperatives argue that the Commission should 
clarify that a network customer is entitled to transmission credits for 
its own transmission facilities and the facilities of member utilities 
for which the network customer arranges and pays for network 
transmission services. East Texas Cooperatives explain that a recent 
Commission decision \448\ allows transmission credits only for 
facilities owned by the generation and transmission cooperative (G&T) 
and not for its individual members, which in its view is contrary to 
past Commission precedent.
---------------------------------------------------------------------------

    \448\ East Texas Electric Cooperative, Inc. v. Central and 
Southwest Services, Inc., 108 FERC ] 61,077 at P 21-23 (2004), reh'g 
denied, 114 FERC ] 61,027 at P 43-44 (2006), appeal docketed, No. 
06-1090 (D.C. Cir. Mar. 10, 2006)
---------------------------------------------------------------------------

    775. FMPA asks that the Commission affirmatively state that it will 
exercise its jurisdiction to ensure that public power entities are 
compensated for transmission investment (including joint transmission 
projects) in the event of dispute with jurisdictional transmission 
providers. FMPA explains that the proposed revisions to section 30.9 
may be insufficient to address all problems that may arise, especially 
in regions without an RTO or an existing compensation method. NRECA 
asks the Commission to prohibit RTOs and ISOs from using a non-public 
utility's transmission facilities without compensating the entity 
simply because it has not joined the RTO or ISO. NRECA argues that 
comparable treatment requires compensation for use of a transmission 
owner's facilities, whether the owner is subject to Commission 
jurisdiction or not, and the Commission should not consider a 
transmission tariff to be just and reasonable if it allows unlawful 
trespass and conversion.
    776. TAPS asks the Commission to include language in section 30.9 
of the pro forma OATT that affirmatively states customers' eligibility 
for rate incentives for new facilities under recently established 
Commission policy. TAPS further requests that the Commission guard 
against a transmission provider blocking such incentive based credits 
by refusing to engage in joint development of transmission projects 
with its customers.
Commission Determination
    777. The Commission finds that there is not enough evidence on the 
record to make a generic determination on these issues and, instead, 
will address them on a case-by-case basis in response to appropriate 
filings under FPA sections 205 and 206. With regard to incentives for 
new facilities, the Commission has already addressed incentives for 
transmission infrastructure investment in Order No. 679.\449\ There the 
Commission identified specific incentives that it will allow when 
justified in the context of individual proceedings. With regard to 
FMPA's concerns regarding potential disputes over compensation for 
transmission investment by non-public utilities, we note that section 
12 of the existing pro forma OATT contains dispute resolution 
procedures. This Final Rule also requires transmission providers to 
propose a dispute resolution process as part of the coordinated 
planning process. Additionally, the Commission's Dispute Resolution 
Service is available to assist in developing a dispute resolution 
process, as well as the Commission via a formal complaint filed 
pursuant to section 206 of the FPA.
---------------------------------------------------------------------------

    \449\ Promoting Transmission Investment through Pricing Reform, 
Order No. 679, 71 FR 43294 (Jul. 31, 2006), FERC Stats. & Regs. ] 
31,222 (2006), order on reh'g, Order No. 679-A, 72 FR 1152 (Jan. 10, 
2007), FERC Stats. & Regs. ] 31,236 (2007).
---------------------------------------------------------------------------

4. Capacity Reassignment
    778. In Order No. 888, the Commission concluded that a transmission 
provider's pro forma OATT must explicitly permit the voluntary 
reassignment of all or part of a holder's firm point-to-point capacity 
rights to any eligible customer.\450\ With respect to the rate for 
capacity reassignment, the Commission concluded it could not permit 
reassignments at market-based rates because it was unable to determine 
that the market for reassigned capacity was sufficiently competitive so 
that assignors would not be able to exert market power. Instead, the 
Commission capped the rate at the highest of (1) The original 
transmission rate charged to the purchaser (assignor), (2) the 
transmission provider's maximum stated firm transmission rate in effect 
at the time of the reassignment, or (3) the assignor's own opportunity 
costs capped at the cost of expansion (price cap). The Commission 
further explained that opportunity cost pricing had been permitted at 
``the higher of embedded costs or legitimate and verifiable opportunity 
costs, but not the sum of the two (i.e., `or' pricing is permitted; 
`and' pricing is not).'' \451\ In Order No. 888-A, the Commission 
explained that opportunity costs for capacity reassigned by a customer 
should be measured in a manner analogous to that used to measure the 
transmission provider's opportunity cost.\452\
---------------------------------------------------------------------------

    \450\ See Order No. 888 at 31,696; pro forma OATT section 23.1.
    \451\ Id. at 31,740.
    \452\ Order No. 888-A at 30,224.
---------------------------------------------------------------------------

NOPR Proposal
    779. In the NOPR, the Commission noted that capacity reassignment 
does not appear to have developed into a competitive alternative to 
primary capacity since the issuance of Order No. 888. To facilitate 
development of this market, the Commission proposed to remove the price 
cap on capacity reassignment and allow negotiated rates for 
transmission capacity reassigned by transmission customers. The 
Commission explained that, because the price cap appears to have 
reduced customers' transmission options, removal of the cap may be 
warranted without a market-by-market analysis. Due to market power 
concerns, however, the Commission proposed to retain the price cap for 
capacity reassigned by the transmission provider's merchant function or 
its affiliates.
    780. The Commission proposed to monitor the market for reassigned 
capacity by requiring regular OASIS postings and quarterly reports from 
transmission providers using information submitted by reassigning 
customers. First, the Commission proposed retaining the existing 
posting and filing requirements for reassigned capacity transactions to 
ensure that capacity is equally available to all customers and to 
protect against undue discrimination and the potential exercise of 
market power.\453\ Second, the Commission asked several questions 
regarding OASIS postings and the data that should be required in 
quarterly reports related to capacity reassignments: (1) What 
information should be required in the quarterly reports and OASIS 
postings, i.e., information about the capacity released, the original 
rate paid for that capacity, the price charged to the assignee for the 
capacity, and the term of the assignment; (2) whether other information 
was necessary for operational and reliability purposes; (3) whether 
additional reports by assignors to the transmission provider are 
necessary and, if so, what information should be reported by assignors; 
(4)

[[Page 12363]]

should the Commission establish a new quarterly reporting process with 
a new form, or use the existing Electric Quarterly Report procedures; 
and (5) how frequently should OASIS postings be made.
---------------------------------------------------------------------------

    \453\ The existing OASIS posting requirements for reassigned 
capacity already require, if selling on OASIS, for sellers to 
include data elements such as the path name, point of receipt, point 
of delivery, source, sink, capacity requested, capacity granted, 
start time, stop time, and offer price. See 18 CFR 37.6(c)(5).
---------------------------------------------------------------------------

Comments
Lifting the Price Cap for All Transmission Customers
    781. Some commenters support eliminating the price cap for 
reassignment of transmission capacity in the secondary market.\454\ For 
example, EPSA states that the Commission is correct to recognize that 
negotiated rates are dynamic and provide a market discipline on the 
price for reassigned capacity. Entegra argues that the Commission's 
removal of rate caps on releases of natural gas pipeline capacity 
increased available peak capacity and facilitated the movement of 
capacity into the hands of those that value it most highly, proving 
that an uncapped capacity release market can be both competitive and 
result in just and reasonable rates for customers.\455\ Exelon supports 
eliminating the price cap, but asserts that, since the transmission 
customer is seeking to reassign the capacity, it is likely the capacity 
is not useful in gaining access to load and therefore is not very 
valuable. BP Energy contends that transparent competition between the 
transmission provider (marketing primary and subscribed but unutilized 
capacity) and transmission customers, with monitoring by the Commission 
and prospective capacity purchasers, will moderate if not eliminate the 
potential exercise of market power and encourage the release of 
capacity that is not otherwise used or useful. As a result, BP Energy 
urges the Commission to require transmission providers to facilitate a 
competitive capacity reassignment process, similar to that used for 
capacity release on natural gas pipelines.
---------------------------------------------------------------------------

    \454\ E.g., Allegheny, AWEA, Constellation, EEI, Entegra, EPSA, 
Exelon, Morgan Stanley, PPL, Seattle, Suez Energy NA, and TranServ.
    \455\ Citing Natural Gas Pipeline Negotiated Rate Policies and 
Practices, 114 FERC ] 61,034 (2006) (Brownell, Comm'r concurring).
---------------------------------------------------------------------------

    782. Some commenters support the proposal to retain the price cap 
for transmission providers and their affiliates.\456\ Seattle states 
that the Commission is correct to continue to cap prices for the 
transmission provider since the transmission provider is a regulated 
monopoly. In its reply, Entegra states that the Commission has found 
that having a pro forma OATT mitigates but does not eliminate a 
transmission provider's ability to leverage its monopoly power in 
transmission into market power in generation markets.\457\ Entegra 
further contends that Southern, Entergy, and other transmission 
providers have monopoly power in transmission markets in their service 
territories and without a cap would exploit that market power in the 
secondary market. Moreover, Entegra argues that allowing transmission 
providers and their affiliates to charge market-based rates for 
transmission capacity in the primary or secondary market would 
exacerbate the skewed incentives that already operate to discourage 
construction of much needed transmission facilities in many markets.
---------------------------------------------------------------------------

    \456\ E.g., APPA, AWEA, NRECA, Seattle, TAPS, and TDU Systems.
    \457\ Citing Public Service Electric & Gas Company, 78 FERC ] 
61,119 at 61,455 (1997) (granting market-based rate authority based 
in part on the adequate ``mitigation of market power'' as evidenced 
by a pro forma OATT).
---------------------------------------------------------------------------

    783. Many commenters contend that lifting the price cap for 
reassignment of transmission capacity only for unaffiliated 
transmission customers would be unreasonable.\458\ For example, Entergy 
argues that for the wholesale markets to work all wholesale market 
participants, including the transmission provider's affiliated 
marketers, must be treated comparably under the pro forma OATT. EEI 
contends that lifting the price cap can result in a more robust 
secondary market for transmission capacity and will reduce any risks 
that transmission customers may associate with being required to 
purchase transmission service for five-year terms in order to obtain 
rollover-rights. In addition, Manitoba Hydro asserts that changing the 
current one-year minimum term creates additional risks for transmission 
customers and therefore having the ability to re-sell the transmission 
capacity at market-based rates would assist transmission customers to 
better manage the financial risks involved with holding longer term 
contracts.
---------------------------------------------------------------------------

    \458\ E.g., Community Power Alliance, EEI, Entergy, FirstEnergy, 
Imperial, Manitoba Hydro, MidAmerican, Progress Energy, and Salt 
River.
---------------------------------------------------------------------------

    784. Some commenters support lifting the price cap for affiliates 
if caps are removed for non-affiliates, but are only generally 
supportive of lifting the price cap.\459\ If the Commission does lift 
the price cap, Southern argues that it should also lift the price caps 
for the transmission provider and its affiliates as well in order to 
counter efforts to corner the market and other related unforeseen 
consequences. MidAmerican agrees, asking the Commission to retain the 
cap for all transmission customers if the transmission provider and its 
affiliates are not allowed to resell capacity at market-based rates.
---------------------------------------------------------------------------

    \459\ E.g., MidAmerican, PNM-TNMP and South Carolina E&G.
---------------------------------------------------------------------------

    785. Several commenters argue that the Commission's justification 
for eliminating the price cap--namely, reducing the ability of non-
affiliated customers to exercise market power in the secondary market 
through competition among releasing customers, monitoring the market 
via quarterly reports, and continuing rate regulation of primary 
capacity--applies to energy and marketing affiliates as well.\460\ 
First, several commenters argue that the Standards of Conduct and 
existing pro forma OATT rules ensure that transmission provider 
affiliates have no more ability to obtain information about the 
transmission system or to reserve point-to-point transmission capacity 
than unaffiliated customers.\ 461\ Entergy contends that, although the 
Commission correctly concludes elsewhere in the NOPR that functional 
unbundling and Standards of Conduct requirements, if properly enforced 
are sufficient to address affiliate abuse concerns, the Commission 
seems to assume that those same protections cannot be effective where 
the reassignment of transmission capacity is concerned.
---------------------------------------------------------------------------

    \460\ E.g., EEI, Entergy, MidAmerican, PNM-TNMP, Progress 
Energy, Southern, and South Carolina E&G.
    \461\ E.g., Community Power Alliance, Entergy, Imperial, 
Manitoba Hydro, Salt River, South Carolina E&G, and Southern.
---------------------------------------------------------------------------

    786. Second, some commenters question the Commission's assertion 
that permitting transmission provider's energy and marketing affiliates 
to resell or reassign transmission capacity would give them the ability 
to favor their own generation.\462\ For example, EEI contends that 
transmission providers have no control over the reassignment process, 
and transmission customers have complete freedom to reassign 
transmission capacity to any customer they choose. Entergy points out 
that under Order No. 888 the assignor of capacity may deal directly 
with an assignee and without involvement of the transmission 
provider.\463\
---------------------------------------------------------------------------

    \462\ E.g., EEI, Entergy, MidAmerican, and Progress Energy.
    \463\ See Order No. 888 at 31,697.
---------------------------------------------------------------------------

    787. Third, some commenters disagree with the Commission's 
statement that lifting the price cap for affiliates may dampen 
transmission investment.\464\ These same commenters argue that there is 
no relationship between the transmission provider's obligation to build 
transmission

[[Page 12364]]

facilities to accommodate third party requests for transmission service 
and the ability of marketing and energy affiliates to resell unused 
transmission capacity at market-based rates. For example, Progress 
Energy and others contend that the transmission provider is obligated 
under the pro forma OATT to construct transmission facilities to meet 
all requests for transmission service.\465\ Progress Energy and EEI 
contend that the transmission customer will decide to purchase 
secondary market transmission capacity if it meets the reasonable needs 
of customers so long as the capacity is priced below the higher of the 
embedded cost of transmission service or the cost of expansion. EEI 
argues that the customer can require the transmission provider to 
construct additional capacity to accommodate the customer's request for 
service if secondary market service--whether offered by the 
transmission provider's marketing and energy affiliates or by a third 
party customer--is priced above the cost of expansion. In such 
situations, EEI and Progress Energy contend that the cost of expansion 
serves as a cap on the price at which both third party customers and 
the transmission provider's marketing and energy affiliates can resell 
transmission capacity. Moreover, Entergy argues that this is the same 
justification that the Commission relies upon to conclude that 
transmission customers would not hoard secondary capacity, and it is 
arbitrary for the Commission to ignore that principle in concluding 
that a transmission provider would hoard capacity.
---------------------------------------------------------------------------

    \464\ E.g., EEI, MidAmerican, and Progress Energy.
    \465\ E.g., EEI, Entergy and MidAmerican.
---------------------------------------------------------------------------

    788. Additionally, some commenters argue that lifting the price cap 
for affiliates will encourage transmission investment.\466\ 
NorthWestern contends that allowing transmission providers to collect 
more than their ceiling price when the market is willing to pay a 
higher price could further the Commission's goal of encouraging 
transmission investment to maintain reliability and keep pace with load 
growth. NorthWestern suggests that the Commission could place 
restrictions on the proceeds in excess of the ceiling price such that, 
within some specified period, the dollars must be reinvested into 
transmission facilities or be refunded back to customers.
---------------------------------------------------------------------------

    \466\ E.g., Entegra and NorthWestern.
---------------------------------------------------------------------------

    789. Several commenters contend that lifting the price cap only for 
non-affiliates could dampen participation in the secondary market and 
place affiliates at a competitive disadvantage.\467\ Community Power 
Alliance argues it is unfair for the Commission to now say that their 
separated marketing affiliates, which have abided by Commission rules 
like any other market participant, cannot now compete on an equal 
footing with other participants in the secondary market for 
transmission capacity. Rather than prohibit transmission providers' 
affiliates from reselling capacity, Manitoba Hydro suggests that a more 
equitable approach would be for the Commission to lift the price cap 
for all resold transmission capacity, except for transmission capacity 
administered by an affiliate's transmission provider.
---------------------------------------------------------------------------

    \467\ E.g., Community Power Alliance, EEI, FirstEnergy, 
Imperial, Northwest IOUs, Southern, and TVA.
---------------------------------------------------------------------------

    790. To the extent the Commission adopts the proposed restriction 
on affiliate reassignments, MidAmerican seeks guidance on whether the 
transmission provider is expected to assure that the assignee is a 
valid eligible customer under the pro forma OATT. Similarly, Southern 
encourages the Commission to carefully identify and evaluate the 
possible adverse effects of lifting any reassignment price caps. 
Southern asserts that such effects could include expanded involvement 
and influence by financial players driven exclusively by profit motives 
and who may not be subject to Commission regulation.
    791. Several commenters contend that the Commission should retain 
the price cap for the reassignment of transmission capacity for all 
customers, not just affiliates of the transmission provider.\468\ APPA 
argues that allowing the resale of such a scarce and valuable service 
to those who value the capacity more highly is a recipe for undue 
discrimination and unjust and unreasonable transmission rates, at the 
expense of end-use customers. While NRECA opposes the Commission 
proposal to remove the price cap, NRECA would support the proposal to 
retain the price caps for affiliates. Similarly, TAPS supports the 
decision not to lift the price caps for affiliates; however, TAPS urges 
the Commission to rethink the NOPR's proposal to otherwise lift the 
price cap for non-affiliates.
---------------------------------------------------------------------------

    \468\ E.g., Alcoa, APPA, International Transmission, Nevada 
Companies, NRECA, PJM, Public Power Council, TAPS, and WAPA.
---------------------------------------------------------------------------

    792. Several commenters argue that lifting the cap for any 
transmission customers would encourage the exercise of market power, 
including hoarding, and discourage transmission investment.\469\ If 
removal of the cap were effective in making reassignment more 
profitable, TAPS contends it would encourage hoarding of capacity on 
key paths that would run afoul of the directive in FPA section 
217(b)(4) to ensure the ability of LSEs to secure long-term rights for 
their long-term power supply arrangements. Northwest IOUs argue that 
lifting the price cap would encourage non-affiliated transmission 
customers to buy transmission capacity at cost and resell it at market, 
in an effort to reduce the amount of transmission capacity available 
for resource development and other long-term uses. PJM argues that the 
final rule should include a requirement that appropriate hoarding 
mitigation procedures be implemented should the price cap be removed. 
APPA argues that, if no transmission capacity is available in the short 
run from the transmission provider, and an LSE needs additional 
capacity to serve load within the next day or week, the fact that the 
transmission provider could build capacity in future years at an 
incremental rate has little if any bearing on the price that LSE is 
willing to pay for the next day, week, or month to avert a looming 
supply problem. TVA asserts that transportation prices rose drastically 
during periods of high demand or constraint after the price cap for 
resale of gas transmission capacity was removed in Order No. 637 for 
everyone except pipelines and their affiliates. TVA states that this 
benefited entities that could afford to hold capacity, but harmed those 
that had to buy additional capacity on a short-term basis.
---------------------------------------------------------------------------

    \469\ E.g., APPA, Nevada Companies, Northwest IOUs, NRECA, PJM, 
TAPS, and WAPA.
---------------------------------------------------------------------------

    793. Alcoa and Nevada Companies argue that there is a significant 
potential for abuse in connection with the removal of the cap, 
particularly in load pockets. Alcoa argues that it is not clear at this 
point that there are sufficient safeguards in place to prevent and 
monitor the exercise of market power, something that must be assured 
before the cap is lifted on transmission capacity resale. Nevada 
Companies contend the proposal to remove the cap may actually reduce 
utilization of the grid, contrary to its intended purpose. For example, 
Nevada Companies state that transmission customers who have locked up 
capacity in constrained markets will likely wait to the very last 
minute to make that capacity available in order to drive up the price, 
which will often result in the capacity not being utilized if 
transactions cannot occur quickly enough. Some


[[Continued on page 12365]]


From the Federal Register Online via GPO Access [wais.access.gpo.gov]
]                         
 
[[pp. 12365-12414]] Preventing Undue Discrimination and Preference in Transmission 
Service

[[Continued from page 12364]]

[[Page 12365]]

commenters contend that, like LMP in organized markets, allowing price 
signals via lifting the cap may not encourage transmission investment, 
but rather create entrenched interests that profit from the existence 
of congestion and oppose efforts to eliminate such congestion through 
transmission expansion.\470\ If transmission providers are forced to 
purchase capacity at higher prices on the secondary market, Imperial 
argues that their native load customers be harmed by such higher 
prices, which may in turn hamper transmission expansion contrary to the 
Commission's stated goals for promoting transmission investment.
---------------------------------------------------------------------------

    \470\ E.g., APPA, International Transmission, NRECA, Public 
Power Council, and Seattle.
---------------------------------------------------------------------------

    794. In addition, some commenters are skeptical of the Commission's 
assertion that existing market mechanisms are a sufficient deterrent to 
anticompetitive behavior.\471\ WAPA and TAPS argue that, while 
eliminating the price cap might increase customers' transmission 
options, the Commission still needs to conduct case-by-case market 
power analyses prior to lifting the cap.\472\ As a result, WAPA argues, 
it is critical for the Commission to identify and aggressively mitigate 
all transmission market power on an ex ante basis, rather than 
utilizing an ex post monitoring scheme as proposed in the NOPR. If the 
Commission lifts the price cap, certain commenters argue that the 
Commission should establish competitive bidding transaction 
standards.\473\ For example, Seattle asserts that a standards 
organization such as NAESB will need to establish bid/ask transaction 
standards and reporting formats and the Commission must periodically 
validate the assumption that the secondary market is workably 
competitive.
---------------------------------------------------------------------------

    \471\ E.g., Alcoa, APPA, Bonneville, TAPS, and WAPA.
    \472\ Citing Farmers Union Cent. Exch., Inc. v. FERC, 734 F.2d 
1486, 1508-10 (D.C. Cir. 1984) (concluding that ``undocumented 
reliance on market forces is insufficient to satisfy the 
Commission's regulatory responsibilities.''); California ex. Rel. 
Lockyer v. FERC, 383 F.3d 1006, 1013 (9th Cir. 2004).
    \473\ E.g., BP Energy, Seattle, and TranServ.
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Application of the Price Cap to Members of ISOs/RTOs
    795. Some commenters request clarification that, if the Commission 
retains the price cap for capacity reassigned by affiliates, that it 
not apply to entities that have turned over control and operation of 
their transmission facilities to an RTO, ISO or independent 
entities.\474\ For example, Constellation requests that the Commission 
clarify that the revised pro forma OATT does not impose the cap on 
affiliates of transmission owners that have turned their transmission 
facilities over to an RTO/ISO when they reassign transmission capacity 
on facilities operated by the RTO/ISO. While MISO takes no position on 
whether the Commission should retain its cap for stand-alone 
transmission providers and their affiliated customers, it argues that 
the cap makes no sense in the context of capacity reassignments 
administered by RTOs and ISOs. MISO observes that the NOPR cites 
affiliate preference and market power concerns as the basis for 
retaining the cap on reassignments by transmission providers and their 
affiliated customers, which MISO argues are not applicable in the RTO/
ISO context. Further, MISO argues that the ownership of transmission 
assets in an RTO/ISO is divorced from the provision of transmission 
service, and RTO transmission owners are transmission customers no 
different from any other customer class.
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    \474\ E.g., Ameren, Constellation, SPP, and TranServ. ISO New 
England and PJM argue that, as providers of transmission service, 
they have no affiliates and likewise are not bound by the 
Commission's reassignment proposal.
---------------------------------------------------------------------------

    796. On the contrary, APPA notes that the issue is whether the 
transmission customer holding transmission rights over a constrained 
path has the ability to exercise market power and charge unjust and 
unreasonable rates if the cap is lifted. APPA argues that the issue is 
the same in both RTO and non-RTO regions. In APPA's view, whether the 
public utility transmission provider has joined an RTO, does not affect 
the ability of its merchant affiliate to extract unjust and reasonable 
rents for the resale of scarce transmission rights.
Alternative Price Cap Proposals
    797. Some commenters propose alternatives to negotiated pricing of 
transmission capacity in the secondary market.\475\ While APPA supports 
retaining the current rate cap, it contends that firm point-to-point 
customers should be allowed to collect demonstrable out-of-pocket costs 
in addition to the maximum capped rate. Alcoa suggests that the 
Commission could stimulate the secondary market for transmission 
capacity by increasing the cap and allowing parties to charge a 
percentage over the original price paid. Seattle contends that the 
existing Commission policy could be incrementally modified to permit 
recovery of remarketing costs and recognize that, for many customers, 
the transmission right is held at a much higher per unit cost than the 
primary rate stated in the transmission provider's pro forma OATT (due 
in part to the fact that a customer may not use all of the capacity for 
which it has contracted).
---------------------------------------------------------------------------

    \475\ E.g., Alcoa, APPA, Manitoba Hydro, PGP, Sacramento, and 
Seattle.
---------------------------------------------------------------------------

    798. Sacramento proposes that prices for released capacity be 
capped at the amortized and rate-based cost of a transmission upgrade. 
Seattle states that costly redirect processes, including system impact 
studies, may be needed to create a reassignment product that has value 
to other customers, given that the point of receipt, point of delivery 
or both typically change in a reassignment. While the current pro forma 
OATT pricing model differentiates transmission rates based on term and 
time of day (monthly, weekly, daily, hourly), Seattle asserts that 
seasonal variations in the value of transmission rights offered for 
short-term reassignment are also worthy of consideration, especially in 
a region like the Northwest, where power production varies seasonally.
    799. MISO states that it believes the Commission should further 
strengthen its pro-competitive policy by permitting RTO/ISO 
transmission providers to offer firm point-to-point transmission 
service for drive-out/drive-through transactions at market-based rates, 
including ``rollover'' transactions. MISO states that the principles 
for allocating firm capacity on such interfaces should be the same as 
for reassigning capacity within an RTO: i.e., permitting customers that 
value the capacity more highly to benefit from it. MISO asserts that 
allowing market participants to compete based strictly on price on 
external interfaces would resolve many inefficiencies stemming from the 
cumbersome queue administration procedures currently used on such 
facilities. MISO states that the final rule should encourage RTOs and 
ISOs to introduce such competitive practices in their footprints.
    800. PGP proposes two alternative approaches. First, PGP proposes 
that the Commission could wait until a regional approach for pricing 
reassignments is developed in those areas of the country that still 
rely on reassignments of point-to-point capacity to create a secondary 
market in transmission service. Second, PGP proposes that any decision 
to remove the price cap could be made on a case-by-case basis after a 
filing by a point-to-point customer at the Commission, in which the 
applicant must meet standards developed by the Commission that 
demonstrate the lack of market power in relevant transmission or 
generator markets.

[[Page 12366]]

    801. South Carolina E&G requests that the Commission clarify how 
the cap is calculated if the Commission chooses to retain the price 
cap. International Transmission asserts that the Commission should lift 
the price cap, on an experimental basis, similar to the approach 
followed in the natural gas industry. Similarly, WAPA recommends that 
the Commission either retain the price cap or institute a separate 
rulemaking proceeding for the purpose of establishing detailed market 
analysis criteria for eliminating the price cap for specific 
transmission segments or paths.
Posting and Filing Requirements
    802. Some commenters support the proposal to require transmission 
providers to submit quarterly reports and make OASIS postings regarding 
reassignments of transmission capacity.\476\ Bonneville asserts that, 
at a minimum, transmission customers should be required to provide a 
downloadable file to the transmission provider for posting on the 
transmission provider's OASIS that identifies the assignee, the amount 
of capacity assigned or transferred, the date of the offer of 
assignment, and the rate and duration of the assignment. Other 
commenters argue that transmission customers should be given greater 
reporting responsibility.\477\ Southern contends that transmission 
providers should not be burdened with submitting quarterly reports and 
making OASIS postings based on assignment information provided to them 
by other assignors/assignees. Rather, Southern and EEI argue that 
assignment information should be filed by the respective assignors and 
assignees in connection with their Electric Quarterly Report filings 
and not by the transmission provider. PNM-TNMP contend that the 
Commission should prescribe specific reporting obligations and 
associated deadlines to the assignors and reporting obligations should 
also include appropriate consequences for non-compliance on the part of 
the assignor. Nevada Companies ask that a system be put in place to 
charge relevant transmission customers for the additional reporting if 
the transmission provider is required to do the reporting, either on 
the OASIS or through some other mechanism.
---------------------------------------------------------------------------

    \476\ E.g., Bonneville, FirstEnergy, and PJM.
    \477\ E.g., EEI, Entergy, Nevada Companies, PNM-TNMP, South 
Carolina E&G, Southern, and TVA.
---------------------------------------------------------------------------

    803. Some commenters argue that more information should be posted 
on OASIS beyond what was proposed in the NOPR.\478\ EEI asserts that 
the details the transmission customers should report on the OASIS and 
in the quarterly reports include: The identity of the primary market 
seller; the identities of the secondary market seller and purchaser; 
the points of receipt and delivery; the term of reassigned service; the 
quantity of the reassigned service; and the charge for the 
reassignment, expressed in dollars per MW-month, week, day, or hour as 
appropriate. Other commenters contend that the existing quarterly 
report is appropriate and a new report should not be instituted.\479\ 
TranServ argues that the existing OASIS posting template query and 
audit functions are sufficient and no new obligations should be 
required. As to frequency of OASIS postings, Seattle suggests seven 
days after a transaction and NorthWestern proposes that the OASIS 
postings be no more frequent than monthly.
---------------------------------------------------------------------------

    \478\ E.g., EEI, PJM, and Seattle.
    \479\ E.g., PJM, PNM-TNMP, and TranServ.
---------------------------------------------------------------------------

    804. Other commenters raise confidentiality concerns or state that 
business practice standards for capacity reassignment posting 
requirements would be required.\480\ Because these negotiated rates 
will be market sensitive, Allegheny asks the Commission not to require 
reporting and OASIS posting until the term of the reassignment has 
expired. NAESB states that capacity reassignment, including removing 
the price cap and allowing negotiated rates, could require posting 
standards for OASIS sites and the addition of significant functions to 
support such postings.
---------------------------------------------------------------------------

    \480\ E.g., Allegheny, Morgan Stanley, NAESB, Seattle, and 
TranServ.
---------------------------------------------------------------------------

    805. NAESB states that capacity reassignment including removing the 
price cap and allowing negotiated rates could require posting standards 
for the OASIS site, and significant functions added to support such 
postings. NAESB asserts that this will require a more comprehensive 
standards solution, which may include data aggregation by the 
transmission provider, reports prepared and posted quarterly including 
how the information is communicated between the transmission provider 
and marketer for collection, submittals of quarterly reports from the 
transmission provider to the Commission, changes to the OASIS S&CP, and 
determination of informational content and design of templates. NAESB 
states that posting is more complicated if the transmission provider is 
required to post information given to it by a marketer on its non-
standard products and requests Commission guidance regarding posting 
requirements.
Other Issues
    806. Some commenters argue that price caps are not limiting 
capacity reassignment under the current pro forma OATT.\481\ Williams 
contends that other non-price limitations on capacity reassignment, 
such as the requirement that the assignee utilize the same source and 
sink as the original customers, are the real reasons there has not been 
more capacity reassignment. Williams acknowledges that this bars 
network customers from reassigning transmission capacity and requests 
that Commission clarify that classification of a transmission customer 
as a network or point-to-point customer does not restrict the purchase 
or reassignment of transmission capacity. Sacramento similarly 
complains that one of the chief impediments to capacity reassignment is 
that network integration service customers are not permitted either to 
assign their capacity or to utilize it to make off-system sales. 
Sacramento contends that a point-to-point customer may utilize 
otherwise unused capacity to make sales ``off-system'' to third 
parties, while network customers cannot make full use of the 
transmission capacity for which they are paying.
---------------------------------------------------------------------------

    \481\ E.g., Powerex, Sacramento, TAPS, and Williams.
---------------------------------------------------------------------------

    807. Some commenters contend that timelines for the release of 
capacity should be clearly stated.\482\ APPA argues that section 13.8 
of the pro forma OATT provides too little time for LSEs attempting to 
make firm power supply arrangements to obtain even daily firm point-to-
point service using the capacity left unscheduled by other firm point-
to-point customers. Powerex and SPP also ask the Commission to set out 
clear rules, including timelines, for releasing unused transmission 
capacity for non-firm use to better encourage full and economically 
efficient use of the existing transmission grid.
---------------------------------------------------------------------------

    \482\ E.g., APPA, Powerex, and SPP.
---------------------------------------------------------------------------

Commission Determination
    808. To foster the development of a more robust secondary market 
for transmission capacity, the Commission concludes that it is 
appropriate to lift the price cap for all transmission customers 
reassigning transmission capacity. In Order No. 888, the Commission 
found that allowing holders of firm transmission capacity rights to 
reassign capacity would help parties manage the financial risks 
associated with their long-term commitments, reduce the market power of 
transmission providers by enabling customers to compete, and foster

[[Page 12367]]

efficient capacity allocation.\483\ Over the past ten years, however, 
it has become clear that capacity reassignment has failed to develop 
into a competitive alternative to primary capacity. In particular, the 
price cap has served to reduce customers' transmission options and 
impaired the development of a secondary market for transmission 
capacity. In order to achieve the goals originally stated in Order No. 
888, we therefore lift the price cap for reassigned capacity. We 
believe this will allow capacity to be allocated to those entities that 
value it most, thereby sending more accurate price signals to identify 
the appropriate location for construction of new transmission 
facilities to reduce congestion.
---------------------------------------------------------------------------

    \483\ Order No. 888 at 31,696.
---------------------------------------------------------------------------

    809. We decline to adopt the NOPR proposal to retain price caps for 
capacity resold by a transmission provider's merchant function or its 
affiliates.\484\ After reviewing the comments submitted in response to 
the NOPR, and further considering our ten years of experience 
regulating capacity reassignments, we conclude that retaining the price 
caps for this portion of the market would continue to impair 
development of the secondary market and is not otherwise necessary to 
ensure just and reasonable rates. We find there are no significant 
market power concerns to justify retaining the price caps for any 
transmission customer. Indeed, the Commission did not distinguish 
between affiliated and non-affiliated transmission customers when it 
initially found in Order Nos. 888 and 888-A that excess capacity 
reserved could be reassigned.\485\ The Commission instead placed a 
price cap on all reassignments of capacity out of a concern that the 
entire market for reassigned capacity was not sufficiently 
competitive.\486\ We now find that market forces, combined with the 
requirements of the pro forma OATT as modified in this Final Rule, will 
limit the ability of assignors to exert market power, including 
affiliates of the transmission provider. First, competition among 
reassigning customers will restrict the exercise of market power. 
Second, the continued regulation of rates for primary capacity will act 
as a further check to ensure rates for reassigned capacity remain just 
and reasonable. Finally, the amended rules we adopt below to govern the 
reassignment of capacity will increase our regulatory oversight of the 
secondary capacity market, allowing us to effectively monitor the 
secondary capacity market. There is thus no need to retain the existing 
price caps on reassigned capacity for any market participant.
---------------------------------------------------------------------------

    \484\ Because Order Nos. 888 and 888-A require a separation of a 
public utility's transmission function and its wholesale generating 
marketing (merchant) function, a transmission provider will take 
service under its OATT through its merchant function or affiliate.
    \485\ Order No. 888 at 31,696-97; Order No. 888-A at 30,219-25.
    \486\ Order No. 888 at 31,697.
---------------------------------------------------------------------------

    810. Our decision to lift the price caps for capacity reassignments 
by all transmission customers is motivated by growing concerns 
regarding the decrease in transmission investment and the corresponding 
increase in congestion costs, as described more fully in section III.C 
of this Final Rule. The Commission believes it is important to take 
every opportunity to explore more efficient use of the grid by industry 
participants, whether they are affiliates of the transmission provider 
or not. Eliminating the price cap for reassigned capacity will provide 
greater flexibility to respond to changing system conditions and 
alternatives for customers that value the capacity more highly. As 
commenters suggest, lifting the price cap will enhance the ability of 
customers that reserve long-term capacity for five-year terms in order 
to obtain rollover rights to resell that capacity if their needs 
change.\487\ Other customers may determine that it is more economic to 
acquire reassigned capacity reflecting market rates than reserve long-
term capacity. In either case, lifting the price cap will help ensure 
that, during peak demand periods, transmission capacity will be used by 
those that value it the most. Establishing a competitive market for 
secondary transmission capacity will thus send more accurate price 
signals that promote efficient use of the transmission system by 
fostering the reassignment of unused capacity.
---------------------------------------------------------------------------

    \487\ As explained in section V.D.3, the Final Rule extends from 
one year to five years the minimum term required to obtain a 
rollover right.
---------------------------------------------------------------------------

    811. While some commenters argue that lifting the cap encourages 
the exercise of market power, including hoarding, and discourages 
transmission investment, we find that competition among reassigning 
customers, continuing rate regulation of the transmission provider's 
primary capacity, and reforms to the secondary capacity market adopted 
below, combined with enforcement proceedings, audits, and other 
regulatory controls, will assure just and reasonable rates. The 
Commission discussed the possibility of transmission capacity hoarding 
in Order No. 888. The Commission noted that unscheduled firm capacity 
is available on a non-firm basis to other customers and, thus, there is 
little practical possibility of hoarding. Instead, the capacity 
reassignment provisions of the pro forma OATT provide an economic 
incentive to make that capacity available to third parties.\488\ This 
applies even when the entity obtaining transmission capacity under the 
pro forma OATT is the transmission provider.\489\ It is equally in the 
corporate interests of a transmission provider and its affiliates not 
to over-reserve or ``hoard'' transmission capacity. Under the pro forma 
OATT, the affiliate--and therefore the upstream corporate parent of the 
affiliate and the transmission provider--bears the cost responsibility 
for transmission capacity that it reserves but does not use to make 
wholesale sales. If the affiliate attempts to hoard transmission 
capacity, its upstream corporate parent loses revenues just like the 
non-affiliate. Like any other customer, an affiliate of the 
transmission provider should find it in its overall corporate interest 
to reassign transmission capacity to others with higher valued uses at 
negotiated rates.\490\
---------------------------------------------------------------------------

    \488\ Order No. 888 at 31,693.
    \489\ See Southwestern Public Service Company, 80 FERC ] 61,245 
at 61,905 (1997).
    \490\ Moreover, Order No. 889 required that all public utilities 
establish or participate in an OASIS that meets certain 
specifications and comply with Standards of Conduct designed to 
prevent employees of a public utility (or any employees of its 
affiliates) engaged in wholesale power marketing functions from 
obtaining preferential access to pertinent transmission system 
information. The Standards of Conduct mitigate the ability of an 
affiliate to hoard capacity or collect rates that are inconsistent 
with market conditions. As a result, we are less concerned in this 
instance about affiliates competing on the same terms as non-
affiliates. To the extent problems arise from affiliate 
participation in the secondary capacity market, we will revisit our 
decision here to lift the price caps for transmission providers and 
their affiliates.
---------------------------------------------------------------------------

    812. We reject the suggestion in the NOPR that lifting the price 
caps for the transmission providers' merchant function or affiliates 
will provide disincentives to build or expand the transmission system. 
Without congestion, the transmission provider's rate on file will serve 
as the de facto price cap and, if congestion exists, the ``incremental 
rate'' reflecting the transmission provider's cost of expanding the 
system should act as a price ceiling for long-term transactions. It 
would be unreasonable to expect a transmission customer to pay a rate 
for reassigned capacity that is higher than the cost of expansion when 
it could simply exercise its rights under the pro forma OATT as a 
cheaper alternative. To the extent there is a lag-time between the 
request for new transmission service

[[Page 12368]]

and the date on which new facilities would be available, the adoption 
of conditional firm service and modifications to redispatch service 
elsewhere in this Final Rule will mitigate the exercise of market power 
during the interim period. We believe that the reforms to rules 
governing reassignments of capacity discussed below, along with 
associated reporting obligations, will adequately limit the ability of 
capacity holders to exercise market power in the limited circumstances 
when neither primary transmission capacity nor these additional 
services are available.
    813. Several commenters raise concerns that lifting of the price 
ceiling could lead to speculative pricing. If high prices occur during 
periods of peak demand it is a legitimate reaction to supply and demand 
forces. As we explained in Order No. 637-A, ``[a] surge in the price of 
candles during a power outage is not evidence of monopoly in the candle 
market.'' \491\ To the extent that capacity is not being 
anticompetitively withheld from the market, high prices are the 
competitive responses to market conditions and should result in a more 
efficient allocation of capacity to those customers valuing it the most 
and a resulting expansion of transmission facilities.
---------------------------------------------------------------------------

    \491\ Order No. 637-A at 31,595.
---------------------------------------------------------------------------

    814. We emphasize that we are not deregulating or otherwise 
adopting market-based rates for the provision of transmission service 
under the pro forma OATT. Transmission providers will continue to be 
obligated to make ATC available to customers, including ATC associated 
with purchased but unused capacity. Transmission providers also will 
continue to be obligated to construct new facilities to satisfy a 
request for service if that request cannot be satisfied using existing 
capacity. The pro forma OATT therefore does not, and will not, permit 
the withholding of transmission capacity in an effort to exercise 
market power. Furthermore, the rates for transmission service provided 
under the pro forma OATT will continue to be determined on a cost-of-
service basis unless the transmission provider can demonstrate, on a 
case-specific basis, that it lacks market power. Nothing in this Final 
Rule affects the obligations of transmission providers to offer service 
under the pro forma OATT at cost-based rates. The only reform being 
adopted concerns the resale of capacity by transmission customers. 
Given that traditional regulation will continue to govern the sale of 
primary capacity under the pro forma OATT, we no longer believe that 
cost-of-service regulation is necessary or appropriate for secondary 
capacity.\492\
---------------------------------------------------------------------------

    \492\ Our findings here address the particular circumstances 
associated with the electric utility industry and are not intended 
to suggest that corresponding changes should be made to the rates 
for capacity release by customers of natural gas transportation 
capacity. Any such changes would be considered only after notice and 
comment and based on a record applicable to the natural gas 
industry.
---------------------------------------------------------------------------

    815. As with any innovative rate program, however, the Commission 
will monitor the secondary capacity market to ensure that participants 
are not exercising market power. To enhance oversight and monitoring by 
the Commission, we adopt reforms to the underlying rules governing 
capacity reassignments. First, we require that all sales or assignments 
of capacity be conducted through or otherwise posted on the 
transmission provider's OASIS on or before the date the reassigned 
service commences. The Commission thus eliminates the current ability 
of transmission customers to assign the transmission rights to another 
party with subsequent notification to the transmission provider.\493\ 
The mechanisms for negotiating a reassignment remain the same. The 
transmission customer may either request that the transmission provider 
make the capacity available on its OASIS or the transmission customer 
may negotiate the terms of an assignment bilaterally. In either 
instance, however, the resulting sale or assignment must be posted by 
the transmission provider on its OASIS prior to the date the reassigned 
service commences. We require transmission providers working through 
NAESB to develop appropriate OASIS functionality to allow such 
postings. Transmission providers need not implement this new OASIS 
functionality and any related business practices until NAESB develops 
appropriate standards.
---------------------------------------------------------------------------

    \493\ See Order No. 888 at 31,697.
---------------------------------------------------------------------------

    816. Second, we require that assignees of transmission capacity 
execute a service agreement prior to the date on which the reassigned 
service commences. Under the current pro forma OATT, transmission 
customers that have executed service agreements may negotiate and 
implement assignments of capacity without involving the transmission 
provider, subject to after-the-fact reporting and posting, provided the 
transmission customer has a market-based rate tariff on file.\494\ In 
order to increase our oversight of reassigned capacity, we find that 
all reassignments must instead be accomplished by the assignee 
executing a service agreement with the transmission provider that will 
govern the provision of reassigned service.\495\ This will effectively 
return the specified capacity to the transmission provider for the 
purpose of reassignment to the assignee.\496\ The assignment shall be 
only to the specified assignee, without any obligation that the 
capacity be made available to third parties, and shall not be subject 
to any queuing by the transmission provider since the assignee is 
merely accepting the assignor's already-approved service for a 
specified period.\497\ All of the non-rate terms and conditions that 
otherwise would apply to the transmission provider's sale of 
transmission capacity continue to apply in the case of a 
reassignment.\498\
---------------------------------------------------------------------------

    \494\ See Order No. 888 at 31,697 n.394; Order No. 888-A at 
30,224 n.151.
    \495\ The pro forma Form of Service Agreement for the Resale, 
Reassignment or Transfer of Long-Term Firm Point-to-Point 
Transmission Service is set forth in a new Attachment A-1 to the pro 
forma OATT.
    \496\ As reformed in this Final Rule, the structural mechanism 
for reassigning transmission capacity will be similar to the 
mechanism for releasing pipeline capacity. While parties may be able 
to negotiate the prices applicable to assigned capacity, the 
assignee will execute a service agreement directly with the 
transmission provider and, thus, there will no longer be a need for 
the assigning party to have on file with the Commission a rate 
schedule governing reassigned capacity. See Order No. 888 at 31,697 
n. 324. The transmission provider's OATT will govern the reassigned 
service. The assignee will pay the transmission provider for service 
at the negotiated rate and the transmission provider will bill or 
credit the assignor with any the difference between the negotiated 
rate and the assignor's original rate. As noted above, however, 
there will be no requirement for the transmission provider to create 
an auction for reassigned transmission capacity similar to the 
pipeline capacity reassignment program, since the underlying price 
caps are being removed for electric transmission capacity.
    \497\ To the extent the assignee desires to change its points of 
receipt or delivery, the limitations set forth in section 23.2 shall 
apply.
    \498\ See Commonwealth Edison Co., 78 FERC ] 61,312 at 62,336 
(1997); Boston Edison Co., 81 FERC ] 61,372 at 62,768 (1997); 
Southwestern Public Service Co., 80 FERC ] 61,245 at 61,905 (1997). 
The non-rate terms and conditions of reassigned service will 
therefore conform to the pro forma OATT. As a result, there is no 
requirement to file with the Commission service agreements for 
reassigned transmission service.
---------------------------------------------------------------------------

    817. Third, in addition to existing OASIS posting requirements, we 
require transmission providers to aggregate and summarize in an 
electronic quarterly report the data contained in these service 
agreements. As proposed in the NOPR, the use of quarterly reports will 
assist the Commission in gathering data to ensure the effectiveness of 
market forces and regulatory requirements to mitigate the exercise of 
market power. The Commission directs that this quarterly report be 
submitted electronically in spreadsheet format

[[Page 12369]]

consistent with the electronic filing system used for Electric 
Quarterly Reports so that it is readily accessible to the Commission 
and the public.\499\
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    \499\ The transmission provider should identify capacity 
reassignments in the Contracts tab of the EQR using the Product Type 
Name ``CAPACITY REASSIGNMENT.'' All terms must be fully described 
and rates provided. If no Product Name adequately captures the 
nature of a given aspect of the capacity reassignment, the assignor 
may use the Product Name ``OTHER,'' but that aspect must be fully 
described in the Rate Description field. If that description is over 
150 characters, the transmission provider may use multiple Contract 
Product lines to describe it. General instructions on how to file 
the EQR may be found at http://www.ferc.gov/docs-filing/eqr.asp.

---------------------------------------------------------------------------

    818. Taken together, these reforms to the rules governing 
reassigned capacity will increase transparency and facilitate our 
monitoring of the secondary market for transmission capacity. We do not 
believe it is necessary to require a market power analysis as a 
condition to exercising the right to reassign transmission capacity. 
Although market power analyses are one method for ensuring that market-
based rates remain just and reasonable, they are not the only 
method.\500\ To achieve the Commission's original goals for capacity 
reassignment expressed in Order No. 888, we adopt a more flexible 
approach in this area and rely on posting requirements and other 
regulatory controls to ensure that rates for reassigned transmission 
capacity remain just and reasonable. As noted above, we find that a 
market power analysis is not required because transmission providers 
continue to be obligated to satisfy requests for service--whether out 
of existing capacity or new facilities--at cost-based rates. 
Transmission capacity therefore cannot be withheld in an effort to 
exercise market power. Moreover, the posting and filing requirements 
adopted herein provide the Commission the necessary information to 
ensure that, even if an entity sought to exercise market power in the 
secondary market, such an attempt could be effectively detected.
---------------------------------------------------------------------------

    \500\ See Alternatives to Traditional Cost-of-Service Ratemaking 
for Natural Gas Pipelines and Regulation of Negotiated 
Transportation Services of Natural Gas Pipelines, 74 FERC ] 61,076 
(1996).
---------------------------------------------------------------------------

    819. We therefore disagree with commenters who assert that lifting 
the cap on reassignment contradicts judicial and Commission precedent. 
In Order No. 637-A, the Commission explained at length why Farmers 
Union \501\ and other precedent did not prevent the Commission from 
adopting negotiated rates for secondary capacity as part of a 
regulatory scheme that provides safeguards to ensure that rates remain 
just and reasonable.\502\ The court affirmed the Commission's removal 
of price ceilings for short-term capacity release shippers in the 
natural gas market established in Order Nos. 637 and 637-A, recognizing 
that non-cost factors such as the need to lift price ceilings to 
facilitate movement of capacity into the hands of those who value it 
most and the negotiated rates only to the secondary market 
distinguished the case from Farmers Union.\503\ The same is true here, 
given the non-cost factor advantages of lifting the price cap and the 
use of monitoring and enforcement of remedies to mitigate the exercise 
of market power.
---------------------------------------------------------------------------

    \501\ Farmers Union Central Exchange v. FERC, 734 F.2d 1486, 
1501 (D.C. Cir. 1984) (Farmers Union) (finding that Commission 
failed to justify relaxation of cost-based regulation of oil 
pipeline companies because it did not ensure rates would remain 
within the zone of reasonableness).
    \502\ Order No. 637-A at 31,558-72.
    \503\ Interstate Natural Gas Association of America v. FERC, 285 
F.3d 18 (D.C. Cir. 2002).
---------------------------------------------------------------------------

    820. The Commission directs staff to closely monitor the 
reassignment-related data submitted by transmission providers in their 
quarterly reports to identify any problems in the development of the 
secondary market for transmission capacity and, in particular, the 
potential exercise of market power. We direct staff to prepare, within 
six months of receipt of two years of quarterly reports, a report 
summarizing its findings. To inform our analysis, we encourage market 
participants to provide feedback regarding the development of the 
secondary capacity market and, in particular, to contact the 
Commission's Enforcement Hotline \504\ with any particular concerns as 
this market develops.
---------------------------------------------------------------------------

    \504\ Market participants may contact the Commission's 
Enforcement Hotline via telephone (202) 502-8390, toll-free 1-888-
889-8030, fax (202) 208-0057, or at http://www.ferc.gov/cust-protect/enforce-hot.asp
.

---------------------------------------------------------------------------

    821. Although several commenters argue that additional posting and 
filing requirements could be too burdensome and costly, the Commission 
does not believe this burden will be great. All capacity reassignments 
must be conducted or otherwise posted on OASIS and each assignee will 
be required to submit an executed service agreement for reassigned 
service. The transmission provider thus will have ready access to data 
necessary for the OASIS postings and electronic quarterly transaction 
reports. In any event, the Commission's access to this data is vital to 
ensure effective monitoring and oversight and, thus, we find that any 
burden on the transmission provider is outweighed by the need for 
transparency. To the extent the transmission provider incurs costs to 
maintain or report this information, Order No. 889 made clear that all 
OASIS users, including the transmission provider, pay all of the fixed 
costs of OASIS-related activities in wholesale rates and pay usage-
related variable costs and fees.\505\
---------------------------------------------------------------------------

    \505\ Order No. 889 at 31,625.
---------------------------------------------------------------------------

    822. With regard to confidentiality concerns, the Commission finds 
that the disclosure of reassigned capacity information is necessary for 
the Commission and market participants to effectively monitor 
transactions for undue discrimination and preference. Consistent with 
our determination in Order No. 2001, where similar concerns were raised 
regarding disclosure of information, we believe that disclosure will 
promote competition and make the market operate more efficiently.\506\ 
Moreover, public reports will provide customers with a certain level of 
price transparency to help them make informed decisions regarding the 
relative value of capacity on a particular path.
---------------------------------------------------------------------------

    \506\ See Order No. 2001 at P 94-129.
---------------------------------------------------------------------------

    823. We decline requests to require implementation of electronic 
auctions for reassigned capacity. While such mechanisms are in place in 
RTO and ISO markets, we conclude that it would be too great a burden to 
impose electronic auctions on other transmission providers simply to 
facilitate capacity reassignments. The continued use of OASIS, combined 
with the posting and service agreement requirements adopted here, 
should be sufficient to facilitate more efficient use of the grid and 
mitigate the exercise of market power.
    824. With regard to the requests that the Commission institute 
alternative specific timelines and other rules for the reassignment of 
capacity rights to ensure efficient use of the grid, we will not revise 
the rules set forth in the pro forma OATT. We do not have sufficient 
evidence in this proceeding to suggest that public utilities' existing 
scheduling timelines generally hinder customers from reselling unused 
transmission capacity or lead to capacity withholding.
    825. With regard to requests for network customers to reassign 
transmission capacity, we affirm our finding in Order Nos. 888 and 888-
A that capacity reassignments are available only to point-to-point 
customers.\507\ Point-to-point service under the pro forma OATT clearly 
sets forth defined capacity rights and is therefore reassignable. In 
comparison,

[[Page 12370]]

there are no specific capacity rights associated with network service 
and, thus, that service is not reassignable. Network service provides a 
network customer with a right to integrate its designated resources 
with its designated loads, in a generation pattern primarily determined 
by the customer. As a result, it would be difficult to determine at any 
moment in time exactly what portion of network service could be resold, 
because the network customer does not have a discrete capacity 
reservation and its usage of the transmission system varies as it 
attempts to most economically use its resources to meet its loads. To 
the extent an entity elects network service, it does so with the 
understanding that the service is not reassignable because there are no 
specific capacity rights to reassign.
---------------------------------------------------------------------------

    \507\ Order No. 888 at 31,696; Order No. 888-A at 30, 223.
---------------------------------------------------------------------------

 5. ``Operational'' Penalties
a. Unreserved Use Penalties
NOPR Proposal
    826. In the NOPR, the Commission proposed to clarify that 
unreserved use penalties apply to any circumstance where a transmission 
customer uses transmission service that it has not reserved.\508\ 
Specifically, the transmission customer would be subject to an 
unreserved use penalty in circumstances where the transmission customer 
has a transmission service reservation, but uses transmission service 
in excess of its reserved capacity. A transmission customer also would 
be subject to an unreserved use penalty if the transmission customer 
uses transmission service where it does not have a transmission service 
reservation. The Commission also proposed that a transmission customer 
would not be subject to an unreserved use penalty in circumstances 
where the transmission customer inappropriately uses a network service 
reservation to support an off-system sale.
---------------------------------------------------------------------------

    \508\ In the NOPR, we referred to an unreserved use penalty as 
an ``unauthorized use penalty.'' For the purpose of the Final Rule, 
we adopt the term ``unreserved use penalty'' as it more clearly 
articulates the nature of the penalty.
---------------------------------------------------------------------------

    827. The Commission sought comment on whether the current policy 
that limits unreserved use penalties to twice the standard rate for the 
entire service period has resulted in penalties that are not just and 
reasonable and, if so, it sought further comment regarding provisions 
that would yield unreserved use penalties that are just and reasonable.
(1) Unreserved Use of Transmission Service
Comments
    828. Several commenters express general support for the 
Commission's proposed clarification that unreserved use penalties apply 
to any circumstance where a transmission customer uses transmission 
service that it has not reserved.\509\ Several commenters support the 
Commission's proposed clarification, but suggest that the transmission 
provider should only assess unreserved use penalties when a 
transmission customer repeatedly uses transmission service that it has 
not reserved.\510\ For instance, PNM-TNMP believes penalty assessment 
should be optional and should be imposed on transmission customers that 
do not change their practices regarding transmission use and OATT 
compliance after being advised of their non-compliance.
---------------------------------------------------------------------------

    \509\ E.g., APPA and Bonneville.
    \510\ E.g., MidAmerican, Southern, and PNM-TNMP.
---------------------------------------------------------------------------

    829. Several commenters argue that transmission customers with 
special circumstances should not be subject to unreserved use penalties 
in the same manner as other transmission customers. For instance, 
Seattle believes unreserved use penalties can result in charges that 
are unjust and reasonable for intermittent resources, such as wind 
generators, that can not precisely schedule power in future periods, 
but are capable of controlling output. Seattle believes that unreserved 
use penalties should not apply if the transmission provider is able to 
operate the transmission system reliably. Seattle argues that an 
unreserved use penalty should only apply if scheduling parties have 
failed to respond to dispatchers' orders stating that system conditions 
necessitate curtailment of output. Southern disagrees with Seattle and 
states that, as a general principle, unreserved use penalties should 
not be based on whether reliability is threatened. TDU Systems 
recommend that the Commission consider treating inadvertent use of 
point-to-point transmission service in excess of reservations by an 
entity serving native load in multiple control areas as an energy 
imbalance in the control area in which the energy imbalance occurs, 
rather than an unreserved use of point-to-point service. In their reply 
comments, EEI and PNM-TNMP disagree with TDU Systems. EEI argues that 
energy imbalance charges compensate generators for the additional 
expense they incur to compensate for the customer's failure to schedule 
sufficient energy to serve its load and do not compensate the 
transmission provider for the use of the transmission system. EEI 
asserts that customers that use more transmission service than they 
schedule should be required to pay for that transmission service just 
like any other user of the system.
    830. Duke opposes the Commission's proposed clarification and 
suggests that an effective means of deterring and punishing unreserved 
use of transmission service is to charge the customer for the point-to-
point service necessary to support the transaction and, additionally, 
to make the customer subject to a civil penalty in cases of intentional 
or repeated unreserved use. TDU Systems argue on reply that a 
transmission provider should not be allowed to charge unreserved use 
penalties unless it employs software technology designed to identify 
unreserved use prior to operation.
    831. Several commenters suggest modifications to the manner by 
which transmission providers determine when unreserved use penalties 
should be assessed. TDU Systems believes unreserved use penalties 
should only be applied with prior Commission approval after notice and 
opportunity for hearing in order to limit the transmission provider's 
discretion in applying such penalties. To encourage regulatory 
certainty, Seattle suggests that the Commission implement tariff 
provisions that state a clear basis for application of unreserved use 
penalties.
    832. Several commenters ask that the Commission delete the proposed 
language added to section 30.4 of the proposed revised pro forma OATT 
regarding the unreserved use of a network resource beyond its 
designated capacity.\511\ In the event the Commission elects to retain 
this language, these commenters ask the Commission to clarify the 
language to expressly permit use of the undesignated portion of a 
remote network resource under secondary non-firm service (as a non-
network resource) and to preserve the customer's right to use the 
undesignated portion of the resource for other purposes (e.g., to serve 
its load on systems other than the host transmission provider or to 
make off-system sales). In its reply comments, Duke notes that the fact 
that a generator is designated as a network resource for a network load 
on one system does not prohibit a network load on a second system from 
obtaining non-firm energy

[[Page 12371]]

from that same generator using point-to-point and secondary network 
resource. Duke points out that the proposed revised section 30.4 
prohibits a network customer from using its firm network service to 
schedule power in excess of the DNR amount. Finally, TAPS asks the 
Commission to modify the language added to section 30.4 so that its 
terms are consistent with the terms used in the rest of the pro forma 
OATT.
---------------------------------------------------------------------------

    \511\ E.g., APPA, TAPS, TDU Systems, and EEI Reply.
---------------------------------------------------------------------------

    833. EEI recommends that a customer that takes unreserved 
transmission service, but that does not have a service agreement with 
the transmission provider, be deemed to have consented to the 
transmission provider's filing of a service agreement, so that the 
transmission provider has a basis for imposing both the prevailing OATT 
rate and the penalty charge on the customer. EEI also recommends that 
the Commission clarify that a customer that uses more transmission 
service than it has reserved also is subject to charges for ancillary 
services.
Commission Determination
    834. The Commission adopts the NOPR proposal that a transmission 
customer will be subject to unreserved use penalties in any 
circumstance where the transmission customer uses transmission service 
that it has not reserved. Specifically, a transmission customer will be 
subject to an unreserved use penalty in circumstances where a 
transmission customer has a transmission service reservation, but uses 
transmission service in excess of its reserved capacity. A transmission 
customer also will be subject to an unreserved use penalty if the 
transmission customer uses transmission service where it does not have 
a transmission service reservation, including the situations described 
in the Arizona Public Service Company (APS) audit report.\512\ We note 
that the transmission provider is subject to the same penalties when it 
takes transmission service under its OATT.
---------------------------------------------------------------------------

    \512\ Arizona Public Service Co., 109 FERC ] 61,271 at P 6 
(2004) (APS). APS contained two findings that Commission audit staff 
characterized as unauthorized use of transmission service. In the 
first finding, APS's wholesale merchant function did not request and 
pay for point-to-point service to support some of the off-system 
power sales it made at trading hubs where APS system resources were 
directly connected. In the second finding, APS incorrectly treated 
the Phoenix Valley 230kV system as a single node on its transmission 
system. As a result, off-system sales made by generators connected 
to the Phoenix Valley system should have been, but were not, 
supported by point-to-point service.
---------------------------------------------------------------------------

    835. Our decision to clarify the application of unreserved use 
penalties will eliminate a potential source of discretion in the 
implementation of the pro forma OATT and will assist the Commission in 
its enforcement of the OATT obligations. The unreserved use penalty 
itself will help discourage disorderly use of transmission service. 
Charging a transmission customer for just the unreserved transmission 
service used, as suggested by Duke, would not provide a sufficient 
incentive to procure adequate transmission service, even with the 
threat of possible civil penalties. In addition, an operational penalty 
rather than a civil penalty is a more appropriate default remedy, even 
though certain circumstances may warrant a civil penalty in addition to 
an operational penalty. In most instances, an unreserved use penalty 
can be applied in a relatively mechanical manner. As a result, an 
operational penalty has a relatively low administrative burden and 
still provides a clear signal to transmission customers regarding the 
cost of non-compliance.\513\ We do not agree with TDU Systems' proposal 
that a transmission provider be required to employ software designed to 
identify unreserved use if the transmission provider wants to charge 
unreserved use penalties. As we explain below, we adopt reforms in this 
Final Rule that will reduce the level of unreserved use penalties for 
instances of inadvertent unreserved use. For instance, we reduce the 
period over which a one-time inadvertent use will be penalized from one 
month to one day. We believe that this and other reforms are sufficient 
to address TDU Systems' concerns.
---------------------------------------------------------------------------

    \513\ The unreserved use penalties thus work in conjunction with 
imbalance penalties described in section V.C.2 of this Final Rule to 
reduce incentives to take actions that impair the reliability of the 
transmission system.
---------------------------------------------------------------------------

    836. We will not adopt Seattle's suggestion to add provisions to 
the pro forma OATT that specify all circumstances that constitute use 
of transmission service without a transmission service reservation. Any 
list of transmission customer actions that would be deemed to 
constitute use of transmission service without a transmission service 
reservation will necessarily be incomplete and out-of-date given the 
dynamic manner by which trading patterns and practices evolve. We 
believe that Commission actions, such as in APS, will provide a 
sufficient guide to circumstances that constitute use of transmission 
system without a transmission service reservation. We also reject TDU 
Systems' suggestion that unreserved use penalties be applied only after 
Commission approval. As mentioned above, an unreserved use penalty can 
be assessed in a relatively straightforward manner in most cases. As a 
result, there will typically be little need for the Commission to 
become involved. That said, a transmission customer can always file a 
complaint with the Commission protesting an unreserved use penalty.
    837. We will not exempt any class of transmission customer from the 
potential assessment of unreserved use penalties. We do not agree with 
Seattle's assertion that unreserved use penalties can result in charges 
that are unjust and reasonable for intermittent resources, such as wind 
generators, that can not precisely schedule power in future periods. 
Unreserved use penalties are based on the transmission capacity 
reserved rather than the transmission service scheduled, so an 
intermittent resource's inability to precisely schedule power in future 
periods is irrelevant, as long as the resource has reserved sufficient 
transmission capacity to deliver the resource's full output. We also do 
not agree with TDU Systems' suggestion that unreserved use of 
transmission service by an entity serving native load in multiple 
control areas should be treated as an energy imbalance in the control 
area in which the energy imbalance occurs, rather than an unreserved 
use of point-to-point service. In this regard, we agree with EEI that 
energy imbalance charges compensate the transmission provider for the 
additional expense it incurs to compensate for a transmission 
customer's failure to schedule sufficient energy to serve its load and 
do not compensate the transmission provider for the use of the 
transmission system.
    838. We will not limit unreserved use penalties to instances where 
the unreserved use jeopardizes the reliable operation of the 
transmission system. Unreserved use penalties are intended, in part, to 
give transmission customers an incentive to reserve and pay for the 
appropriate level of transmission service so that transmission service 
is allocated in an orderly fashion. A transmission customer that uses 
unreserved transmission service requires the transmission provider to 
take some action to accommodate the additional use of the system. Some 
penalty is warranted even in those instances when the transmission 
provider's accommodations are sufficient to avoid curtailment of 
transmission service to other transmission customers. Absent a penalty 
in all instances, transmission customers would have an increased 
incentive to under-reserve transmission service, which would lead to an 
increase in the likelihood that system reliability would be impaired. 
In

[[Page 12372]]

addition, a transmission customer that uses more transmission service 
than it has reserved, even in periods when system reliability has not 
been impaired, has nonetheless disturbed the orderly allocation of 
transmission service.
    839. In response to comments requesting that we remove the language 
added to section 30.4 of the proposed revised pro forma OATT regarding 
the unreserved use of a network resource beyond its designated 
capacity, we clarify our intent in modifying section 30.4. The 
Commission has identified instances when a transmission provider has 
scheduled delivery of off-system non-designated short-term purchases 
using transmission capacity reserved for designated network 
resources.\514\ The intent of the language added to section 30.4 of the 
pro forma OATT was to clarify that network customers are subject to 
unreserved use penalties when they schedule delivery of off-system non-
designated purchases using transmission capacity reserved for 
designated network resources. We clarify, however, that a network 
customer may use the undesignated portion of a remote network resource 
to serve network load using secondary network service and may use the 
undesignated portion of the resource for other non-network service 
purposes, such as third-party sales, as long as the network customer 
acquires the appropriate point-to-point transmission service. Moreover, 
because a transmission provider does not have to ``take service'' under 
its own OATT for the transmission of power that is purchased on behalf 
of bundled retail customers, it is free to use the undesignated portion 
of a remote network resource to serve its bundled retail 
customers.\515\ If the transmission provider desires to use a remote 
network resource for non-native load purposes, such as third-party 
sales, it must acquire the appropriate point-to-point transmission 
service.\516\
---------------------------------------------------------------------------

    \514\ See MidAmerican Energy Co., 112 FERC ] 61,346 (2005); 
PacifiCorp, 118 FERC ] 61,026 (2007).
    \515\ See Order No. 888-A at 30,216-17.
    \516\ See id. at 30,217.
---------------------------------------------------------------------------

    840. In order to ensure that the transmission provider has a basis 
for charging an unreserved use penalty, we modify section 13.4 of the 
pro forma OATT to provide that a customer that takes unreserved point-
to-point transmission service and does not have a service agreement 
with the transmission provider is deemed to have executed the 
transmission provider's form of service agreement for point-to-point 
service. In addition, we clarify that a customer that uses more 
transmission service than it has reserved is also subject to charges 
for ancillary services. The ancillary service charges will be based on 
just the period of unreserved use. For instance, if a transmission 
customer has unreserved use during two hours on the same day, the 
customer must pay the ancillary service charges for those two hours, 
rather than for the entire day. This modification is appropriate, as 
the transmission provider is entitled to compensation for the ancillary 
services it provides when it provides transmission service. We also 
will modify section 3 of the pro forma OATT to reflect this rule.
(2) Treatment of Inappropriate Use of Network Service as an Unreserved 
Use of Point-to-Point Transmission Service
Comments
    841. A few commenters argue that a transmission customer that 
inappropriately uses a network service reservation to support an off-
system sale should be subject to unreserved use penalties.\517\ Other 
commenters request clarification or modifications to the Commission's 
proposal regarding the treatment of transmission customers that 
inappropriately use a network service reservation to support an off-
system sale. TAPS asks the Commission to clarify that a transmission 
provider that inappropriately uses network service to support an off-
system sale is required to pay for point-to-point service to support 
the off-system sale and potentially is liable for civil penalties, as 
the Commission proposed in the NOPR. Suez Energy NA suggests that an 
affiliate of the transmission provider that violates network tariff 
provisions by making unauthorized sales should also disgorge unjust 
profits from such sales. TDU Systems urges the Commission not to impose 
civil penalties for inadvertent use of network service by an LSE when 
it serves its own native load on a neighboring system.
---------------------------------------------------------------------------

    \517\ E.g., APPA and PNM-TNMP.
---------------------------------------------------------------------------

Commission Determination
    842. The Commission declines to adopt the NOPR proposal to exempt a 
network customer or transmission provider that inappropriately uses 
network transmission service to support off-system sales from 
unreserved use penalties. As mentioned above, one of the purposes of 
unreserved use penalties is to encourage orderly use and acquisition of 
transmission service. A network customer or transmission provider that 
inappropriately uses network transmission service to support off-system 
sales potentially uses or acquires transmission service that should be 
allocated to other transmission customers. In addition, the network 
customer or transmission provider has not paid for transmission service 
as required. Therefore, we conclude that a network customer or 
transmission provider inappropriately using network transmission 
service to support off-system sales should be subject to unreserved use 
penalties. We will evaluate the appropriateness of civil penalties in 
addition to unreserved use penalties on a case-by-case basis and will 
not exempt, as a matter of general policy, inadvertent use of network 
service by an LSE when it serves its own native load on a neighboring 
system as suggested by TDU Systems. A network customer or transmission 
provider that inappropriately uses network transmission service to 
support off-system sales also may be required to disgorge unjust 
profits from such sales, as the Commission may determine on a case-by-
case basis.
(3) Penalty Rate for Unreserved Use of Transmission Service
Comments
    843. Transmission providers generally assert that the Commission's 
current policy of limiting unreserved use penalties to twice the 
standard rate for the entire service period has yielded just and 
reasonable rates.\518\ EEI contends that if the customer is required to 
pay an unreserved use charge only for the period of unreserved use, the 
customer would have an incentive to reserve service for less than its 
maximum expected use and simply pay unreserved use charges in the hours 
in which it exceeds that usage. EEI concedes, however, that the maximum 
period for which the unreserved use charge should be assessed is one 
month. For example, EEI acknowledges that it would be unreasonable to 
charge a customer that takes yearly service a penalty for an entire 
year because of, for instance, a single hour of unreserved use. In 
addition, EEI suggests several modifications to the current unreserved 
use penalty policy. EEI suggests the Commission include, in the pro 
forma OATT, provisions stating that the penalty charge for unreserved 
use of transmission service is equal to twice the standard rate for 
transmission service. EEI recommends that the Commission establish a 
policy that a

[[Page 12373]]

customer that uses transmission service without a reservation must pay 
a penalty equal to twice the rate for transmission service for the 
greater of the period of unreserved use or one month.
---------------------------------------------------------------------------

    \518\ E.g., EEI, Bonneville, MidAmerican, Nevada Companies, and 
PNM-TNMP Reply.
---------------------------------------------------------------------------

    844. Transmission customers generally assert that unreserved use 
penalties should be limited to twice the standard rate for the period 
of unreserved use.\519\ Transmission customers who take this position 
argue that using the service period rather than the period of 
unreserved use as the basis for the penalty charge discriminates 
against transmission customers with longer term transmission service 
reservations.\520\ For instance, AWEA believes that applying an 
unreserved use penalty based on the reservation period rather than the 
period of unreserved use has resulted in charges that are not just and 
reasonable. AWEA asserts that such a policy would also be 
discriminatory because, if the customer causing the unreserved use had 
made a shorter reservation, its penalty would be much lower. TDU 
Systems argue in its reply comments that there is little to be gained 
from charging inadvertent unreserved use more than twice the standard 
rate for the period of unreserved use.
---------------------------------------------------------------------------

    \519\ E.g., APPA, AWEA, TAPS, and TDU Systems.
    \520\ E.g., APPA, AWEA, TAPS, and TDU Systems Reply.
---------------------------------------------------------------------------

    845. Several commenters suggest that unreserved use penalty charges 
greater than twice the standard rate for the entire service period 
should be limited to instances of intentional unreserved use.\521\ 
Nevada Companies note that there are some marketing entities that are 
consistently abusing the current policy and recommends that the 
Commission consider more severe penalties for continuous carelessness 
in tagging or a repeated pattern of unreserved use of the transmission 
system. Southern believes the transmission provider should be permitted 
to charge increased unreserved use penalties if a transmission customer 
consistently uses transmission services it has not reserved. TDU 
Systems disagree on reply comments, arguing that a penalty equal to 
twice the applicable charge is sufficient to deter unreserved use of 
transmission service.
---------------------------------------------------------------------------

    \521\ E.g., NRECA, Nevada Companies, and Southern.
---------------------------------------------------------------------------

Commission Determination
    846. We will continue giving transmission providers discretion in 
setting their unreserved use penalty rates, although those rates will 
need to be consistent with this Final Rule. Penalty charges must be 
based on the period of unreserved use rather than the period for which 
service is reserved, subject to the following principles. First, the 
unreserved use penalty for a single hour of unreserved use will be 
based on the rate for daily firm point-to-point service, even if the 
transmission provider has a rate for hourly firm point-to-point 
transmission service on file. Second, as a general rule, more than one 
assessment for a given duration (e.g., daily) will increase the penalty 
period to the next longest duration (e.g., weekly). The unreserved 
penalty charge for multiple instances of unreserved use (i.e., more 
than one hour) within a day will be based on the rate for daily firm 
point-to-point service. The unreserved penalty charge for multiple 
instances of unreserved use isolated to one calendar week would result 
in a penalty based on the charge for weekly firm point-to-point. The 
unreserved use penalty charge for multiple instances of unreserved use 
during more than one week during a calendar month will be based on the 
charge for monthly firm point-to-point.\522\
---------------------------------------------------------------------------

    \522\ There are a number of possible permutations of these 
principles. For instance, a transmission customer that has 25 MW of 
unreserved use in two hours on one day during the first week of the 
month and 50 MW of unreserved use in two hours on one day during the 
last week of the month will pay an unreserved use penalty based on 
the rate for 25 MW of daily firm point-to-point service and 50 MW of 
daily firm point-to-point service. A transmission customer that has 
25 MW of unreserved use on two separate days during the first week 
of the month and 50 MW of unreserved use in two hours on one day 
during the last week of the month will pay an unreserved use penalty 
based on the rate for 25 MW of weekly firm point-to-point service 
and 50 MW of daily firm point-to-point service. A transmission 
customer that has 25 MW of unreserved use on two separate days 
during the first week of the month and 50 MW of unreserved use on 
two separate days during the last week of the month will pay an 
unreserved use penalty on 50 MWs of monthly firm point-to-point 
service.
---------------------------------------------------------------------------

    847. Our determination is based, in part, on agreement with those 
commenters arguing that using the period for which a transmission 
customer has reserved service rather than the period of unreserved use 
as the basis for the penalty charge discriminates against transmission 
customers with longer term transmission service reservations. We are 
mindful, however, that basing unreserved use penalties on only the 
period of unreserved use could give the transmission customer an 
incentive to reserve service for less than its maximum expected use and 
simply pay unreserved use charges in the hours in which it exceeds that 
usage. We believe the unreserved penalty regime we articulate in this 
Final Rule will provide a reasonable incentive to ensure that 
transmission customers reserve the appropriate level of transmission 
service without unduly charging a transmission customer for inadvertent 
unreserved use. In addition, transmission customers will continue to be 
subject to civil penalties on a case-by-case basis, so attempts to game 
this penalty regime could result in additional penalties depending on 
the specific facts at issue. We reject the suggestion in some comments 
that the transmission provider should only assess unreserved use 
penalties where a transmission customer repeatedly uses transmission 
service that it has not reserved. Rather, we find that penalties are 
appropriate for all unreserved uses of the system. Because we are 
allowing penalties to be based on the period of unreserved use, not the 
reservation period, such penalties do not unduly charge a transmission 
customer for inadvertent unreserved use. This penalty regime will apply 
to all instances where a transmission customer has an unreserved use of 
transmission service, regardless of whether the transmission customer 
had an existing relevant transmission service reservation but for a 
lesser amount of service.
    848. A transmission provider that wants to charge unreserved use 
penalties must explicitly state the penalty rate in its tariff. The 
Commission retains the current policy established in Allegheny that the 
unreserved use penalty rate may not be greater than twice the firm 
point-to-point rate for the period of unreserved use, as defined 
above.\523\ We continue to believe that penalties up to twice the 
relevant firm point-to-point rate are just and reasonable, given the 
new definition for the penalty period. As a result, we establish a 
rebuttable presumption that unreserved use penalties no greater than 
twice the firm point-to-point rate for the penalty period defined above 
are just and reasonable. As we discuss above, the transmission customer 
must face a penalty in excess of the firm point-to-point transmission 
service charge it avoids through unreserved use of transmission service 
or the transmission customer will have no incentive to reserve the 
appropriate amount of service.
---------------------------------------------------------------------------

    \523\ Allegheny Power System, Inc., 80 FERC ] 61,143 at 61,545-
46 (1997) (Allegheny).
---------------------------------------------------------------------------

    849. The Commission thus concludes that a penalty of twice the 
standard rate is not excessively punitive, particularly given the 
definition of the penalty period established in this Final Rule. 
Without evidence to the contrary, we

[[Page 12374]]

believe an unreserved use penalty equal to twice the applicable rate 
should create the appropriate incentive to transmission customers to 
purchase the correct amount of transmission service. Nonetheless, we 
will allow transmission providers to make a filing under section 205 of 
the FPA to propose an unreserved use penalty in excess of twice the 
relevant firm point-to-point rate for pervasive unreserved use. 
Transmission providers that propose such a rate must establish that a 
higher penalty rate is required to combat pervasive unreserved use of 
transmission. In arguing for such a higher penalty rate, the 
transmission provider must address why the standard penalty rate that 
penalizes repeated unreserved use is not adequate to discourage 
repeated instances of unreserved use of transmission service.
b. Distribution of Operational Penalties
NOPR Proposal
    850. In the NOPR, the Commission proposed to have the transmission 
provider distribute to non-offending, unaffiliated transmission 
customers operational penalties incurred by the transmission provider's 
merchant function or its affiliates.\524\ For those transmission 
providers subject to operational penalties, the Commission proposed to 
require the transmission provider to make an annual compliance filing 
to notify the Commission of the amounts of such operational penalties 
incurred during the year and to propose a method to identify non-
offending, unaffiliated transmission customers to which the 
transmission provider would distribute penalty amounts. In addition, 
the Commission also proposed to allow a transmission provider to avoid 
an annual compliance filing by making a one-time filing to propose a 
mechanism through which it would identify non-offending, unaffiliated 
transmission customers and a method by which it would distribute the 
operational penalties it or its affiliates have incurred to the 
identified transmission customers. Finally, the Commission proposed to 
prohibit transmission providers from recovering for ratemaking purposes 
or through any service or facility under the Commission's jurisdiction 
any cost it incurs when it or an affiliate pays an operational penalty.
---------------------------------------------------------------------------

    \524\ An operational penalty explicitly defines the charge 
associated with a set of pre-defined activities (e.g., unreserved 
use of transmission service, completing request studies outside of 
the 60-day due diligence deadline) that are not in compliance with 
specific provisions of the OATT.
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Comments
    851. Transmission customers along with several other commenters 
support the Commission's proposal to distribute operational penalties 
paid by the transmission provider's merchant function to non-offending, 
unaffiliated transmission customers.\525\ Entegra and Morgan Stanley 
advocate extending the proposal so that the transmission provider 
distributes operational penalties paid by all transmission customers to 
non-offending unaffiliated transmission customers. Entegra also notes 
that the Commission's policy in the natural gas setting is that 
pipelines must credit all penalty revenues back to non-offending 
shippers. Entegra argues that the precedent the Commission cited in 
proposing that operational penalties paid by the transmission provider 
be distributed to non-offending, unaffiliated transmission customers 
applies equally to penalties paid by affiliated and unaffiliated 
transmission customers.\526\
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    \525\ E.g., APPA, ELCON, Entegra, TAPS, TDU Systems, Sacramento, 
and Seattle.
    \526\ Entegra cites Carolina Power & Light Co. and Florida Power 
Corp., 103 FERC 61,209 at P 24 (2003) (Carolina Power & Light).
---------------------------------------------------------------------------

    852. With regard to unreserved use penalties, NRECA and TDU Systems 
argue that the Commission should encourage transmission providers to 
supervise inadvertent unreserved use and notify the customer of such 
occurrence rather than rely on large unreserved use penalties. They 
argue it is better to prevent unnecessary costs than to approve post 
hoc penalties for unintentional unreserved use that could have been 
prevented.
    853. A number of transmission providers oppose the portion of the 
Commission's proposal that would prohibit their non-offending 
affiliates from receiving a portion of the operational penalties the 
transmission provider incurs.\527\ For instance, PNM-TNMP asserts that 
the Commission should allow the transmission provider's non-offending 
affiliates, which are abiding by the same rules as other transmission 
customers in accordance with Standards of Conduct, to be eligible to 
receive a portion of the operational penalties the transmission 
provider incurs. In the specific case of unreserved use penalties, 
Southern does not support distributing penalties imposed on a 
transmission provider's affiliate to other OATT customers. Southern 
argues that such a proposal is predicated upon the false assumption 
that such penalties are not of true financial consequence. Southern 
asserts that penalties paid by an affiliate do, in fact, represent a 
real cost to the wholesale business of that affiliated entity. In its 
reply comments, TDU Systems disagrees with comments that suggest that 
non-offending affiliates should be allowed to receive a load ratio 
share of penalty revenues when a transmission provider or one of its 
affiliates incurs an operational penalty. TDU Systems argue that 
allowing any member of the corporate family to retain any portion of 
the penalty revenues incurred by another member of the corporate family 
will dilute the incentive inherent in the Commission's proposal.
---------------------------------------------------------------------------

    \527\ E.g., EEI, MidAmerican, Nevada Companies, and PNM-TNMP.
---------------------------------------------------------------------------

    854. Seattle suggests that compliance monitoring and enforcement to 
ensure that the transmission provider appropriately assesses penalties 
to its affiliates will be as important as correctly accounting for and 
distributing the revenues from penalties collected from affiliates.
    855. Most commenters were supportive of the Commission's proposal 
to have transmission providers notify the Commission of the amounts of 
all operational penalties they incurred during the year through either 
an annual compliance filing or a one-time filing.\528\ Several 
commenters expressed a preference for a one-time filing by transmission 
providers.\529\ For instance, Ameren states that it prefers the use of 
a one-time filing to propose a mechanism through which the transmission 
provider would identify non-offending, unaffiliated transmission 
customers and a method by which the transmission provider would 
distribute the operational penalties it or its affiliates have incurred 
to the identified transmission customers. Ameren believes this would be 
less burdensome than an annual repeated compliance filing. TDU Systems, 
on the other hand, prefer the Commission's proposal to require an 
annual reporting of penalties levied and penalty revenues credited in 
order to foster greater transparency on this matter. TDU Systems 
believe greater transparency through improved reporting requirements 
would provide greater opportunities for detecting abuses by 
transmission providers or their affiliates, either in imposing 
inappropriate penalties on transmission customers or in failing to 
penalize their own or their affiliates' transgressions. In addition, 
TDU Systems suggest that this reporting requirement should include 
details on the amount of penalties

[[Page 12375]]

levied, whether on customers or the transmission provider or its 
affiliates, for all violations. With regard to the annual reporting 
requirements (for those companies that do not propose a standard 
mechanism to handle the distribution of penalties), Nevada Companies 
suggest that a standard template be proposed so that all companies are 
following the same reporting format.
---------------------------------------------------------------------------

    \528\ E.g., EEI, Suez Energy NA, Sacramento, TAPS, and Wisconsin 
Electric.
    \529\ E.g., Ameren and PNM-TNMP.
---------------------------------------------------------------------------

    856. Several commenters make recommendations that they argue will 
ease the administrative burden of distributing operational penalties 
paid by the transmission provider to non-offending, unaffiliated 
transmission customers. MidAmerican suggests that excluding short-term 
firm and non-firm transactions from the distribution methodology would 
avoid the need to develop a costly and administratively difficult 
program. TVA suggests that the amount of any such operational penalties 
should simply be a credit against the transmission provider's 
transmission revenue requirement, thereby more efficiently reducing the 
cost of transmission service to transmission customers.
    857. Several commenters argue that the transmission provider must 
be made whole before it distributes any penalty revenues. For instance, 
EEI supports the Commission's proposal to the extent penalty revenues 
exceed the cost of transmission service. Nevada Companies assert that 
it is the transmission provider's native load that incurs the cost of 
correcting for the offending customer's intentional deviation from 
schedule or for a transmission customer's self-provided reserves being 
unavailable. Therefore, Nevada Companies contend that any penalties 
should be returned to the native load to offset its cost of generation.
    858. Sacramento and WPS Companies' reply comments support the 
Commission's proposal to prohibit a transmission provider from 
recovering any cost it incurs when it or an affiliate pays an 
operational penalty through jurisdictional rates or services.
Commission Determination
    859. The Commission agrees with those commenters recommending that 
we broaden the NOPR proposal, which required transmission providers to 
distribute to non-offending, unaffiliated transmission customers only 
the unreserved use penalties the transmission provider's merchant 
function incurs. Consistent with our conclusion regarding imbalance 
penalties, we conclude that it would be more appropriate for 
transmission providers to be required to distribute all unreserved use 
penalties they collect, whether from the transmission provider's 
merchant function or other transmission customers. The penalties the 
transmission provider pays for late studies are penalties that, by 
their nature, are fully distributed only to non-affiliated transmission 
customers. Requiring the transmission provider to distribute the 
unreserved use penalty charges that its merchant function incurs will 
ensure that the transmission provider faces a meaningful financial 
consequence when its merchant function incurs an operational penalty. 
Extending the NOPR proposal to all unreserved use penalty revenues the 
transmission provider collects maintains the incentive structure of the 
unreserved use penalty and prevents the transmission provider from 
retaining revenues above those it should reasonably be allowed to 
earn.\530\ This determination is consistent with the Final Rule for 
imbalance penalties and the Commission's decision in Order Nos. 637 and 
637-A.\531\
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    \530\ As we explain further below, the transmission provider 
will be allowed to retain the base firm point-to-point transmission 
service charge when it assesses an unreserved use penalty.
    \531\ Regulation of Short-Term Natural Gas Transportation 
Services, and Regulation of Interstate Natural Gas Transportation 
Services, Order No. 637, 65 FR 10156 (Feb. 25, 2000), FERC Stats. & 
Regs. ] 31,091 at 31,309 (2000) (``* * *to effectively shift 
pipelines to the use of the non-penalty mechanisms described above 
to solve and prevent operational problems, it will be necessary to 
eliminate the pipelines' financial incentive to impose penalties and 
OFOs. Thus, the Commission is requiring pipelines to credit the 
revenues from penalties and OFOs to shippers.''); order on reh'g, 
Order No. 637-A, 65 FR 35706 (Jun. 5, 2000), FERC Stats. & Regs. ] 
31,099 at 31,609 (2000) (``The goal of the Commission's new policy 
on penalties is to encourage pipelines to rely less on penalties and 
more on non-penalty mechanisms to manage their systems* * *.'').
---------------------------------------------------------------------------

    860. We agree with those commenters that suggest that non-offending 
affiliates of the transmission provider, including the transmission 
provider's native load customers, should be eligible to receive a 
portion of the unreserved use penalties that the transmission provider 
collects. Unreserved use penalties are assessed against transmission 
customers and should, therefore, be distributed to all non-offending 
transmission customers, whether affiliated with the transmission 
provider or not. Given the distribution of unreserved penalties 
articulated above, the transmission provider's corporate profit is 
reduced if one of the transmission provider's wholly-owned marketing 
affiliates pays an operational penalty to the transmission provider. 
This is so because the corporate shareholders ultimately pay the 
marketing affiliate's penalty, while the transmission provider 
distributes the revenues to non-offending transmission customers.
    861. The Commission requires the transmission provider to make an 
annual compliance filing and to propose in that filing a mechanism 
through which it will identify non-offending, transmission customers 
and a method by which it will distribute the unreserved use penalties 
revenue it receives to the identified transmission customers. This rule 
is consistent with our determination regarding the distribution of 
imbalance penalties. The transmission provider must also indicate in 
its compliance filing how it will distribute late study penalties to 
unaffiliated transmission customers. In addition, the transmission 
provider is required to make an annual filing with the Commission, 
described further below, that provides information regarding the 
penalty revenue the transmission provider has received and distributed. 
We will not allow the transmission provider to make an annual filing to 
propose a distribution method for unreserved use and late study 
penalties, as proposed in the NOPR. We agree with Ameren that 
restricting the transmission provider to proposing a distribution 
method through the transmission provider's compliance filing will 
reduce the administrative burden of distributing operational penalties. 
We believe that we can accomplish the goals underlying a mandatory 
annual filing to propose a distribution method--to detect inappropriate 
penalties and failure to penalize the transmission provider's 
affiliates--by requiring an annual informational filing. As suggested 
by Seattle, compliance monitoring and enforcement by Commission staff 
will provide a measure of assurance that the transmission provider 
appropriately assesses penalties.
    862. All point-to-point and network transmission customers, 
including the transmission provider's native load, will be eligible to 
receive a portion of the penalty revenues distributed by the 
transmission provider. As a result, we will not adopt MidAmerican's 
proposal that we exclude short-term firm and non-firm transmission 
customers to reduce the burden to the transmission provider. Given the 
steps we have taken to manage the transmission provider's burden of 
distributing penalty revenues, we believe it more equitable to allow 
all transmission customers subject to operational penalties to be 
eligible to receive a portion of the distributed penalty revenues. In 
response to TVA's suggestion that the amount of any such operational 
penalties be credited against

[[Page 12376]]

the transmission provider's transmission revenue requirement, we note 
that the transmission provider is free to propose this mechanism, with 
assurances that offending customers will not benefit, and we will 
decide the appropriateness of the proposal on a case-by-case basis.
    863. We agree with those commenters that assert that the 
transmission provider must be made whole before it distributes any 
penalty revenues. With regard to unreserved use penalties, we will 
allow the transmission provider to retain the base firm point-to-point 
transmission service charge, but require it to distribute any revenue 
collected above the base firm point-to-point transmission service 
charge. For instance, if a transmission customer has unreserved use 
that results in a penalty equal to twice the rate for firm weekly 
point-to-point service, then the transmission provider can retain an 
amount equal to the rate for firm weekly point-to-point transmissions 
service. A transmission provider will be required to distribute the 
entire amount it pays for completing service request studies on an 
untimely basis.
    864. We will not require transmission providers that make an annual 
compliance filing to use a standard template, as suggested by Nevada 
Companies. Transmission providers are in the best position to determine 
the least burdensome way to present the information required. We will 
provide guidance, however, on the information that transmission 
providers must provide in their annual informational filings. 
Transmission providers must provide: (1) A summary of penalty revenue 
credits by transmission customer, (2) total penalty revenues collected 
from affiliates, (3) total penalty revenues collected from non-
affiliates, (4) a description of the costs incurred as a result of the 
offending behavior, and (5) a summary of the portion of the unreserved 
penalty revenue retained by the transmission provider.
    865. Transmission providers are prohibited from recovering for 
ratemaking purposes or through any service under the Commission's 
jurisdiction any amount it or an affiliate pays as an operational 
penalty. This will ensure that the transmission provider faces a true 
financial consequence when it or an affiliate incurs an operational 
penalty.
c. Applicability of Operational Penalties Proposal to RTOs and Other 
Independent or Non-Profit Entities
    866. The Commission did not address the degree to which RTOs and 
other independent entities would be subject to operational penalties in 
section V.C.4 (Operational Penalties) of the NOPR. For the most part, 
the discussion in that section of the final rule addressed how a 
transmission provider should distribute operational penalties it incurs 
when it takes transmission service under its own tariff. In the section 
V.D.5 (Acquisition of Transmission Service) of the NOPR, the Commission 
separately addressed whether RTOs should pay operational penalties for 
failure to complete request studies on a timely basis.
Comments
    867. Several RTOs and RTO members asked that the Commission clarify 
that RTOs are not subject to any operational penalties.\532\ Entergy 
opposes the Commission's proposal to assess operational penalties 
against non-RTO transmission providers, but not RTOs. However, if the 
Commission maintains this distinction, Entergy asks that it clarify 
that independent entities--such as Entergy's Independent Coordinator of 
Transmission--and the transmission providers that allow independent 
entities to process transmission service requests will have the same 
protection from operational penalties as RTOs. PGP argues that, in the 
case of non-profit transmission providers, requiring the transmission 
provider to pay ``non-offending'' customers when the provider incurs 
operational penalties is self-defeating, because there is no one other 
than the customers to bear the cost of the penalty. PGP cites 
Bonneville as an example and notes that Bonneville must recover all 
costs from its customers.
---------------------------------------------------------------------------

    \532\ E.g., ISO New England, PJM, MISO, SPP, and Ameren.
---------------------------------------------------------------------------

Commission Determination
    868. This section of the Final Rule primarily addresses how 
transmission providers should distribute operational penalties they 
incur when taking transmission service under their own tariff. RTOs and 
independent transmission coordinators do not take transmission service, 
so most of the discussion in this section of the Final Rule is simply 
not applicable to either RTOs or independent transmission coordinators. 
RTOs and independent transmission coordinators are bound however by the 
requirement to distribute revenues they receive when they assess 
operational penalties. We address whether RTOs or independent 
transmission coordinators are subject to operational penalties due to 
processing transmission service request studies on an untimely basis in 
section V.C.5.a of this Final Rule. We address whether RTOs are subject 
to civil penalties in section 0 of this Final Rule.
    869. We do not agree with those arguing that a non-profit 
transmission provider should be exempt from the requirement to 
distribute unreserved use penalties it pays when taking service under 
its own tariff. To the extent that a not-for-profit transmission 
provider incurs an operational penalty as a result of its activities as 
a transmission customer, it is still required to distribute penalties 
to non-offending customers. A non-profit transmission provider would 
only incur an operational penalty as the result of its wholesale 
marketing operations. As such, a non-profit transmission provider would 
pay for any operational penalty it incurs by using the profit it has 
earned through its wholesale marketing operations.
6. ``Higher of'' Pricing Policy
    870. As noted in the NOPR, the Commission is concerned that some 
transmission providers may not be applying our existing pricing 
policies consistently and, as a result, customers may be quoted prices 
that are not consistent with the ``higher of'' policy.\533\ The 
practice of quoting customers an incremental rate as a lump sum payment 
is inconsistent with our ratemaking policy and has the potential to 
discourage customers from proceeding with service requests.\534\ Under 
the Commission's ``higher of'' pricing policy, when the requested 
transmission service requires network upgrades, the transmission 
provider should calculate a monthly incremental cost transmission rate 
using the revenue requirement associated with the required upgrades and 
compare this to the monthly embedded cost transmission rate, including 
the expansion costs.\535\ This incremental rate should be established 
by amortizing the cost of the upgrades over the life of the 
contract.\536\
---------------------------------------------------------------------------

    \533\ In Order No. 888, the Commission stated that system 
expansions should be priced at the higher of the embedded cost rate 
(including the expansion costs) or the incremental cost rate, 
consistent with the Transmission Pricing Policy Statement. See 
Inquiry Concerning the Commission's Pricing Policy for Transmission 
Services Provided by Public Utilities Under the Federal Power Act, 
Policy Statement, 59 FR 55031 at 55037 (Nov. 3, 1994), FERC Stats. & 
Regs. ] 31,005 at 31,146 (1994), order on reconsideration, 71 FERC ] 
61,195 (1995) (Transmission Pricing Policy Statement).
    \534\ Southwest Power Pool, Inc., 100 FERC ] 61,096 (2002) 
(designing a rate to include a balloon payment is not a substitute 
for a properly designed rate).
    \535\ Southwest Power Pool, Inc., 112 FERC ] 61,319 at P 33 
(2005).
    \536\ See Southwest Power Pool, Inc., 98 FERC ] 61,256 at 
62,026, reh'g denied in pertinent part, 100 FERC ] 61,096 (2002) 
(``We agree with SPP that the amortization period for upgrade costs 
should match the contract period * * * As the customer is only 
obligated to take service for the term of the contract, it is 
reasonable that the costs only be amortized over the term of the 
contract.'').

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[[Page 12377]]

NOPR Proposal
    871. As a result of the Commission's concerns regarding application 
of the ``higher of'' pricing policy, the Commission sought comments in 
the NOPR on whether changes to the pro forma OATT are necessary to 
ensure that incremental cost transmission rates are presented as 
monthly rates for service.
Comments
    872. Several commenters agree that incremental cost rates must be 
expressed as monthly rates, but do not believe that imposing this 
requirement requires changes to the pro forma OATT.\537\ To ensure 
transparency, Bonneville recommends that transmission providers post on 
their OASIS the methodology used to calculate incremental rates. APPA 
suggests that the Commission simply state in the preamble to the Final 
Rule that the transmission provider must include a proposed incremental 
rate in its offer of service.
---------------------------------------------------------------------------

    \537\ E.g., APPA, Bonneville, and Public Power Council.
---------------------------------------------------------------------------

    873. Other commenters see no need for clarification at this time. 
Southern states that it is not aware of problems regarding the 
calculation of incremental rates. Southern requests that the Commission 
consider allowing deviations to the Commission's ``higher of'' pricing 
policies and to allow all transmission providers, not just RTOs, to 
utilize participant funding. MidAmerican suggests the Commission defer 
consideration of possible changes to the pro forma OATT regarding this 
issue until the Commission undertakes comprehensive transmission 
pricing reform.
    874. Other commenters support changes to the pro forma OATT that 
will ensure that incremental costs are presented as monthly rates for 
service.\538\ EPSA suggests that the Final Rule include an example of 
an appropriate monthly revenue requirement calculation and the upgrade 
costs included in the monthly rate. Suez Energy NA supports this 
proposed change but requests that the transmission provider be required 
to provide in a clear format the existing transmission rate, the lump 
sum cost of the upgrades, and the incremental rate.
---------------------------------------------------------------------------

    \538\  E.g., ELCON, Constellation, FirstEnergy, NorthWestern, 
PGP, TDU Systems.
---------------------------------------------------------------------------

    875. Some commenters ask the Commission to further clarify, or 
establish additional requirements, regarding incremental rates. Entegra 
states that the incremental rate should be stated as both a monthly 
unit rate and a lump sum representing the net present value of the 
upgrade costs with all inputs and assumptions in the calculation 
disclosed. Entegra further contends that the customer should be allowed 
to choose between paying the incremental rate, the lump sum, or some 
combination of the two (e.g., to pay an incremental rate over some 
period of time and then to pay the balance of the upgrade costs as a 
lump sum). While Morgan Stanley supports the Commission's clarification 
that the transmission provider may not demand a lump sum payment as a 
condition of providing the requested service, it asks that transmission 
providers not be precluded from offering a lump sum payment option, or 
any other mutually agreeable approach, to customers.
    876. MidAmerican, EEI and Allegheny recommend that the Commission 
clarify that the transmission provider is not currently limited to 
charging the customer the rate per MW-month specified in the facilities 
study for the entire term of service if the customer pays the 
incremental cost of the network upgrades. These commenters explain that 
the transmission provider's revenue requirement with respect to the 
incremental cost of network upgrades will vary over the customer's term 
of service in the same way as its embedded cost of service will vary, 
including the cost of capital, operations and maintenance expense and 
administrative and general expense. EEI argues that the transmission 
provider should have the same right to modify a rate based on 
incremental costs pursuant to section 205 that it has to modify 
embedded cost rates and that the transmission provider should be 
permitted to present an incremental cost rate as a formula rate.
    877. Seattle states that incremental costs may require more 
rigorous treatment than simply stating a monthly rate, since the cost 
of expansion is very path specific and often the expansion will affect 
multiple beneficiaries. According to Seattle, the ``higher of'' pricing 
policy will often hinge on contestable assumptions regarding the 
beneficiaries of discrete expansion projects and the grey area that 
separates reliability related aspects of new transmission projects from 
projects intended to provide commercial benefits.
    878. Great Northern requests that the Commission clarify that a 
transmission customer may adjust the term of its requested transmission 
service contract to provide a longer period for amortizing the cost of 
necessary system upgrades once the incremental cost of expansion is 
disclosed by the transmission provider, as the Commission seems to 
suggest in the NOPR.\539\ In contrast, Allegheny states that the 
amortization period for the cost of an upgrade should not exceed the 
requested term of the contract, even if exercise of the rollover option 
by the customer is anticipated because transmission providers must have 
assurances of cost recovery for upgrades necessitated by customer 
decisions.
---------------------------------------------------------------------------

    \539\ See NOPR at P 285 (``Presenting the incremental charge in 
the form of a monthly rate allows a customer seeking a lower rate to 
choose to request a longer transaction term.'').
---------------------------------------------------------------------------

    879. TAPS and EEI recommend that the Commission modify sections 
19.3 and 19.4 of the pro forma OATT to specify that the transmission 
provider must present the incremental costs of transmission service on 
a $/MW month basis contemporaneous with providing the facilities study 
to the customer. TAPS further states that similar changes should be 
made to sections 32.3 and 32.4 of the pro forma OATT, to ensure that 
network customers are not scared off by inappropriate presentations of 
network upgrade costs. TAPS explains that, while more complex, it 
believes that ``higher of'' pricing can work in the context of network 
service if applied in a comparable manner to the transmission 
provider's treatment of the upgrades needed for service to its retail 
native load.\540\
---------------------------------------------------------------------------

    \540\ Citing Midwest Indep. Transmission Sys. Operator, Inc., 
109 FERC ] 61,085, P 57 (2004) (applying Order 2003 crediting 
mechanism to network customers).
---------------------------------------------------------------------------

    880. ISO New England and PJM state that the Commission's pricing 
concerns are not present for their respective markets and, therefore, 
any rule promulgated in this proceeding should not apply to these RTOs.
    881. TAPS argues that creditworthiness or security requirements 
associated with network upgrades for a transmission customer (in 
sections 19.4 and 32.4 of the pro forma OATT) must be distinguished 
from the incremental cost or pricing of the upgrade. Otherwise, the 
customer may mistake a demand for security for a request for upfront 
payment of the entire cost of the upgrade.
    882. In reply comments, EEI states that it continues to support the 
Commission's proposed modification to the way in which the transmission

[[Page 12378]]

provider presents information on the incremental cost of network 
upgrades and asserts that nothing in the initial comments justifies a 
change in the Commission's policies with respect to the pricing of 
transmission service. EEI states that changes in transmission pricing 
policy, such as NRECA's proposal to require rolled-in pricing for 
network customers and TAPS's proposal to exempt network customers from 
security for the payment of costs related to network upgrades, are 
outside the scope of this proceeding.
Commission Determination
    883. In the NOPR, the Commission sought comments on the narrow 
issue of whether changes to the pro forma OATT are necessary to ensure 
that, consistent with our ``higher of'' policy, incremental cost 
transmission rates are presented as monthly rates for service. The 
Commission did not propose any changes to the underlying pricing 
policy. Commenters' proposals to change or clarify the Commission's 
transmission pricing policy are therefore outside the scope of this 
proceeding.\541\ Other comments are directed toward the application of 
our ``higher of'' policy in individual cases. These include the 
comments of Seattle (on the need to accurately identify the 
beneficiaries of the network upgrades), TAPS (on the use of ``higher 
of'' pricing in the context of network service), and EPSA (asking the 
Commission to present an example calculation of costs and rates). We 
will not address those comments here because they involve issues that 
are largely fact-specific that are best addressed on a case-by-case 
basis.
---------------------------------------------------------------------------

    \541\ Comments that fall into this category include those of 
Entegra, Suez Energy NA, Morgan Stanley, MidAmerican, EEI (regarding 
the right to modify incremental rates) and Allegheny.
---------------------------------------------------------------------------

    884. Based on the remaining comments received, the Commission 
concludes that changes to the language of the pro forma OATT to address 
this matter are not needed at this time. We believe that the existing 
pricing policy provides sufficient information for transmission 
customers to make an informed decision regarding a request for 
service.\542\ Transmission providers must continue to include a 
proposed monthly incremental rate with their offer of service whenever 
the transmission provider proposes to charge the customer an 
incremental rate, as well as cost support indicating the derivation of 
the rate calculation consistent with the cost support that the 
transmission provider would provide to the Commission in a section 205 
rate filing. Because transmission providers are required to explain the 
calculation of their incremental rate, we conclude that the 
transmission provider need not post on its OASIS the calculation 
methodology, as recommended by Bonneville. Similarly, in response to 
TAPS's concern about security payments, the transmission provider's 
explanation should allow the customer to clearly distinguish between 
any security requirements associated with the service and the 
incremental cost of the service.
---------------------------------------------------------------------------

    \542\ Because the Commission declines to adopt changes to the 
pro forma OATT regarding the ``higher of'' pricing policy, the 
requests of ISO New England and PJM to exempt ISOs and RTOs from 
tariff changes related to that policy are moot. Procedures regarding 
implementation of the Final Rule by ISOs and RTOs are otherwise 
discussed in section IV.C.
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    885. We will not adopt Great Northern's recommendation to require 
the transmission provider to permit the customer to opt for a longer 
contract term (to obtain a longer amortization period and a lower rate) 
once the incremental cost of the upgrades has been determined. The 
specific upgrades required to provide transmission service may depend 
on the time period over which the service is provided; therefore, 
allowing the customer to opt for a longer contract term may trigger a 
need for additional, or different, upgrades.
7. Other Ancillary Services
    886. Other than the pricing of imbalances, the NOPR did not address 
pricing issues related to ancillary services required under the pro 
forma OATT. A few commenters nonetheless proposed revisions to the pro 
forma OATT regarding the pricing and procurement of, and other issues 
related to, ancillary services.
a. Demand Response
Comments
    887. Alcoa submits that load resources (i.e., demand response) 
should be permitted to self-supply and, under certain circumstances, 
sell ancillary services to third parties. Alcoa states that large 
customers such as aluminum smelters are capable of providing, for 
themselves and third parties, some ancillary services so long as they 
are not required to subrogate their aluminum business functions to the 
needs of the ancillary service markets. In Alcoa's view, demand 
resources such as Alcoa's smelter loads should be appropriately 
compensated as providers of ancillary services, recognizing their 
ability to contribute significantly to the operational flexibility of 
energy markets and the stability of the grid. Alcoa asserts that 
industrial loads' contribution to the reliability of the grid was 
demonstrated during the August 2003 Blackout, when Alcoa's smelters 
remained in operation and facilitated the restoration of the system. 
Accordingly, Alcoa asks the Commission to require transmission 
providers to recognize that demand response resources can be a 
substitute for ancillary services such as Energy Imbalance, Operating 
Reserve and Spinning Reserve.
Commission Determination
    888. With respect to Alcoa's concern regarding a transmission 
customer's own use of ancillary service, we note that the existing pro 
forma OATT requires transmission providers to permit transmission 
customers to purchase ancillary services from third parties or make 
alternative comparable arrangements for the provision of all ancillary 
services except for scheduling, system control and dispatch service and 
reactive supply and voltage control service. Regarding the sale of 
other ancillary services including energy imbalance, operating reserve 
and spinning reserve by load resources, we agree that such sales should 
be permitted where appropriate on a comparable basis to service 
provided by generation resources. Comparable treatment of load 
resources is consistent with Staff's August 2006 Assessment of Demand 
Response & Advanced Metering Report \543\ as well as provisions of 
EPAct 2005.\544\ We note that some RTOs and ISOs already allow demand 
response resources to participate in certain ancillary services 
markets, while participation of such resources in other ancillary 
services markets is being studied. We therefore modify Schedules 2, 3, 
4, 5, 6, and 9 of the pro forma OATT to indicate that Reactive Supply 
and Voltage Control, Regulation and Frequency Response, Energy 
Imbalance, Spinning Reserves, Supplemental Reserves and Generator 
Imbalance Services, respectively, may be provided by generating units 
as well

[[Page 12379]]

as other non-generation resources such as demand resources where 
appropriate.
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    \543\ In the Demand Response Report, staff recommended that 
federal and state regulators consider whether to allow appropriately 
designed demand response resources to provide all ancillary services 
including spinning reserve, regulation, and any new frequency 
responsive reserves. Demand Response Report at 97-100.
    \544\ Section 1252 (f) of EPAct 2005 states: ``It is the policy 
of the United States that time-based pricing and other forms of 
demand response, whereby electricity customers are provided with 
electricity price signals and the ability to benefit by responding 
to them, shall be encouraged, the deployment of such technology and 
devices that enable electricity customers to participate in such 
pricing and demand response systems shall be facilitated, and 
unnecessary barriers to demand response participation in energy, 
capacity and ancillary service markets shall be eliminated.''
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b. Procurement and Pricing of Ancillary Services Generally
Comments
    889. Steel Manufacturers Association contends that the pro forma 
OATT's approach to other generation-based ancillary services should 
recognize that regional ancillary services markets do a better job of 
ensuring system reliability and holding down ancillary services costs 
than ancillary services provided on a control area by control area 
basis. Steel Manufacturers Association cites to MISO and SPP reports 
that provide evidence that ancillary services provided across large 
geographical regions are more effective and economical than when those 
services are provided by single utilities. For example, Steel 
Manufacturers Association notes that the SPP report concluded that, if 
a single Area Control Error were used for SPP, energy used for 
regulation service could be reduced by approximately 30 percent. Steel 
Manufacturers Association contends that, although ancillary services 
markets in the organized markets have proven successful at ensuring 
reliability and at keeping ancillary services costs low and 
predictable, utilities outside of the RTO and ISO markets continue to 
provide ancillary services primarily from their own limited pools of 
generation resources.
    890. Occidental and Steel Manufacturers Association propose that 
transmission providers should be required, if feasible, to 
competitively procure ancillary service products if there are suppliers 
of such services other than the vertically integrated merchant 
function. Occidental argues that such procurement will result in just 
and reasonable rates for these generation-related ancillary services 
that reflect their cost-effective market-based competitive supply. In 
Occidental's view, competitive procurement of ancillary services will 
also help assure non-discriminatory treatment of transmission customers 
since transmission providers will have less incentive to favor their 
merchant function in the provision of generation-related ancillary 
services. Occidental notes that such procurement should be conducted in 
a manner consistent with reliability.
    891. Alcoa argues that the transmission provider's costs of 
providing ancillary services for the network as a whole should not be 
socialized on a MWh basis without regard to the relative cost burden 
that specific customers impose on the transmission system. Alcoa 
contends that, while a particular consumer may use a considerable 
quantity of energy, the cost of serving that customer beyond the per-
unit energy cost may be much less than it would be for other individual 
customers or groups of customers.
Commission Determination
    892. The Commission recognizes that there can be possible economic 
and reliability benefits to larger geographic markets for ancillary 
services, as suggested by Steel Manufacturers Association. However, as 
stated in the NOPR and repeated above the purpose of this rulemaking is 
to strengthen the pro forma OATT to ensure that it achieves its 
original purpose--remedying undue discrimination--not to create new 
market structures or, as proposed here, to modify existing market 
structures. We do not believe that altering the scope of the current 
ancillary services markets is needed to remedy undue discrimination at 
this time.
    893. Similarly, we conclude that a fundamental overhaul of the 
current procurement and pricing of ancillary services, as proposed by 
Occidental and Steel Manufacturers Association, is beyond the scope of 
this proceeding.\545\ The pro forma OATT already permits transmission 
customers to make alternative arrangements to satisfy certain of their 
ancillary services obligations. Therefore, transmission customers are 
free to seek out competitive providers for those ancillary services 
other than scheduling, system control and dispatch service and reactive 
supply and voltage control service from third party suppliers. We also 
find Alcoa's contention that the transmission provider's costs of 
providing ancillary services for the network as a whole should not be 
socialized on a MWh basis without regard to the relative cost burden 
that specific customers impose on the transmission system, to be beyond 
the scope of this Final Rule.
---------------------------------------------------------------------------

    \545\ We note, however, that the rates charged for these 
ancillary services must be just and reasonable under the Commissions 
standard of review. Thus, if less expensive options to supply 
ancillary services (including from demand side resources) are 
available, we would expect the transmission provider to examine such 
options.
---------------------------------------------------------------------------

c. Pricing and Procurement of Reactive Power
Comments
    894. Several commenters \546\ suggest that the Commission consider 
the need for reform of the methods of compensation for the provision of 
reactive power.
---------------------------------------------------------------------------

    \546\ E.g., SPP, Alcoa, and Occidental.
---------------------------------------------------------------------------

    895. Alcoa argues that ancillary services pricing should recognize 
the efficiency contributions made by load as a result of their demand 
response capabilities and the contribution that load located near 
generators makes to the provision of reactive power in particular. 
Alcoa states that the localized supply of reactive power near load 
centers can alleviate transmission constraints and allow cheaper real 
power to be delivered into a load center, as the provision of such 
reactive power increases the available flow for real power between two 
points. Alcoa argues that the pro forma OATT should recognize and 
credit the manner in which certain loads' location and load profile 
allows for the provision of reactive power and contributes to real 
power transfer capability.
    896. Occidental objects to the existing requirement that 
transmission customers purchase reactive power service from the 
transmission provider, arguing that numerous independent generators 
provide reactive supply and voltage control to support transmission 
service in competitive wholesale markets. Occidental states that the 
Commission should formalize the policy of compensating generators on a 
comparable, non-discriminatory basis for several ancillary services, 
particularly providing reactive power capability, by requiring changes 
to the pro forma OATT to mirror the changes accepted by the Commission 
to the PJM and MISO tariffs. Occidental contends that amending the pro 
forma OATT to formalize this policy would be consistent with the FPA 
and achieving non-discriminatory access to transmission. Occidental 
notes that PJM and MISO amended their tariffs to provide equal 
compensation to affiliated and non-affiliated generators based on the 
generation owner's monthly revenue requirement for reactive supply and 
voltage control as accepted by the Commission. Occidental also notes 
that, when addressing generator interconnection agreements in Order No. 
2003-A, the Commission stated that ``if the Transmission Provider pays 
its own or its affiliated generators for reactive power within the 
established [power factor] range, it must also pay [the 
interconnecting, independent generator].'' \547\
---------------------------------------------------------------------------

    \547\ See Order No. 2003-A at P 416.
---------------------------------------------------------------------------

    897. SPP requests that the Commission reform its reactive power 
pricing methodology, which has grown

[[Page 12380]]

out of AEP Serv. Corp.\548\ SPP contends that the Commission can reduce 
uncertainty and litigation surrounding the pricing of reactive power by 
acting generically in a rulemaking rather than causing the industry to 
litigate reactive power pricing issues on a case-by-case basis. SPP 
argues that, based on its studies, it does not expect to call upon IPPs 
to provide reactive power; and therefore, it should not be required to 
pay for reactive power. SPP questions whether paying all IPPs a 
reservation charge, regardless of any determination of need or of the 
location of the plant and the locational need for reactive power, 
provides the appropriate siting incentives. SPP contends that the 
Commission can reduce the uncertainty and litigation by acting 
generically rather than causing the industry to fully litigate these 
issues in numerous cases before various courts. In addition, SPP 
challenges whether the AEP pricing method for reactive power continues 
to be appropriate. SPP suggests the Commission consider alternative 
pricing options, such as: Tying compensation to the actual provision of 
reactive power; eliminating compensation for the ninety-five percent 
leading/lagging band contained in most interconnection agreements, as 
such costs may be considered as a cost of interconnection and included 
in the power sales price; or, allowing compensation only outside of the 
band or perhaps when a sale is displaced.
---------------------------------------------------------------------------

    \548\ Opinion No. 440, 88 FERC ] 61,141 (1999).
---------------------------------------------------------------------------

Commission Determination
    898. In Order No. 2003 et al., the Commission found that 
interconnection customers must be treated comparably with the 
transmission provider and its affiliates in terms of reactive power 
compensation. The Commission required the transmission provider to pay 
interconnecting generators for providing reactive power within the 
specified range if the transmission provider so pays its own generators 
or those of its affiliates.\549\ Commenters seeking reform of the 
methods of compensation for the provision of reactive power have not 
demonstrated that such reforms are needed at this time to remedy undue 
discrimination or that the current compensation method does not provide 
a comparable result. Accordingly, we do not believe that acting 
generically on pricing reactive power is needed at this time and we 
will continue to resolve compensation issues for reactive power to 
qualifying generators on a case-by-case basis based on the 
circumstances presented.
---------------------------------------------------------------------------

    \549\ See Order No. 2003-B at P 119.
---------------------------------------------------------------------------

    899. In response to SPP's specific proposals for the treatment of 
reactive power, we note that the Commission recently found that it is 
unduly discriminatory and non-comparable for SPP to apply a ``needs'' 
test to reactive power capability for independent power producers to 
receive compensation that is not also applied to all other generating 
plants in its vicinity.\550\ The Commission also found that parties may 
make a separate FPA section 205 filing with the Commission with 
criteria, applied comparably and prospectively, that would determine 
which generators would receive reactive power compensation.
---------------------------------------------------------------------------

    \550\ See Calpine Oneta Power, L.P., 116 FERC ] 61,282 (2006).
---------------------------------------------------------------------------

    900. Finally, Alcoa's assertion that certain loads' location and 
load profile allows for the provision of reactive power to the 
transmission system is consistent with Staff's February 2005 report, 
Principles for Efficient and Reliable Reactive Power Supply and 
Consumption,\551\ as well as the above-cited provisions of EPAct 2005. 
As previously discussed, we have modified Schedule 2 of the pro forma 
OATT to allow for the provision of Reactive Supply and Voltage Control 
from demand resources where appropriate.
---------------------------------------------------------------------------

    \551\ See Staff Report: Principles of Efficient and Reliable 
Reactive Power Supply and Consumption (Docket No. AD05-1-000), 
available at http://www.ferc.gov/EventCalendar/Files/20050310144430-02-04-05-reactive-power.pdf.
 Staff noted that in many cases load 

response and load-side investment could reduce the need for reactive 
power capability in the system and that increasing reactive power at 
certain locations (usually near a load center) can sometimes 
alleviate transmission constraints and allow cheaper real power to 
be delivered into a load pocket. See id. at 4, 108. The report also 
noted that distributed generators have the same reactive power 
characteristics as large generators, with both producing dynamic 
reactive power, and that the amount of reactive power does not 
necessarily decrease when voltage decreases. Id. at 27.
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D. Non-Rate Terms and Conditions

 1. Modifications to Long-Term Firm Point-to-Point Service
a. Planning Redispatch and Conditional Firm Options
    901. The current pro forma OATT requires the transmission provider 
to provide two types of redispatch service: Planning redispatch and 
reliability redispatch.\552\ Planning redispatch is a product that 
Order No. 888 required transmission providers to use, in certain 
circumstances, to create additional transmission capacity to 
accommodate a request for firm transmission service. Specifically, the 
existing pro forma OATT requires the transmission provider to expand or 
upgrade its transmission system or, if it is more economical, plan to 
redispatch its resources to provide requested firm point-to-point 
service, provided redispatch does not (1) degrade or impair the 
reliability of service to native load customers, network customers and 
other transmission customers taking firm point-to-point service or (2) 
interfere with the transmission provider's ability to meet prior firm 
contractual commitments to others.\553\ The transmission provider must 
first identify planning redispatch options in the system impact study 
in conjunction with identifying relevant system constraints that impact 
the service request.\554\ When a system impact study and facilities 
study identify planning redispatch as a more economical means of 
relieving a transmission constraint than a transmission upgrade, the 
customer is obligated to pay the costs of redispatch consistent with 
Commission policy.
---------------------------------------------------------------------------

    \552\ In Order No. 888, the Commission referred to planning 
redispatch as economic redispatch. Here we avoid the term economic 
redispatch because in the last ten years it has taken a different 
meaning in the industry and because we will no longer require that 
planning redispatch be capped at the cost of expansion.
    \553\ See pro forma OATT section 13.5.
    \554\ See pro forma OATT section 19.3.
---------------------------------------------------------------------------

    902. Reliability redispatch is required, when feasible, to relieve 
system constraints that would otherwise cause curtailment of the 
network customer or transmission provider loads. To provide reliability 
redispatch, the transmission provider redispatches all network 
resources and transmission provider resources on a least-cost basis. 
The transmission provider and network customers each pay a load ratio 
share of these redispatch costs.\555\
---------------------------------------------------------------------------

    \555\ See pro forma OATT sections 33.2-33.3.
---------------------------------------------------------------------------

NOPR Proposal
    903. In the NOPR, the Commission stated its belief that current 
practices for evaluating long-term firm point-to-point service may not 
be comparable to the manner in which transmission service is planned 
for bundled retail native load and may no longer be just, reasonable 
and not unduly discriminatory. The Commission described two potential 
solutions: modifications to the planning redispatch provisions and 
conditional firm point-to-point service.\556\ The Commission proposed 
to modify the existing planning redispatch option by (1) accelerating 
the study of planning

[[Page 12381]]

redispatch in the transmission request study process, (2) requiring an 
estimate of the number of hours of redispatch that may be required to 
accommodate the requested service, (3) requiring a preliminary estimate 
of the cost of planning redispatch, and (4) pricing planning redispatch 
services to facilitate increased availability of the service.\557\ The 
Commission suggested that conditional firm service could also be used 
to accommodate additional transactions, defining the service as a form 
of firm point-to-point service that includes less-than-firm service in 
a defined number of hours of the year when firm point-to-point service 
is unavailable. The Commission sought comment on its preliminary view 
that planning redispatch is the superior option because, in part, it is 
comparable to the way the transmission provider plans for bundled 
retail native load.
---------------------------------------------------------------------------

    \556\ Conditional firm point-to-point service (hereinafter 
conditional firm service) and planning redispatch point-to-point 
service (hereinafter planning redispatch service) are options 
available under long-term firm point-to-point service.
    \557\ The Commission did not propose to modify the reliability 
redispatch provisions that exist in the network integration 
transmission sections of the pro forma OATT.
---------------------------------------------------------------------------

    904. The Commission's October 12 Technical Conference focused, 
among other things, on issues related to the planning redispatch and 
conditional firm proposals in the NOPR. On November 15, 2006, the 
Commission issued a notice (November 15 Notice) requesting supplemental 
comments on a transparent redispatch proposal submitted by Transparent 
Dispatch Advocates (TDA proposal) and certain aspects of the 
conditional firm option.\558\ The Commission also requested comments 
regarding the conditional firm option, including whether it is a 
complementary service to planning redispatch, whether it should be 
available for all long-term requests or limited to a request where the 
customer agrees to pay for upgrades, potential modeling problems, and 
requirements for defining the conditions under which the service would 
be curtailable.\559\
---------------------------------------------------------------------------

    \558\ The following summary reflects comments received as 
initial and reply comments to the NOPR, as well as supplemental 
comments received in response to the November 15 Notice. Some 
commenters have changed their positions over time and these 
summaries reflect the most recent position expressed by commenters.
    \559\ Questions relating to the TDA proposal are discussed later 
in this section.
---------------------------------------------------------------------------

Comments
    905. Some commenters agree with the Commission's preference for 
modifications to planning redispatch over development of conditional 
firm service.\560\ They state that the attributes of conditional firm 
service are not clearly defined and key implementation issues are 
unresolved. They state that using planning redispatch to the maximum 
degree feasible, while not interfering with reliability, is inherent in 
maximizing the efficient use of the transmission system and should be 
fully evaluated before undertaking expensive expansion of the 
transmission system. Other commenters state that conditional firm 
service will create significant complications for transmission 
providers and disincentives to build transmission in exchange for 
limited and questionable benefits for new point-to-point customers or 
LSEs.\561\ EEI, Indianapolis Power and Ameren express doubt that 
customers would agree to be curtailed during peak usage periods. In 
response, AWEA contends that existing resources serving load would be 
able to manage curtailment risks so long as they could reasonably 
predict the curtailed hours.
---------------------------------------------------------------------------

    \560\ E.g., Exelon, FirstEnergy, ELCON, MidAmerican, Arkansas 
Commission, MISO, and East Texas Cooperatives.
    \561\ E.g., EEI, Indianapolis Power, Ameren, and Northwest IOUs.
---------------------------------------------------------------------------

    906. Most independent power producers and a few other entities 
support the inclusion of both services in the pro forma OATT, stating 
that the services are required to remedy undue discrimination and 
provide for comparable transmission service.\562\ Western Governors 
believe that the planning redispatch and conditional firm options are 
important to fully use the existing transmission grid and to enable new 
intermittent generation resources to reach markets. To build the case 
for transmission expansion, the Western Governors argue, it is 
important to demonstrate that the existing grid is being effectively 
utilized; approval of both options will help make this necessary 
demonstration. EPSA and AWEA state that, while they believe 
transmission providers should be required to offer both services, 
conditional firm service may be simpler and less costly to implement 
because it involves the transmission provider directing the customer to 
turn off its resources during a contingency. Similarly, Bonneville 
suggests that conditional firm service is a reasonable alternative to 
planning redispatch where a transmission provider cannot provide both 
options. Commenters state that the Commission should require 
transmission providers to offer conditional firm service and planning 
redispatch and allow customers to choose the option that best suits the 
physical, commercial and economic circumstances of the request.\563\
---------------------------------------------------------------------------

    \562\ E.g., EPSA, AWEA, Entegra, BP Energy, Newmont Mining, 
Sempra Global, Suez Energy NA, PPM, Utah Municipals, Williams, 
Morgan Stanley, PPL, Project for Sustainable FERC Energy Policy, 
California Commission, CREPC, TranServ, South Carolina E&G, 
Constellation, Barrick Supplemental, Xcel Supplemental, and 
Bonneville Supplemental.
    \563\ E.g., California Commission Supplemental, Williams 
Supplemental, Constellation Supplemental, and Barrick Supplemental.
---------------------------------------------------------------------------

    907. On the other hand, many commenters argue that the Commission 
should not require either option because the services are unnecessary, 
operationally unworkable, and legally unjustified, or because they 
would harm reliability and the quality of existing network service and 
provide disincentives for transmission investment.\564\ Several 
commenters state that these services would make curtailments of 
existing firm service more likely and limit opportunities for use of 
secondary network service, thereby harming native load protections and 
reducing reliability, contrary to FPA sections 215 and 217 
respectively.\565\ Others opposing both options put forth primarily 
reliability, cost causation and comparability arguments. For example, 
Duke states that the two options are antithetical to reliable grid 
operation because they would require a transmission provider to grant a 
long-term request with the prior knowledge that it cannot be 
accommodated. International Transmission states that the grid is 
already operating at capacity and that requiring the transmission 
provider to accommodate additional megawatt-hours of service during 
periods of system stress would increase the likelihood of system 
failure. While it recognizes that conditional firm service has been 
successful in parts of the Western Interconnection, NRECA contends a 
mandate would undermine responsible planning and expansion of the 
transmission grid by harnessing the transmission provider's planning 
and dispatch functions to frame more and more elaborate service 
conditions for conditional firm service. APPA, Southern and Progress 
Energy argue that both services may require adoption of a form of 
organized LMP market, an action that raises significant political 
opposition and would be contrary to the Commission's commitment in the 
NOPR to avoid such restructuring. Similarly, other commenters contend 
that the planning redispatch option is only appropriate for 
transmission providers who are members of an RTO, ISO or

[[Page 12382]]

who have an independent administrator of their transmission 
system.\566\ Some of the commenters that urge rejection of both options 
state that a properly structured conditional firm service is preferable 
to the modified planning redispatch service should the Commission 
implement one of the services.\567\
---------------------------------------------------------------------------

    \564\ E.g., Ameren, Duke, Entergy, Imperial, International 
Transmission, LPPC, Progress Energy, Santee Cooper, Salt River, 
Southern, Tacoma, TDU Systems, Community Power Alliance, Northwest 
IOUs, NorthWestern, NPPD, NRECA, Public Power Council, TVA, SPP 
Reply, South Carolina E&G Supplemental, E.ON Supplemental, MISO 
Supplemental, and APPA Supplemental.
    \565\ E.g., Duke, EEI, LPPC, NRECA, NPPD, Progress Energy, 
Southern, Utah Municipals Reply, and Duke Reply.
    \566\ E.g., CREPC, TVA, and East Texas Cooperatives.
    \567\ E.g., EEI, Entergy, Ameren, Progress Energy, Santee 
Cooper, TAPS, E.ON Supplemental, TDU Systems Supplemental, LPPC 
Supplemental, Tacoma Supplemental, and PNM-TNMP Supplemental.
---------------------------------------------------------------------------

    908. Several commenters prefer the development of conditional firm 
service over the modifications to the planning redispatch service 
because of the complexities surrounding redispatch costs and 
protocols.\568\ For example, in supplemental comments, EEI and 
Community Power Alliance state that, while not ideal, conditional firm 
service would provide an opportunity to meet customers' transmission 
needs and is preferable to Transparent Dispatch Advocates' redispatch 
proposal.\569\ They also contend that the conditional firm option would 
provide faster provision of service and relative certainty of timing 
and costs for a new customer and its lenders, while ensuring 
reliability and promoting infrastructure expansion, so long as 
transmission providers are permitted to work with their customers to 
devise appropriate service parameters. Entergy believes conditional 
firm service can provide benefits to transmission customers without 
unfairly socializing costs to native load and network customers of the 
transmission provider. Overall, a majority of commenters express 
support for some form of conditional firm service.\570\
---------------------------------------------------------------------------

    \568\ E.g., Manitoba Hydro, Nevada Companies, Sacramento, 
Pinnacle, East Texas Cooperatives, Barrick Reply, APPA Supplemental, 
Community Power Alliance Supplemental, Entergy Supplemental, and 
TAPS Supplemental.
    \569\ Section V.D.1.b contains a summary and in-depth discussion 
of the TDA proposal.
    \570\ The following entities expressed some level of support for 
conditional firm service: EPSA, AWEA, Entegra, BP Energy, Newmont 
Mining, Sempra Global, Suez Energy NA, PPM, Utah Municipals, 
Williams, Morgan Stanley, PPL, Project for Sustainable FERC Energy 
Policy, California Commission, Western Governors, CREPC, TranServ, 
Constellation, Manitoba Hydro, Nevada Companies, Sacramento, 
Pinnacle, PNM-TNMP, Bonneville, EEI, Entergy, Ameren, Progress 
Energy, Southern, Santee Cooper, Seattle, LPPC, Salt River, and 
TAPS.
---------------------------------------------------------------------------

    909. Several commenters argue that, if the services are required, 
the Commission should add to the services the following requirements: 
The services should not adversely affect reliability and service to 
firm customers or provide unduly preferential service to point-to-point 
customers; the services should be an interim option until transmission 
upgrades are in place to provide firm service; and, planning redispatch 
and conditional firm customers should bear the actual costs of the 
services received, including costs associated with system operational 
changes needed to accommodate the services.\571\
---------------------------------------------------------------------------

    \571\ E.g., EEI, Southern, TAPS, Seattle, APPA, LPPC 
Supplemental, Tacoma Supplemental and E.ON Supplemental. Issues 
related to pricing of planning redispatch service are addressed in 
paragraphs V.D.1.a.3.c below.
---------------------------------------------------------------------------

    910. A few commenters believe that the Commission should allow for 
regional differences in development of the new services.\572\
---------------------------------------------------------------------------

    \572\ E.g., California Commission, PGP, Pinnacle, and Imperial.
---------------------------------------------------------------------------

Commission Determination
    911. The Commission has determined that modifications to the 
current planning redispatch requirement and creation of a conditional 
firm option are both necessary for provision of reliable and non-
discriminatory point-to-point transmission service. The planning 
redispatch and conditional firm options represent different ways of 
addressing similar problems. They can be used to remedy a system 
condition that occurs infrequently and prevents the granting of a long-
term firm point-to-point service. These options also can be used to 
provide service until transmission upgrades are completed to provide 
fully firm service. Planning redispatch involves an ex ante 
determination of whether out-of-merit order generation resources can be 
used to maintain firm service. Conditional firm involves an ex ante 
determination of whether there are limited conditions or hours under 
which firm service can be curtailed to allow firm service to be 
provided in all other conditions or hours. As we explain below, both 
techniques are currently used under certain conditions by transmission 
providers to serve native load and, hence, it is necessary to make 
comparable services available to transmission customers in order to 
avoid undue discrimination.
    912. We therefore find these options are complementary services 
that can remedy undue discrimination, facilitate the provision of long-
term transmission service and provide customers with greater 
flexibility in choosing resources to meet their needs. There is support 
in the comments for development of some type of conditional firm 
service that would allow for a longer-term use of the grid when 
transmission is projected to be unavailable for a small portion of the 
year. Additionally, we note that both options could help integrate new 
generation more quickly. For example, when there is a lag between the 
time that a new generation resource becomes operational and the time 
that transmission upgrades can be built to accommodate the resource, 
these options allow power to reach customer loads at an earlier date. 
This can be particularly beneficial to renewable resources, such as 
wind, that can be constructed more quickly than the transmission 
upgrades necessary to deliver their power on a firm basis over the 
long-run.
    913. We recognize, however, that both options raise reliability 
concerns. The proposal in the NOPR for planning redispatch service 
would require the transmission provider to predict system conditions 
for the term of the service request, a task that becomes more 
difficult, and hence less accurate, with longer-term requests. This 
poses several related problems. Because longer-term forecasts are 
inherently uncertain and the further into the future the forecasts, the 
less accurate they are, the provision of planning redispatch service 
can threaten the reliability of service to native load unless very 
conservative assumptions are used. This incentive to use conservative 
assumptions to protect native load, in turn, increases the likelihood 
that planning redispatch service will be denied. This, in turn, will 
increase the number of disputes as to whether the denials were 
discriminatory. Such disputes would pose enforcement problems because 
they will turn on long-term projections regarding load growth, 
generation resource additions, etc., that by definition involve some 
degree of subjectivity. Moreover, as we discuss below, there is 
evidence suggesting that, while transmission providers use planning 
redispatch to serve native load, they do not use it as a long-term tool 
to avoid future upgrades indefinitely.
    914. In balancing the foregoing considerations, the Commission will 
modify the approach proposed in the NOPR in two principal respects. 
First, given the ability of both services to address similar problems, 
we have reconsidered the proposal that only one of the options should 
be required. We find that availability of both planning redispatch and 
conditional firm in the short-run is necessary to ensure that 
competitive power suppliers have comparable access to the grid. As 
discussed below, we will continue to require that transmission 
providers offer to provide planning redispatch under certain 
circumstances in which the transmission providers determine that there 
is insufficient ATC. If customers

[[Page 12383]]

request study of planning redispatch, transmission providers have an 
obligation to seriously evaluate the provision of planning redispatch 
from their own resources and provide customers with information on the 
capabilities of other generators to provide planning redispatch. If 
planning redispatch is unavailable from the transmission provider's 
resources or inadequate to meet customers' needs, transmission 
providers have an independent obligation to offer conditional firm, if 
available, as part of the firm point-to-point service.\573\ Customers 
will have the choice of whether to request study of the planning 
redispatch option, the conditional firm option or both.
---------------------------------------------------------------------------

    \573\ Application of planning redispatch and conditional firm 
service obligations to RTO and ISO transmission providers is 
discussed in section V.D.1.a.3.B.i below.
---------------------------------------------------------------------------

    915. Second, we will not impose a planning redispatch or 
conditional firm obligation over the long run. Such an obligation is 
not, as described below, necessary to remedy undue discrimination and 
would otherwise pose reliability problems, put the transmission 
provider at risk for estimating the costs of long-term redispatch, and 
undermine incentives to upgrade the transmission grid. Therefore, we 
will limit the availability of both service options so that their 
duration is for a time period over which service can be reasonably 
provided without impairing reliability.\574\ This limitation scales 
back the existing planning redispatch requirement in section 13.5 of 
the pro forma OATT that could, in practice, allow for an open-ended 
obligation to provide planning redispatch in lieu of upgrading the 
transmission system (e.g., involving forecasts up to 30 years).
---------------------------------------------------------------------------

    \574\ As explained in more detail below, we adopt limitations 
that are tailored to the two types of customers that may request the 
options. First, for customers that agree to support the construction 
of new transmission facilities, redispatch and conditional firm 
point-to-point service will be available as a bridge until such time 
as those facilities are constructed and the relevant conditions must 
be specified in the initial service agreement and are not subject to 
change. Second, for customers that do not agree to support the 
construction of new facilities, the transmission provider will be 
able to re-evaluate the conditions under which services are provided 
every two years.
---------------------------------------------------------------------------

    916. We discuss in detail the comparability and reliability 
findings that support these decisions below.
(1) Comparability
NOPR Proposal
    917. In the NOPR, the Commission expressed its preliminary view 
that current practices for evaluating long-term firm point-to-point 
service may not be comparable to the manner in which transmission 
service is planned for bundled retail native load and may no longer be 
just, reasonable and not unduly discriminatory.\575\
---------------------------------------------------------------------------

    \575\ The Commission did not propose to modify the reliability 
redispatch provisions that exist in the network integration 
transmission sections of the pro forma OATT.
---------------------------------------------------------------------------

Comments
    918. Some commenters challenge the Commission's authority to order 
planning redispatch or conditional firm service as a remedy for 
potential undue discrimination. EEI and others argue that planning 
redispatch is not necessary to eliminate actual or perceived undue 
discrimination because many transmission providers do not rely on 
redispatch in planning to serve native load.\576\ However, EEI also 
states that when transmission providers do incorporate redispatch into 
their system planning, they do so generally only when the cost of 
redispatch is lower than the cost of network upgrades and system 
reliability is not impacted. Some transmission providers state that 
they do not currently use planning redispatch in lieu of transmission 
construction in order to designate their network resources.\577\ On the 
other hand, Entergy and Southern state that they currently use or have 
used planning redispatch of their own resources on the same basis that 
they allow any network customer to redispatch from the network 
customer's resources. For example, Southern states that it has used the 
redispatch potential of its generators during off-peak/shoulder periods 
on an interim basis until completion of transmission upgrades to 
designate network resources that otherwise might be undeliverable.\578\ 
Entergy disagrees that there is undue discrimination because this 
service is not available to point-to-point customers, stating that 
network and point-to-point service are not similarly situated services. 
TDU Systems state that conditional firm service does not ensure 
comparability among types of transmission service or between 
transmission providers and transmission customers. NRECA and others 
argue that the Commission requires a better understanding of the degree 
to which comparability is a problem in providing point-to-point service 
before the Commission makes changes to point-to-point service.\579\ In 
supplemental comments, EEI contends that the record in this proceeding 
does not demonstrate that conditional firm service is necessary to 
remedy undue discrimination.
---------------------------------------------------------------------------

    \576\ E.g., EEI, TDU Systems, NRECA, Southern, and Duke Reply.
    \577\ E.g., Southern, Duke, and Progress. Duke suggests that the 
Commission exempt transmission providers from the obligation to 
provide redispatch if they commit not to use redispatch as a 
planning tool for native load, network customers or merchant 
functions.
    \578\ Southern states that it offered this service on a 
comparable basis to a non-affiliated transmission customer.
    \579\ E.g., TDU Systems and EEI Reply.
---------------------------------------------------------------------------

    919. Others assert that it is not within the Commission's 
jurisdiction to order planning redispatch for point-to-point customers 
because this type of redispatch requires use of the transmission 
provider's generation resources.\580\ LPPC states that the 
comparability principle is wrongly applied to the use of generation by 
a transmission provider. In Salt River's view, the Commission proposal 
sets up its own form of discrimination by making redispatch of the 
transmission provider's resources mandatory while making redispatch of 
generation using firm point-to-point reservations and generation in 
other control areas voluntary.
---------------------------------------------------------------------------

    \580\ E.g., LPPC, NPPD, Progress Energy, and Salt River.
---------------------------------------------------------------------------

    920. Those that support development of both services support the 
Commission's statement in the NOPR that ``transmission owners may 
evaluate transmission availability to serve long-term transmission 
service requests in a manner that is not comparable with the method 
they use to evaluate transmission needs for bundled retail native 
load.'' \581\ They argue that this divergent treatment of internal 
transmission needs versus external transmission requests is unduly 
discriminatory and violates the FPA. EPSA states that the fact that 
point-to-point service requests can be rejected due to a few hours of 
predicted reliability problems in a year is ``evidence of a poor use of 
existing transmission capacity and display clear discrimination against 
non-affiliated generation and its customers.'' \582\ TransAlta states 
that its actual experience with planning redispatch in the Pacific 
Northwest demonstrates that planning redispatch is used 
discriminatorily to the benefit of some customers and the detriment of 
others.
---------------------------------------------------------------------------

    \581\ E.g., AWEA, Utah Municipals, Project for Sustainable FERC 
Energy Policy, EPSA, and Barrick Reply citing NOPR at P 300.
    \582\ EPSA Reply.
---------------------------------------------------------------------------

    921. In support of conditional firm service, Manitoba Hydro and 
Tacoma reiterate their experience that long-term transmission service 
requests are being denied due to constraints occurring during a small 
percentage of the time within the requested period of service.

[[Page 12384]]

EPSA and AWEA similarly state that a transmission provider will reject 
a long-term firm service request unless it can satisfy every element of 
the request. Manitoba Hydro and others state that, in an era of 
transmission under-investment, optimizing the capacity usage is 
paramount to system reliability.\583\ EPSA and AWEA further explain 
that the concept of turning off a generator to avoid system upgrades is 
not new; Maine Independence Station avoided expensive system upgrades 
by installing automatic switching devices to take it offline during 
certain system conditions. Seattle states that, according to the Seams 
Steering Committee of the Western Interconnection, utilization on most 
constrained paths is limited to only a few hundred hours per year and, 
therefore, it is highly likely that service under a conditional firm 
product could be offered for even a baseload plant without 
significantly impacting the capacity factor. Santee Cooper states that, 
unlike the planning redispatch option, conditional firm service is 
presumptively within the subject matter jurisdiction of the Commission.
---------------------------------------------------------------------------

    \583\ E.g., EPSA, AWEA, and Project for Sustainable FERC Energy 
Policy.
---------------------------------------------------------------------------

    922. Entergy states that the most comparable service for long-term 
point-to-point transmission customers is not a requirement that a 
transmission provider redispatch its own or network customers' 
resources to grant long-term firm point-to-point transmission service. 
The most comparable service instead is a service that allows the 
transmission provider to curtail the service granted, while permitting 
the point-to-point customer to obtain alternative, deliverable 
resources if and when such curtailments occur in real-time.
Commission Determination
    923. We reject arguments that planning redispatch service is 
unnecessary to remedy undue discrimination as a collateral attack on 
Order No. 888. The obligation to provide planning redispatch was 
established in Order No. 888. The modifications proposed in the NOPR 
did not increase the obligation placed on transmission providers to use 
their generation resources to provide planning redispatch to point-to-
point customers. Rather, the proposed modifications merely added 
specificity to the redispatch information already required in a system 
impact study and adjusted the timing of when the transmission provider 
must study planning redispatch options.\584\ Therefore, many of the 
arguments raised, including arguments pertaining to the Commission's 
jurisdiction over transmission provider generation resources, are 
impermissible collateral attacks on the current planning redispatch 
obligation in Order No. 888. Entergy's argument that planning 
redispatch should not be available to point-to-point customers because 
they are not similarly situated to be able to provide redispatch from 
their own units thus ignores the current obligation for each 
transmission provider to provide redispatch from the transmission 
provider's resources, if available, in evaluating a request for long-
term point-to-point service.\585\
---------------------------------------------------------------------------

    \584\ See pro forma OATT section 19.3.
    \585\ See pro forma OATT section 13.5.
---------------------------------------------------------------------------

    924. Additionally, information in the comments counters the 
assertion that transmission providers do not use planning redispatch or 
service analogous to the conditional firm option for their own loads. 
Entergy and Southern volunteer that they have planned for redispatch of 
their own resources in order to designate network resources when ATC 
was unavailable.\586\ As a caveat, Southern states that it has planned 
for the use of redispatch only for an interim period until upgrades 
could be constructed to make the transmission service from the 
designated resource fully firm. Entergy states that it offers planning 
redispatch service to network customers that plan to use their own 
resources to provide redispatch in real time. Contrary to EEI's 
assertion about the record in this proceeding, commenters, such as EPSA 
and AWEA, explain that some transmission providers already employ 
automatic devices, such as special protection systems (SPS), to take 
resources offline during certain system conditions. In a way that is 
analogous to the proposed conditional firm service, these protection 
schemes are used to increase native loads' firm uses of the 
transmission system until a contingency occurs that reduces available 
transmission.\587\ This information, taken together, provides ample 
evidence to support our finding that transmission providers currently 
evaluate transmission availability to serve long-term firm point-to-
point transmission service requests in a manner that is not comparable 
with the method they use to evaluate their own transmission needs and 
to integrate their resources to serve bundled retail native load.
---------------------------------------------------------------------------

    \586\ Entergy and Southern. EEI's comments also indicate that at 
least a few transmission providers do rely on redispatch in planning 
to serve their native loads.
    \587\ SPS, also known as remedial action schemes, are used to 
varying degrees in every NERC reliability region. For example, there 
are about 65 SPS in the Western Interconnection. See Western 
Electricity Coordinating Council Operating Procedures, Index, V-1 to 
V-5 (revised July 2, 2002). There are 8 SPS used by Florida Power 
and Light in FRCC. See Florida Power and Light Control Area 
Readiness Audit Report, 19 (March 10-11, 2004). Two SPS are used in 
the Southern Subregion of SERC. Reliability Coordinator Readiness 
Audit Report Southern Subregion Reliability Coordinator, 19 (March 
27-30, 2006).
---------------------------------------------------------------------------

    925. Furthermore, we wish to emphasize that, in making these 
findings in support of a conditional firm option, we are not relying on 
the findings to create a new service. This Final Rule retains the two 
services adopted in Order No. 888--point-to-point service and network 
service. Conditional firm service is not a third service, but rather 
represents a modification to the existing procedures for granting long-
term point-to-point service and the curtailment priorities for that 
service. The primary purpose of conditional firm is to address the 
``all or nothing'' problem associated with the current procedures for 
requesting long-term point-to-point service. Currently, a request can 
be denied because firm service is unavailable in a very few hours of 
the year. For a customer who needs long-term point-to-point service to 
support a long-term transaction, this leaves the customer in the 
position of trying to cobble together a collection of shorter-term 
requests to effectuate its transaction, e.g., arranging firm service in 
the periods when it is available and non-firm service in the other 
periods. Such a customer also risks interruption of the non-firm 
portion of its service for economic reasons, e.g., a day of non-firm 
service for the customer combining firm and non-firm service could be 
interrupted for another customer seeking one month of non-firm service. 
We do not believe such an approach is just and reasonable. It makes 
little sense to ask the customer to cobble together a collection of 
firm and non-firm requests when the transmission provider has better 
information about when the service may be available or unavailable. It 
is therefore appropriate to require the transmission provider to grant 
the service on a conditional basis, as we explain further below.
    926. We are however modifying the planning redispatch obligation, 
and similarly limiting the conditional firm option, to better reflect 
the manner in which redispatch or special protections schemes are used 
by transmission providers, in recognition of certain legitimate 
reliability concerns and the inherent difficulty of long-term 
projections in this area. This Final Rule limits transmission 
providers' planning redispatch obligations by removing the current 
obligation to provide planning redispatch for an indefinite period as

[[Page 12385]]

long as the redispatch is cheaper than the relevant transmission 
upgrades. We also limit the conditional firm option by linking it to 
the transmission upgrades or a biennial assessment of the conditions.
    927. We find such an open-ended obligation to provide this service 
is not necessary to remedy undue discrimination, nor is it consistent 
with the need to maintain system reliability. As indicated above, 
transmission providers temporally limit their use of planning 
redispatch and curtailment of resources and there is no evidence that 
transmission providers use these options on a prolonged basis, e.g., 
for more than a few years, without upgrading their transmission 
systems. Rather, over the long run, transmission providers generally 
will construct sufficient transmission to integrate their resources on 
a firm basis. This is consistent with transmission planning 
requirements and the emphasis placed upon transmission expansion in 
this Final Rule. The modifications to long-term point-to-point service 
we adopt are consistent and comparable to the existing use of these 
options by transmission providers' bundled retail native loads. Thus, 
the planning redispatch and conditional firm options will be available 
primarily as interim measures until transmission systems are upgraded 
to meet the transmission service request. We believe this limitation 
will have the added benefit of lessening disincentives to provide the 
service so that more planning redispatch is offered to transmission 
customers by transmission providers.
    928. We disagree with TDU Systems' statement that conditional firm 
service does not ensure comparability among types of transmission 
service or between transmission providers and transmission customers. 
TDU Systems' assertion is unsupported by any explanation or examples of 
how the conditional firm service would degrade comparability. 
Nevertheless, we believe the argument is essentially a collateral 
attack on Order No. 888. Order No. 888, not this rulemaking, created 
the distinction between point-to-point transmission service and network 
integration service. We did so to recognize the different ways in which 
transmission providers typically use their system. The two services are 
not precisely the same, nor were they intend to be identical. Nothing 
in this Final Rule changes these distinctions. Indeed, we are not 
changing the relative priorities applicable to firm point-to-point 
service, network integration service and service to bundled native 
load.\588\ These services do, and will continue to, share the same 
priority--the highest priority of firm service on the transmission 
provider's system. The only change, as it relates to the conditional 
firm option, is to allow the customer to elect to have its long-term 
firm transmission service interrupted under certain defined 
circumstances. This does not harm other firm customers. Indeed, it has 
precisely the opposite effect: it permits an interruption to maintain 
firm service to other customers. Moreover, we find, as indicated above, 
that conditional firm service is necessary to remedy undue 
discrimination.
---------------------------------------------------------------------------

    \588\ See supra section V.D.5.b.
---------------------------------------------------------------------------

    929. The addition of conditional firm service therefore does not 
significantly alter the existing balance between the point-to-point and 
network service. Customers of network service retain flexibility that 
is not enjoyed by point-to-point customers. Moreover, conditional firm 
does not reduce the availability of secondary network service or the 
ability of network customers to temporarily undesignate network 
resources any more than short-term firm point-to-point service already 
reduces the availability of these network customer options. We 
therefore reject TDU Systems' arguments and find that the addition of 
conditional firm service is necessary to remedy undue discrimination 
and will otherwise increase utilization of the grid without impairing 
system reliability.
(2) Reliability
(A) Ability to Predict Redispatch Opportunities and System Conditions 
in the Long Run
Comments
    930. Some commenters state that redispatch, used as a planning tool 
rather than as a short-term operational tool, is overly complex, prone 
to causing disputes, reduces reliability and thus should not be 
included in the pro forma OATT.\589\ Southern asserts that planning 
redispatch should not be required where it reduces reliability by 
reducing a utility's reserve margin, shifting the operational, 
reliability and economic risks from the new customer to native load, or 
causing a single contingency to overload the system. Additionally, Xcel 
states that pledging a network resource to support planning redispatch 
carries a risk of penalties for inadequate resources in some areas. 
MISO states that contingency conditions must be considered and 
respected when evaluating planning redispatch options so that there is 
no reliance on curtailment of service. MidAmerican and Progress Energy 
conclude that the customer must accept the risk of selecting planning 
redispatch service over transmission construction.
---------------------------------------------------------------------------

    \589\ E.g., Duke, Entergy, WAPA, NRECA, NPPD, LPPC, and 
Southern.
---------------------------------------------------------------------------

    931. Several commenters request modification of the existing 
planning redispatch provisions of the pro forma OATT.\590\ They state 
that the Commission should clarify that the current section 13.5 does 
not require planning redispatch when it would adversely affect system 
reliability or service to native load, network customers and other firm 
point-to-point customers or impair other contractual obligations. 
Indianapolis Power states that the Commission should modify section 
13.5 to require all reasonable redispatch options be examined by the 
transmission provider.
---------------------------------------------------------------------------

    \590\ E.g., EEI, Indianapolis Power, Public Power Council, 
Southern, Seattle, Sacramento, and LPPC.
---------------------------------------------------------------------------

    932. In its reply comments, Southern explains that transmission 
providers fail to provide the currently required planning redispatch 
service to point-to-point customers because the service is impractical 
and would harm reliability. Southern contends that a redispatch 
scenario identified in a transmission plan may not be available in real 
time due to outages or loop flow. Southern is also concerned about the 
complications in planning and modeling that would occur if the 
transmission provider is required to redispatch multiple resources in 
order to accommodate multiple planning redispatch customers.
    933. Similar to their arguments in favor of conditional firm, EPSA 
and AWEA state that planning redispatch is necessary because a 
transmission provider will reject a long-term firm service request 
unless it can satisfy every element of the request, even if reliability 
violations occur in only a few hours of the year. In its reply 
comments, EEI responds that there is no evidence to support the 
assertion that a transmission provider will reject a long-term firm 
service request unless it can meet every element of that request. EEI 
states that in such a situation the transmission provider must offer 
partial service, offer to perform a system impact study, and exercise 
due diligence in constructing needed upgrades to accommodate the 
request. EEI adds that the potential customer can also request short-
term service. Finally, EEI states that there is no evidence that 
transmission providers are refusing to redispatch in response to 
customer request when redispatching resources would have no impact on 
reliability. In

[[Page 12386]]

its reply comments, MISO states that denial of service complained of by 
EPSA and AWEA is a consequence of the customer's economic decision not 
to build upgrades.
    934. Many transmission providers assert that the costs and 
inequities of achieving the proposed planning redispatch outweigh any 
new benefits for point-to-point customers.\591\ They state that the 
Commission's proposal is based on an erroneous assumption that 
redispatch is nearly always feasible; instead when redispatch is most 
desirable, generators operating at peak would not be available for 
redispatch.\592\ Southern also explains that problems of insufficient 
transmission capacity cannot be avoided by redispatching generation 
because there is no guarantee that a redispatch solution will be 
available during real-time operations. Imperial argues that the 
personnel and modeling costs to transmission providers of calculating 
planning redispatch costs prior to a facilities study are too 
excessive. Xcel concludes from a NERC experiment on market redispatch 
that redispatch involving non-market-based or bilateral coordination 
with third parties to protect a delivery path is cumbersome, 
inefficient, and does not promote reliability.
---------------------------------------------------------------------------

    \591\ E.g., Duke, Entergy, Imperial, International Transmission, 
Salt River, Seattle, Southern, Tacoma, Northwest IOUs, Sacramento, 
Progress Energy, E.ON, Xcel, TVA, and EEI Reply.
    \592\ E.g., Sacramento and TVA.
---------------------------------------------------------------------------

    935. Xcel states that its estimate of hours of planning redispatch 
is unlikely to be accurate given that it uses a static power flow that 
is created for a specific peak hour and a specific off-peak hour in a 
given year. Commenters state that planning redispatch service should 
not be a guaranteed service because generation or transmission 
availability, system loads, loop flows from adjoining systems, weather, 
and fuel availability all entail a component of risk that should not be 
pushed back on the transmission provider or its native load.\593\
---------------------------------------------------------------------------

    \593\ E.g., Progress Energy, E.ON, WAPA, Entergy, and 
MidAmerican.
---------------------------------------------------------------------------

    936. Operators of systems that rely primarily on hydroelectric 
resources argue that planning redispatch should not be considered a 
viable option for their systems and they should be exempt from OATT 
planning redispatch obligations because hydroelectric operators are 
unable to make long-term commitments that a resource will be available 
to relieve transmission constraints.\594\ Bonneville states that the 
variability in water flows and the interdependence of the generating 
units contribute to the inability to predict future redispatch ability. 
Bonneville, WAPA and Bureau of Reclamation state that planning 
redispatch can conflict with federal obligations to operate federal 
dams and reservoirs in a manner that does not impact project purposes 
and provide preference in the sale of hydropower to its preference 
customers. Tacoma states that planning redispatch must be linked to 
market price indexes to work in a hydro-based system. Seattle states 
that in hydro-dominant systems fuel availability and fuel price risk 
undermine the feasibility of providing long-run redispatch cost 
estimates that reasonably reflect future costs. Seattle adds on reply 
that planning redispatch fails to address costs pertaining to fish 
species preservation, recreation and flood control impacts, increased 
risk of spill, or replacement power that are associated with 
hydroelectricity.
---------------------------------------------------------------------------

    \594\ E.g., Bonneville, Seattle, Public Power Council, and WAPA.
---------------------------------------------------------------------------

    937. Morgan Stanley argues on reply that the Commission should not 
exempt hydroelectric system operators from providing planning 
redispatch; instead, factors unique to hydroelectric systems should be 
taken into account in determining how much planning redispatch a 
transmission provider can provide. In supplemental comments, PPM agrees 
with Morgan Stanley and adds that hydro-based systems, such as 
Bonneville's, are flexible enough for a transmission provider to use 
planning redispatch to create additional firm capacity.
    938. In their reply comments, Utah Municipals and EPSA state that 
planning redispatch would not impair reliability because the OATT 
provisions do not require transmission providers to permit intentional 
overloading of lines. Since transmission providers are already required 
to provide planning redispatch now, Utah Municipals contend that any 
change in the sequence for studying the option cannot have an impact on 
reliability. EPSA argues that claims of adverse reliability impacts 
should be dismissed because transmission providers do not make these 
same claims when they redispatch to enable transmission service to meet 
their own load obligations. Utah Municipals state that reliability 
would be most enhanced by completely restricting access to the grid, a 
policy that Utah Municipals do not recommend because it would be 
extraordinarily costly and promote discrimination. In its reply 
comments, Entegra states that customers seeking planning redispatch are 
not seeking to shift a disproportionate share of the risks or costs to 
native load or other users of the system.
    939. In its reply comments, EPSA further argues that the Commission 
should place the burden of showing unreliability in a particular 
instance on the transmission provider. EPSA also argues that 
transmission providers should not be allowed to delay service through 
feasibility studies. EPSA contends that planning redispatch will not 
delay needed system upgrades and, instead, will ensure optimized use of 
the existing system that will provide additional information about the 
system's capabilities to regional planning initiatives. In its reply 
comments, Morgan Stanley states that the Commission should establish 
clear standards as to the degree of expected reliability that appends 
to a firm transmission sale and allow transmission providers to sell as 
much of the system as can be sold on a firm basis, consistent with 
maintaining the reasonable standard.
    940. EEI and some transmission providers add that the conditional 
firm product could result in an oversubscription of a transmission 
system in violation of NERC reliability standards that require the 
transmission system to be planned to meet all firm needs.\595\ ELCON 
states that conditional firm service may not truly support long-term 
contracts for firm power but may lead to a greater volume of short-term 
trading.
---------------------------------------------------------------------------

    \595\ E.g., Ameren, Southern, and EEI.
---------------------------------------------------------------------------

Commission Determination
    941. Many commenters are concerned that the options described in 
the NOPR will impair system reliability. We have taken these comments 
into account and have tailored the modifications to long-term point-to-
point service so as to not impair system reliability. There are two 
important limitations that provide such protections. First, we make 
clear that transmission providers are not required to offer planning 
redispatch or conditional firm service if doing so would impair system 
reliability.\596\ Second, as explained above and discussed in further 
detail below, we are limiting the time period under which either option 
is offered. We do so because forecasts of potential redispatch or 
interruption options become more

[[Page 12387]]

speculative over time and to require a transmission provider to commit 
for a substantial period of time, subject to the uncertainty inherent 
in such long-term projecting, has the potential to degrade reliability. 
With these two limiting conditions, we find that neither the planning 
redispatch nor conditional firm option will degrade reliability and, as 
discussed above, that both are necessary to remedy undue 
discrimination.
---------------------------------------------------------------------------

    \596\ A transmission provider may not be able to provide 
conditional firm service without impairing the reliability of its 
system if it is required, for example, to manage many conditional 
firm point-to-point reservations across the same path. The ability 
of system operators to track, tag and manage curtailment of multiple 
conditional firm reservations is necessarily limited by time, human 
resources and other reliability-related duties of the operators.
---------------------------------------------------------------------------

    942. We agree with a majority of commenters that over the long 
term, new resources should be supported by sufficient transmission 
capacity to deliver their output reliably. Imposing a planning 
redispatch or conditional firm obligation over the long-run would not 
be consistent with the need to increase the reliability of the grid or 
otherwise necessary to remedy undue discrimination. Rather, it would 
tend to degrade reliability over time, contrary to the public interest 
and the underlying goals of EPAct 2005. Projections of planning 
redispatch options and conditional firm conditions are more accurate in 
the near term and, hence, should facilitate the efficient use of 
existing resources without impairing reliability.
    943. We therefore impose limits on the transmission provider's 
current planning redispatch obligations. We do so by removing the 
obligation to provide planning redispatch for an indefinite period as 
long as the redispatch is less expensive than the relevant transmission 
upgrades. Section 13.5 of the pro forma OATT could, in conjunction with 
rollover rights, allow for an extremely long-term obligation to provide 
planning redispatch in lieu of upgrading the transmission system. We 
find that this existing obligation may unreasonably harm reliability 
and provides incorrect incentives to delay necessary grid expansion. We 
emphasize that the obligation to provide planning redispatch applies 
only when the service can be provided reliably.
    944. We also limit the time period over which a transmission 
provider must predict the system conditions or conditional hours that 
would apply to customers using the conditional firm option. We do so in 
recognition of the difficulty in attempting to forecast curtailment 
options over the long-term and the fact that there is no evidence that 
transmission providers perform similar forecasts for their native load 
customers. We do not, however, eliminate entirely the risk of 
predicting future system conditions or shift it in whole to the 
requesting transmission customer as requested by certain commenters. We 
believe that the transmission provider should retain responsibility for 
incorporating reasonable assumptions into its transmission models so 
that it can manage this risk, just as it currently manages the 
prediction risk in its ATC models.
    945. We will now turn to certain clarifications and other issues 
raised by the commenters. We acknowledge that planning redispatch to 
support annual service may require redispatch of generation during the 
peak month or months. Since transmission providers plan their 
generation to meet their peak native load plus reserves, the 
transmission provider's resources may, in some cases, be fully employed 
to meet the needs of bundled retail native load and thus may not be 
available to provide redispatch during the peak period.\597\ In such an 
instance, the unavailability of such resources to provide redispatch 
service will constitute a legitimate basis for denying planning 
redispatch service. However, we will not excuse the existing obligation 
that requires transmission providers to study any available planning 
redispatch, including redispatch that might provide some but not all of 
the service requested. Given that some transmission providers have 
acknowledged their own use of planning redispatch for their network 
resources,\598\ the service must continue to be available to those 
seeking point-to-point service to ensure comparability.
---------------------------------------------------------------------------

    \597\ See, e.g., Arizona Public Service Co. v. Idaho Power Co., 
95 FERC ] 61,081 at 61,241 (2001) (resources projected to be 
unavailable during system peak month to provide planning 
redispatch).
    \598\ E.g., Entergy.
---------------------------------------------------------------------------

    946. We reiterate that the transmission provider remains obligated 
to provide planning redispatch from its resources as long as the 
planning redispatch does not (1) degrade or impair the reliability of 
service to native load customers, network customers and other 
transmission customers taking firm point-to-point service or (2) 
interfere with the transmission provider's ability to meet prior firm 
contractual commitments to others.\599\ We continue to believe these 
are the appropriate exceptions and will not adopt a broad and undefined 
reasonableness standard as suggested by Indianapolis Power. We agree 
with Southern that the transmission provider may consider the impact of 
the planning redispatch service in reducing its reserve margin below 
that necessary to maintain reliability or causing a single contingency 
to overload the system in determining whether the service can be 
reliably provided.
---------------------------------------------------------------------------

    \599\ See also Order No. 888 at 31,739.
---------------------------------------------------------------------------

    947. Further we will not excuse transmission providers from the 
obligation to manage multiple planning redispatch or conditional 
curtailment obligations simply because some commenters express concerns 
about planning and modeling impacts. While we do not take these 
concerns lightly, we believe they can be managed by transmission 
providers. The planning redispatch obligation has existed for ten 
years, and with it the potential for multiple planning redispatch 
requests. We have no evidence that transmission providers have been 
unable to manage the process. Moreover, by scaling back the time period 
for which transmission providers must plan for provision of redispatch, 
we have greatly reduced any planning and modeling impacts. We believe 
that whatever additional work the options cause with regard to planning 
and modeling, it is small and more than offset by the considerable 
value of the options which allow for more efficient use of the 
transmission system, expansion of long-term uses of the grid and 
remedying of undue discrimination.
    948. Finally, we recognize the difficulty of predicting, over 
prolonged periods, whether hydroelectric resources will be available to 
provide redispatch. We agree with Morgan Stanley that factors unique to 
hydroelectric systems should be taken into account in determining how 
much planning redispatch a transmission provider can provide. For 
example, transmission providers operating hydro-based systems must 
predict both system load growth and water availability in order to 
determine whether resources will be available in the next few years to 
provide redispatch. We acknowledge that certain circumstances may in 
fact limit long-term redispatch on these systems due to increased 
prediction risks. We reiterate, however, that all transmission 
providers, including those operating hydro-based systems, are required 
to make a determination, regarding whether planning redispatch service 
can be provided consistent with system reliability based on the 
specific facts of a particular request for service. The fact that 
hydro-based systems may not be able to provide planning redispatch 
service under many circumstances should not necessarily limit the 
availability of conditional firm service on these systems. We expect 
that transmission providers with hydro-based systems will focus on 
provision of the conditional firm option in a manner consistent with 
their system conditions.

[[Page 12388]]

    949. We also repeat that planning redispatch service does not need 
to be provided if doing so would impair the firmness of service to 
existing transmission customers. For example, pre-existing federal 
obligations, such as those described by Bonneville, WAPA and Bureau of 
Reclamation, would qualify as the type of firm commitments to others 
that would excuse transmission providers from the planning redispatch 
obligation to the extent that redispatch impaired service to these 
customers.
(B) Impact on Network Customers and Native Load
    950. Several commenters argue that the use of planning redispatch 
may remove the ability to use reliability redispatch in real-time 
operations to respond to system contingencies, resulting in more 
curtailment of network and native load.\600\ In addition to reducing 
availability of redispatch as an operational tool, NRECA contends that 
planning redispatch will reduce ATC for network service and the 
incentive to build new transmission. Several commenters state that 
planning redispatch may unfairly shift costs to network and native load 
customers.\601\ Progress Energy argues that such a mandate places the 
power grid in serious jeopardy because the system has not been designed 
to handle the redispatch planning model. Progress Energy and Nevada 
Companies state that the planning redispatch option could conflict with 
transmission providers' state resource planning obligations to reliably 
serve load at least cost. Exelon replies, however, that planning 
redispatch could increase flexibility for network customers by 
increasing the availability of point-to-point service across adjacent 
transmission systems to bring generation to network loads.
---------------------------------------------------------------------------

    \600\ E.g., EEI, Duke, Imperial, LPPC, PNM-TNMP, Public Power 
Council, NRECA, NPPD, Southern, and Progress Energy.
    \601\ E.g., EEI, TAPS, LDWP, MidAmerican, Southern, Community 
Power Alliance, and MISO Reply.
---------------------------------------------------------------------------

    951. Some commenters argue that the conditional firm option would 
adversely impact system reliability by subjecting firm customers to 
additional curtailments once conditional curtailment hours are 
exceeded.\602\ NRECA and Utah Municipals state that the conditional 
firm service will reduce the flexibility of network customers by 
preventing network customers from using secondary network service, a 
right that NRECA argues is protected by FPA section 217.
---------------------------------------------------------------------------

    \602\ E.g., Duke, LPPC, NRECA, NPPD, Progress Energy, Southern, 
APPA, and South Carolina E&G.
---------------------------------------------------------------------------

Commission Determination
    952. We reiterate that transmission providers are not required to 
offer planning redispatch and conditional firm point-to-point service 
if doing so would impair the reliable service to firm customers, 
including native load and network customers. The concerns of the 
commenters regarding the impacts on native load, network and other 
existing firm uses are therefore misplaced.
    953. Transmission providers are already obligated to provide 
planning redispatch service pursuant to Order No. 888 and thus 
arguments that the planning redispatch option will harm existing 
customers is equally misplaced. Indeed, under the limitation on the 
duration of planning redispatch service imposed in this Final Rule, 
transmission providers will be able to better manage the risks of 
curtailment for current users of the transmission grid. This is because 
the obligation to redispatch will no longer be an open-ended 
obligation. Customers will need to commit to upgrade the system or to 
have their service reassessed periodically. Both of these allow the 
transmission provider to better plan to serve needs reliably because it 
reduces the unknowns. With regard to NRECA's argument that planning 
redispatch will cause less flexibility in real-time and more potential 
for curtailments of network customers and bundled retail native load, 
all sales of point-to-point service could to some extent cause more 
curtailments of network customers and bundled retail native load. Our 
decision today limits the existing planning redispatch obligation for 
point-to-point service, rather than expanding it.
    954. Similarly, the conditional firm option does not reduce the 
availability of secondary network service or the ability of network 
customers to temporarily undesignate network resources any more than 
short-term firm point-to-point service already reduces the availability 
of these network customer options. We see no reason to reject the 
conditional firm option so that transmission providers avoid offering 
higher-quality service such as conditional firm point-to-point service 
in order to retain the ability to offer lower-quality service such as 
secondary network service.
    955. Finally, we believe that network customers can benefit from 
the use of the planning redispatch and conditional firm options 
available in a point-to-point transmission service request. As 
described below, long-term point-to-point service that employs the 
planning redispatch or conditional firm option would qualify as a 
network resource on any adjoining system importing that resource.
(3) Implementation of Planning Redispatch and Conditional Firm Options
    956. Commenters raise various concerns regarding specific 
implementation issues associated with the planning redispatch and 
conditional firm options. We address those concerns below, but first 
provide an overview of the planning redispatch and conditional firm 
service required in this Final Rule in order to outline the new rights 
and obligations of transmission providers and customers. Following this 
overview, we address specific comments relating to the service.
    957. Pursuant to the modified obligations adopted in this Final 
Rule, where a request for long-term point-to-point firm transmission 
service is made and cannot be satisfied out of existing capacity, the 
transmission provider shall, at the request of the customer and in the 
system impact study, identify (1) the transmission upgrades necessary 
to provide the service, and (2) the options for providing service 
during the period prior to completion of those transmission upgrades. 
Additionally, if upgrades cannot be completed prior to expiration of 
the requested service term, the transmission provider shall, at the 
request of the customer and in the system impact study, identify 
options for providing the service during the requested term. The 
options studied by the transmission provider must include planning 
redispatch and conditional firm options.\603\ The transmission 
provider, at its discretion, may study and offer a mix of planning 
redispatch and conditional firm options for a single service request. 
We provide further detail on each required option below.
---------------------------------------------------------------------------

    \603\ Although partial interim service is not addressed in this 
rulemaking, we note that the OATT continues to require this service, 
on an as available basis, if a multi-year service request is denied.
---------------------------------------------------------------------------

    958. If the transmission provider determines that planning 
redispatch is available, it shall provide the customer with non-binding 
estimates of the incremental costs of redispatch and identify the 
relevant constrained flowgates for which redispatch will be provided. 
For the conditional firm option, the transmission provider shall 
identify the conditions and hours pursuant to which the service may be 
curtailed, using a secondary network curtailment priority, to maintain 
reliability. Specifically, the transmission provider shall identify (1) 
the specific

[[Page 12389]]

system condition(s) when conditional curtailment may apply and (2) the 
annual number of hours when conditional curtailment may apply. 
Customers agreeing to take conditional firm service must choose one of 
these options, conditions or hours.
    959. Where the customer requests firm service for more than two 
years, but is unwilling to commit to a facilities study or the payment 
of network upgrade costs, the transmission provider shall identify and 
provide the planning redispatch or conditional firm options subject to 
the following limitation. The transmission provider shall have a 
periodic right to reassess (1) the planning redispatch required to keep 
the service firm or (2) the conditions or hours under which the 
transmission provider may conditionally curtail the service. This 
reassessment may occur every two years during the term of the service, 
i.e., at the end of year two, year four, year six, and year eight of a 
ten-year service. The transmission provider may not implement 
reassessments during intervening periods nor may it reassess the 
conditions in order to amend the service agreement in an intervening 
year should it forego any biennial reassessment.\604\
---------------------------------------------------------------------------

    \604\ For example, if a transmission provider opts to forego the 
reassessment at the end of year two, the transmission provider may 
not reassess the conditions of the service again until the end of 
year four of service for imposition of new conditions starting in 
year five.
---------------------------------------------------------------------------

    960. The service agreement shall specify the relevant congested 
transmission facilities and whether the transmission provider will 
provide planning redispatch, a mix of planning redispatch and 
conditional firm, or conditional firm in order to provide the point-to-
point transmission service. For the conditional firm option, customers 
must choose among and the service agreement must specify either (1) 
specific system condition(s) during which conditional curtailment may 
occur or (2) annual number of conditional curtailment hours during 
which conditional curtailment may occur. We deem that any service 
agreement that incorporates planning redispatch or conditional firm 
options is a non-conforming agreement and must be filed by the 
transmission provider pursuant to section 205 of the FPA. Additionally, 
transmission providers must file with the Commission any amendments to 
these service agreements that result from reassessments. If a 
transmission provider proposes to change the redispatch or conditional 
curtailment conditions due to a reassessment, the transmission provider 
must provide the reassessment study to the customer along with a 
narrative statement describing the study and reasons for changes to the 
curtailment conditions or redispatch requirements no later than 90 days 
prior to the date for imposition of these new conditions or 
requirements. The transmission provider shall assess the conditions 
based on two years of service or the continuation of the term of 
service, whichever is less.
    961. In situations in which the customer commits to paying the 
costs associated with upgrades necessary to provide the service on a 
fully firm basis, the conditions or hours identified by the 
transmission provider shall remain in effect until such time as the 
upgrades have been completed. Also, for such customers, the service 
agreement shall specify the upgrade costs as determined through the 
facilities study.
(A) Eligibility for and Timing of Planning Redispatch and Conditional 
Firm Options
NOPR Proposal
    962. In the NOPR, the Commission proposed that customers who 
request long-term firm point-to-point transmission service and have the 
service denied because of lack of ATC would be eligible to receive 
planning redispatch service or, if the Commission chose to adopt the 
conditional firm service option, conditional firm service. The 
Commission also proposed earlier evaluation of the planning redispatch 
option in the system impact study rather than in the facilities study. 
The Commission proposed that, if it were to adopt conditional firm 
service, the evaluation of conditional firm availability should occur 
prior to a system impact study or facilities study.
Comments
    963. If the conditional firm option is required by the Commission, 
many commenters believe it should be a bridge product to span the gap 
between when the relevant transmission service request is being studied 
and when the relevant upgrades become operational.\605\ These 
commenters state that a bridge product is appropriate because it would 
not depress funding for new transmission infrastructure and would 
better meet the NOPR's and Congress' grid expansion objectives. In 
their view, use of a bridge product would avoid equity and free rider 
problems that may occur if a conditional firm customer is taking long-
term service and the transmission system is upgraded during that 
service. They also argue that the bridge product would better allow for 
transmission providers to judge the likelihood of curtailment and avoid 
complicated system modeling and planning issues; as well as protect 
existing long-term transmission customers. Duke and Ameren state that 
an annual re-determination of the conditional period is necessary for a 
bridge product. If the upgrade has not been completed within a three 
year period, NRECA suggests that the customer be required to make a new 
long-term firm service request so the provider can update to reflect 
system conditions at that time.
---------------------------------------------------------------------------

    \605\ E.g., Progress Energy Supplemental, PNM-TNMP Supplemental, 
LPPC Supplemental, APPA Supplemental, TAPS Supplemental, TDU Systems 
Supplemental, NRECA Supplemental, EEI Supplemental, Entergy 
Supplemental, Ameren Supplemental, Powerex Supplemental, and MISO 
Supplemental.
---------------------------------------------------------------------------

    964. Several commenters suggest that transmission providers should 
offer conditional firm service as both a bridge product and as a stand-
alone long-term firm service.\606\ Where not used as a bridge service, 
several commenters state that it should be limited to reservations that 
do not have rollover rights.\607\ Duke argues that the service duration 
for non-bridge service should be one year, but with renewal rights that 
give the conditional firm customer a priority over other non-bridge 
conditional firm service customers seeking capacity. APPA supports one 
to two-year service offers.
---------------------------------------------------------------------------

    \606\ E.g., Bonneville Supplemental, PPL Supplemental, EPSA and 
AWEA Supplemental, EEI Supplemental, Barrick Supplemental, and 
Constellation Supplemental.
    \607\ E.g., Xcel Supplemental, Duke Supplemental, and EEI 
Supplemental.
---------------------------------------------------------------------------

    965. In supplemental comments, EEI supports a voluntary conditional 
firm product with three types of service: A one-year product with no 
rollover rights; a bridge product for a term of more than one year that 
is provided until upgrades necessary to accommodate a firm service 
request are completed; and a non-bridge product of more than one year, 
with no rollover rights or transmission provider obligation to 
construct upgrades and subject to the transmission provider's periodic 
review of its system capability to provide such service. EEI contends 
that the Commission should encourage transmission providers to offer 
conditional firm service for more than one year without rollover rights 
to a customer that is not willing to take service of sufficient length 
to allow recovery of upgrades costs, if such service can be provided 
without affecting the reliability and quality of service to firm 
transmission customers.
    966. In support of limitations on the term of conditional firm 
service, many

[[Page 12390]]

commenters state that analyzing and modeling system conditions will 
always be more accurate in the near term than in the long term.\608\ 
EEI and Community Power Alliance believe that limitations on system 
modeling prevent many transmission providers from accurately evaluating 
their ability to provide conditional firm service over long periods. 
According to EEI, system conditions change on both the transmission 
provider's and neighboring systems substantially affecting the ability 
of the transmission provider to provide conditional firm service and 
the periods such service is subject to curtailment. While system loads 
can be predicted with a reasonable degree of accuracy for more than one 
year, other components of the prediction model, such as transmission 
and generator outages, typically are not determined more than a year in 
advance. For example, EEI states that members in the SERC region 
coordinate transmission and generation outages in a 13-month planning 
horizon. Duke states that the ability to model the system varies 
significantly by region. Entergy and MidAmerican believe that system 
modeling limitations would present serious reliability problems if 
transmission providers were required to offer a multi-year conditional 
firm transmission product because even the most advanced modeling 
software cannot predict long-term conditions that may affect service. 
Entergy and MidAmerican propose that the Commission allow transmission 
providers to update the curtailment criteria for a reservation, to 
reflect, among other things, changing load assumptions and forecasts 
over time. MidAmerican argues that without annual reevaluation there 
would be cost shifts to other firm customers. In its reply comments, 
MidAmerican explains that this reevaluation can only occur when the 
actual data becomes available for projecting potential curtailment 
hours.
---------------------------------------------------------------------------

    \608\ E.g., Nevada Companies Supplemental, TDU Systems 
Supplemental, LPPC Supplemental, Ameren Supplemental, Community 
Power Alliance Supplemental, MISO Supplemental, PNM-TNMP 
Supplemental, NRECA Supplemental, and Xcel Supplemental.
---------------------------------------------------------------------------

    967. If a transmission provider offers conditional firm service 
based on specified system conditions, Bonneville states in supplemental 
comments that limitations on modeling do not present a problem. If, 
however, the service is based on a maximum number of conditional 
curtailment hours per year, Bonneville believes that modeling presents 
problems in offering longer-term service. Bonneville states that 
forecasting the number of hours of conditional firm service requires 
great analysis. To remedy this, Bonneville suggests allowing the 
transmission provider to make conditional firm offers under which the 
transmission provider could periodically adjust the number of 
conditional curtailment hours.
    968. In supplemental comments, Constellation proposes that the 
Commission require transmission providers to offer two types of 
conditional firm service: service for less than the service term 
eligible for rollover rights (e.g., five years) if customers do not 
agree to pay for transmission upgrades; and service for five years or 
longer with a rebuttable presumption that the customer is obligated to 
pay for upgrades that are both economic and necessary to relieve the 
constraint that prevents its service from being fully firm.\609\ EPSA 
and AWEA maintain that it is critical that the conditions be defined, 
and remain unchanged, for the term of the service agreement in order to 
obtain financing of new projects. EPSA and AWEA also propose that, if 
the contingency is removed during the life of the customer's 
conditional firm service, the service should convert to traditional 
firm service. Williams, EPSA and AWEA argue that up-front commitment to 
continue the conditions for the entirety of a long-term service 
agreement would take no greater risk than transmission providers take 
today in committing to other long-term firm transmission service. EPSA 
and AWEA state that limited term conditional firm service should pose 
no problems based on system modeling.
---------------------------------------------------------------------------

    \609\ EPSA and AWEA endorse Constellation's approach in defining 
and delineating the two forms of conditional firm service.
---------------------------------------------------------------------------

    969. Several commenters believe that there is no need for any type 
of special rules for conditional firm customers taking bridge service 
and required to pay extremely expensive upgrades.\610\ If the 
Commission abandons the ``higher of'' pricing principle for upgrades, 
these commenters suggest that any new pricing policies should be 
consistent with cost-causation principles and not result in any 
improper socialization.\611\ Other commenters argue for special rules 
when upgrades are extremely expensive.\612\ Xcel states that customers 
should have the option to take short-term conditional firm service that 
would remain subject to limitation and curtailment if upgrades are too 
expensive. Constellation proposes that customers taking the longer-term 
service should have the opportunity to show that upgrades would not be 
just and reasonable given the relevant circumstances, e.g., the cost of 
upgrades for a single service request is $300 million. If the 
Commission determines that the bridge requirement in a particular 
circumstance is unjust and unreasonable, Constellation proposes that 
the transmission provider would provide the service for the requested 
term, but there would be no obligation for the transmission customer to 
pay for such upgrades, and the service would not be eligible for 
rollover. NRECA contends that instances in which special rules apply 
should be extremely rare and are best addressed by the transmission 
provider and customers on an ad hoc basis.
---------------------------------------------------------------------------

    \610\ E.g., Nevada Companies Supplemental, Duke Supplemental, 
Bonneville Supplemental, Powerex Supplemental, BP Energy 
Supplemental, MISO Supplemental, PNM-TNMP Supplemental, Entergy 
Supplemental, Community Power Alliance Supplemental, and Southern 
Supplemental.
    \611\ Proposals regarding the ``higher of'' pricing policy are 
discussed below.
    \612\ E.g., Xcel Supplemental, Constellation Supplemental, and 
NRECA Supplemental.
---------------------------------------------------------------------------

    970. Commenters recognize that upgrades required under a bridge 
conditional firm option could create lumpiness problems,\613\ but most 
commenters suggest that this problem is not unique to the conditional 
firm option, nor can it be resolved through use of the option.\614\ 
These commenters support continuation of the Commission's existing 
policies with regard to lumpiness issues, and some suggest the need to 
address the issue as it pertains to all upgrades in a future 
proceeding.\615\ In contrast, a few commenters suggest that the 
Commission should address the lumpiness issue with regard to 
conditional firm service. PPL, EPSA and AWEA state that the 
transmission provider should be required to pay the costs of any 
incremental lumpiness associated with upgrades and the service request. 
BP Energy contends that any lumpy capacity needs to be resolved on a 
bilateral contractual basis. Powerex suggests using an ``open season'' 
process to finance expensive and lumpy upgrades. California Commission 
supports prorating large lumpy

[[Page 12391]]

upgrades over a large base of new customers, to the extent that it is 
non-discriminatory and fiscally sound.
---------------------------------------------------------------------------

    \613\ In the November 15 Notice, the Commission described an 
example of lumpy capacity as upgrades to provide a requested 100 MW 
of point-to-point service that results in 1,000 MW of additional 
transmission capacity.
    \614\ E.g., EEI Supplemental, Xcel Supplemental, APPA 
Supplemental, Bonneville Supplemental, LPPC Supplemental, NRECA 
Supplemental, Progress Energy Supplemental, Duke Supplemental, 
Ameren Supplemental, Entergy Supplemental, Community Power Alliance 
Supplemental, MISO Supplemental, Williams Supplemental, and PNM-TNMP 
Supplemental.
    \615\ E.g., LPPC Supplemental, Bonneville Supplemental, and EEI 
Supplemental.
---------------------------------------------------------------------------

    971. In supplemental comments, Nevada Companies urge that the time 
period of a conditional firm bridge product should be left up to the 
discretion of each transmission provider. They suggest that most, if 
not all, transmission providers should be able to offer a conditional 
firm service for a one-year period and most should be able to offer it 
for longer periods. Nevada Companies state that they should be able to 
provide conditional firm service in their control areas for longer 
periods, possibly for up to five years in some circumstances and in 
certain locations.
    972. BP Energy and Williams disagree that conditional firm service 
should be a bridge product. They state that such a limitation would 
provide additional opportunities for undue discrimination and limit 
competitive alternatives used to serve customer load. According to 
California Commission, conditional firm service needs to be available 
for long-term requests unless there exists a valid, proven reason why 
conditions make it physically or economically impossible to guarantee 
such service. California Commission states that some limitations on 
modeling should be accepted as justification for not providing 
conditional firm or related services only if such provisions for load 
growth are nondiscriminatory, justified and contractually sound.
    973. Commenters take both sides on whether planning redispatch 
should be evaluated before the customer is obligated to incur the costs 
and delays of a facilities study. EPSA argues that evaluation prior to 
a facility study meets nondiscrimination requirements given the methods 
used by transmission owners to evaluate planning redispatch for their 
own needs. In its reply comments, Exelon supports the minor changes to 
planning redispatch proposed by the Commission, including the earlier 
study of planning redispatch options in the system impact study, and 
states that these changes will expand choices for customers. EEI states 
that requiring an offer of planning redispatch prior to completion of a 
facilities study would be unduly preferential to point-to-point 
customers because transmission providers consider the costs of network 
upgrades and the impacts on system reliability before choosing planning 
redispatch for their native load. Southern points to the internal 
inconsistencies of the NOPR that on one hand seek to expedite the study 
process and on the other hand would require a planning redispatch study 
provision that would slow the study process.
    974. EEI states that the vast majority of facilities studies show 
that the embedded cost of transmission service is higher than the 
incremental amortized cost of upgrades. Thus, EEI argues that the 
Commission's proposal to reform planning redispatch could lead to 
uneconomic decisions by the customer as well as provide disincentives 
to upgrade and expand transmission infrastructure.\616\ In their reply 
comments, Utah Municipals respond that most of the time the embedded 
cost of transmission is higher than the costs of upgrades, adding that 
customers find requests for a transmission upgrades to be a time 
consuming and costly impediment to transmission access. Further, Utah 
Municipals add that limited and occasional redispatch or curtailment, 
would be more economically efficient than the construction of 
transmission facilities most of the time.
---------------------------------------------------------------------------

    \616\ E.g., Xcel, PPM, and BP Energy.
---------------------------------------------------------------------------

    975. Several commenters state that it would be extremely burdensome 
to develop, at the system impact study stage, a reliable estimate of 
the number of hours of redispatch and the cost of the planning 
redispatch.\617\ These commenters state that this would require 
substantial investment in probabilistic studies of equipment 
availability and extensive training of personnel and expansion of data 
collection, yet still would not provide reliable estimates of the 
number of hours or costs of the service. MISO states that at a minimum, 
this would require two years to implement.
---------------------------------------------------------------------------

    \617\ E.g., EEI, Southern, TVA, SPP, E.ON, and MISO.
---------------------------------------------------------------------------

    976. EEI asserts that conditional firm service should be determined 
based on system impact studies and facilities studies so that the 
customer can evaluate the costs of upgrades versus the lack of 
reliability of the conditional firm service. EEI and others also 
propose that conditional firm service only be available when upgrades 
cannot be completed during the term of service or during the period 
prior to completion of transmission upgrades.\618\ In its reply 
comments, Bonneville disagrees that conditional firm service should be 
an interim service available only when the customer has agreed to pay 
for upgrades, stating that such a requirement would undercut the value 
of conditional firm service. Bonneville adds that, for example, the 
costs to build upgrades in order to resolve a constraint in a two-month 
period could raise the costs of the conditional firm service to a 
prohibitive level for little additional benefit to the customer.
---------------------------------------------------------------------------

    \618\ E.g., APPA, PNM-TNMP, and Southern.
---------------------------------------------------------------------------

Commission Determination
    977. As we explain above, the Commission finds that both planning 
redispatch and conditional firm point-to-point service must be offered 
under certain circumstances for the provision of reliable and non-
discriminatory point-to-point transmission service. We set forth below 
the parameters of this service, keeping in mind the concerns expressed 
by commenters.
    978. First, the planning redispatch and conditional firm options 
need only be made available to customers who request firm point-to-
point service of more than a year in duration. When the requested firm 
point-to-point service is not available and the customer agrees to a 
system impact study, the transmission provider must evaluate the 
planning redispatch and conditional firm option at the customer's 
request. If the customer requests study of the planning redispatch or 
conditional firm options, the system impact study must identify the 
following: (1) The system constraints, identified by transmission 
facility or flowgate, causing the need for the system impact study; (2) 
additional direct assignment facilities or network upgrades required to 
provide the requested service; (3) redispatch options, including an 
estimate of the incremental costs of redispatch and the relevant 
congested transmission facilities for which redispatch will be 
provided; and (4) conditional firm options, including the number of 
conditional curtailment hours and the specific system conditions during 
which conditional curtailment may occur. Transmission providers may 
recover the costs of studying these options through the system impact 
study agreement.
    979. Second, we adopt limitations on the nature of the planning 
redispatch and conditional firm options to reflect the two different 
types of customers that may request the service: customers who support 
the construction of upgrades and those who do not.
    980. For customers supporting the construction of upgrades, the 
planning redispatch or conditional firm options will serve as a bridge 
until upgrades are constructed to remedy the congested transmission 
facilities. For these customers, the transmission provider must offer 
planning redispatch or conditional firm service until the time when the 
upgrades are constructed. The conditions or redispatch applicable to 
this period must be specified in the service agreement and are not 
subject to change. We impose this requirement

[[Page 12392]]

because customers who commit to support transmission upgrades are 
typically those financing and constructing new resources. These 
customers require certainty both with regard to upgrade costs and, 
before upgrades can be constructed, the redispatch requirements or 
curtailment conditions that may apply to their service. We disagree 
with Williams and BP Energy that requiring transmission providers to 
offer this bridge product will present more opportunities for undue 
discrimination. As we note above, available information on transmission 
providers' current uses of redispatch and curtailment plans for their 
retail native load indicates that the mechanisms are used for 
relatively short periods of time until upgrades are completed to 
resolve the transmission insufficiencies. Comparable services for long-
term point-to-point customers should therefore be similarly limited to 
shorter time periods or otherwise linked to transmission upgrades.
    981. For customers choosing not to support the construction of new 
facilities, the planning redispatch or conditional firm options also 
must be made available as a reassessment product, i.e., subject to 
certain limitations. Although many transmission providers argue that 
planning redispatch and conditional firm service should be offered only 
to customers who seek to upgrade the grid, we disagree. We find that 
there are legitimate circumstances under which customers may not choose 
to support system upgrades--either because the costs of construction 
are too high or because the term of service (e.g., less than five 
years) does not merit the construction of additional facilities. We 
will therefore make planning redispatch and conditional firm service 
available to such customers, but subject to certain limitations to 
reflect the nature of the services. Specifically, we must select a 
limitation on the term for the conditions that permit interruption or 
redispatch, given that, for these customers, the term is not 
circumscribed by the period during which upgrades are constructed. We 
adopt two years as the appropriate time period to allow the 
transmission provider to reassess the conditions under which planning 
redispatch or conditional firm service is provided. The transmission 
provider will retain the right to reassess the planning redispatch and 
conditional firm option after the first two years of service, and every 
two years thereafter. The transmission provider shall reassess (1) the 
redispatch required to keep the service firm or (2) the conditions or 
hours under which the transmission provider may conditionally curtail 
the service. The customer will receive service for the requested term 
unless the transmission provider determines through its biennial 
reassessment that the firm point-to-point service can no longer be 
reliably provided. The customer may also choose to terminate the 
service at the time of reassessment if the service no longer meets it 
needs.
    982. We select two years as providing a reasonable balance between 
the concerns of potential customers and transmission providers. We 
recognize that a shorter period would increase the reliability of 
predictions, as sought by certain transmission providers, but find that 
a two-year period is consistent with the bridge concept, given that two 
years is often less than the typical time to construct new facilities. 
While this is a shorter period than some transmission customers would 
desire, customers who require greater certainty over the long-term can 
obtain that certainty by agreeing to support the construction of new 
facilities. In the long run, all firm transmission customers, including 
conditional firm customers, should support the expansion of the grid to 
reliably serve load.
    983. We decline to adopt any of the suggestions to address unique 
circumstances that may arise in which upgrades are prohibitively 
expensive. Specifically, we will not adopt Constellation's suggestion 
that customers be able to rebut the presumption that required upgrades 
are just and reasonable. In this Final Rule, we provide customers with 
the option of obtaining planning redispatch or conditional firm service 
for a long term, with the ability to roll over a five-year or longer 
reservation, subject to a limitation that the underlying restrictions 
on the service, i.e., the conditions for redispatch or curtailment, may 
be reassessed by the transmission provider every two years. We believe 
that this option is superior to that proposed by Constellation because 
it will provide the customer with rollover rights while ensuring that 
transmission providers can reliably operate their transmission systems. 
Additionally, since issues of lumpy capacity are present in the 
provision of transmission services generally, we will not address such 
issues in this Final Rule as they do not present issues unique to 
planning redispatch or conditional firm options.
    984. Contrary to the assertion of several commenters, we believe 
that transmission providers would take greater risk in committing to 
conditions for the entire term of a 10-year conditional option than 
they take today in committing to provide unconditioned firm point-to-
point transmission service for a similar period. Planning for reliable 
service for existing transmission customers is a difficult process, but 
it is much more difficult to plan over an extended long-term period for 
reliable service when the service is firm for most of the hours of the 
year and less firm for other hours. This is because many transmission 
providers use annual hourly peak load for two to 10-year planning 
purposes. They would need to substantially change their planning 
methods to ensure no change in service for a conditional firm customer 
that is not expected to be served during the peak hour. We therefore 
adopt a two year assessment window to provide an appropriate degree of 
flexibility for transmission providers' planning needs.
    985. We acknowledge, however, that some commenters, such as 
Bonneville and Nevada Power, state that they may be able to provide 
conditional firm service over a period longer than two years, without 
the need for reassessment. The Commission encourages the provision of 
planning redispatch or conditional firm service for longer periods 
where it is practical. In the event a transmission provider is able to 
extend the assessment period, we will allow the transmission provider 
to waive or extend its right to reassess the availability of the 
option, provided that the waiver or extension is provided consistently 
for all similarly situated service.
    986. With regard to timing of the study of planning redispatch and 
conditional firm options, the Commission finds that study of both 
options is appropriate in the system impact study. The obligation for 
the transmission provider to study planning redispatch options in the 
system impact phase is already present in the existing OATT.\619\ The 
Commission clarifies in this Final Rule the specific requirements 
necessary to meet this obligation. Transmission providers, when 
requested by potential customers, must provide non-binding estimates of 
the incremental costs of planning redispatch and identify the relevant 
congested transmission facilities for which redispatch will be 
provided. Transmission providers will not be required to estimate the 
number of hours of redispatch that may be required to accommodate the 
requested service as proposed in the NOPR. The Commission is persuaded 
by commenters that such an estimate is of limited use to potential 
customers and is difficult, expensive and time consuming for 
transmission

[[Page 12393]]

providers to calculate with any accuracy.
---------------------------------------------------------------------------

    \619\ See pro forma OATT section 19.3.
---------------------------------------------------------------------------

    987. Finally, the Commission disagrees that the study of planning 
redispatch options must necessarily go hand in hand with the study of 
the costs and construction requirements of facility upgrades. Again, 
the obligation to study planning redispatch in the system impact study 
is not new. Our action in reinforcing this existing obligation cannot 
violate comparability or, in itself, cause the slowing of study 
processes. We have moved to a later study of conditional firm options 
so that both options can be studied in tandem. Furthermore, we note 
that the structure of the reassessment product requires the study of 
both options at the system impact study phase, since by definition 
customers opting for the reassessment product are not likely to enter 
into a facilities study agreement. We acknowledge that the few changes 
that we are making to the planning redispatch obligation may increase 
requests for study of the option and certainly the new conditional firm 
option will need more study than in the past. While we recognize the 
tension between the adoption of requirements to speed study completion 
and the increase in studies' complexity caused by the conditional firm 
option,\620\ we will not forego a beneficial new option for customers 
because of this tension. We expect that transmission providers will be 
diligent in completing the system impact studies and in bringing to our 
attention any difficulties in meeting deadlines caused by the study of 
the two options.
---------------------------------------------------------------------------

    \620\ In section V.D.5.a, we adopt a requirement that 
transmission providers post metrics on their performance in 
processing system impact studies and facilities studies.
---------------------------------------------------------------------------

(B) Who Must Provide Planning Redispatch and Conditional Firm
NOPR Proposal
    988. In the NOPR, the Commission requested comment on the 
applicability of these two options to transmission providers who 
operate as RTOs and ISOs. The Commission also requested comment on 
which resources should be required in the provision of planning 
redispatch. First, the Commission proposed that the planning redispatch 
requirement apply to the redispatch of the transmission provider's own 
generation resources, but not to obligate transmission providers to 
purchase new resources to provide the service. If a transmission 
provider cannot accommodate a long-term firm point-to-point 
transmission request through planning redispatch, the Commission 
proposed requiring the transmission provider to identify additional 
generators in other control areas that could relieve the constraint. 
The Commission also requested comment on whether the planning 
redispatch obligation should be expanded to require the use of network 
customer resources in addition to transmission provider resources or 
expanded to require that transmission providers contract to purchase 
off-system resources to facilitate the planning redispatch.
(i) Application to RTOs and ISOs
Comments
    989. RTOs state that reforms regarding planning redispatch and 
conditional firm services are unnecessary in RTO markets with financial 
congestion management because these markets already provide sufficient 
redispatch inside RTOs and sufficient interconnection service for 
generators located at RTO boundaries to address the Commission's point-
to-point service concerns.\621\ Ameren and MISO add that the options 
could disrupt the distribution of financial transmission rights in RTO 
markets. Others disagree and argue that planning redispatch should be 
used by RTOs to define the current and future operational environment 
to ensure that systems are not overbuilt.\622\ AWEA contends that, 
since RTOs and ISOs vary considerably in the services they offer, RTOs 
and ISOs should be required to demonstrate that their services are 
consistent with or superior to planning redispatch and conditional firm 
services. In particular, AWEA argues that RTOs that do not provide 
financial rights should be required to provide both of these services. 
Exelon states on reply that the Commission has proposed minor changes 
to the existing planning redispatch requirement that should not be 
impractical or too burdensome for RTOs to administer.
---------------------------------------------------------------------------

    \621\ E.g., MISO, PJM, California Commission, and ISO New 
England.
    \622\ E.g., AWEA, Indianapolis Power Reply, and Exelon Reply.
---------------------------------------------------------------------------

    990. In its reply comments, California Commission adds that capping 
the frequency or costs of redispatch in an RTO market would 
inappropriately shift the costs of congestion to others. Although SPP 
has successfully used planning redispatch to facilitate short-term firm 
transmission service and to address interim circumstances associated 
with long-term firm transmission service,\623\ it argues that the 
Commission's proposed expanded planning redispatch service would slow 
its batch processing of transmission service, require significant 
investment of time to evaluate the options given the scope of an RTO, 
and create speculative redispatch estimates at best. SPP adds that RTOs 
should simply assist the customer with identification of planning 
redispatch options so that the customer can bilaterally contract with 
the generation owners of its choice.
---------------------------------------------------------------------------

    \623\ Citing Attachment AC of the SPP OATT (Optimal Reservation 
Processing Method for Short Term Firm Transmission Services).
---------------------------------------------------------------------------

    991. MISO adds that conditional firm is inconsistent with RTO 
market mechanisms, requires burdensome changes to curtailment protocols 
and reliability coordinator's procedures, and would impact every tool 
used in real time for congestion management in RTOs. In its reply 
comments, MISO adds that adoption of conditional firm service would 
require revisions to seams agreement protocols. California Commission 
states on reply that the added administrative complexity of conditional 
firm service is unnecessary in the CAISO because the ISO's transmission 
service model makes no distinction between firm and non-firm service 
and provides prospective new customers with information to objectively 
estimate curtailments. FirstEnergy and MISO express concern regarding 
disruption of existing RTO communication protocols if these services 
are required in RTOs.
Commission Determination
    992. Notwithstanding the requirements of section IV.C of this Final 
Rule, the Commission finds that it would be inappropriate to require 
RTOs and ISOs with real-time energy markets to adopt the provisions for 
conditional firm point-to-point service. Customers transacting in RTOs 
and ISOs are able to buy through transmission congestion in the RTOs' 
real-time energy markets and need no prior reservation in order to 
access transmission. Voluntary curtailment in order to access 
transmission is thus not an attractive option given the range of 
options available for customers transacting in RTOs and ISOs. Further, 
in RTOs and ISOs with financial transmission rights, conditional firm 
service may disrupt the distribution of these rights. We therefore 
believe that there is no need to reform existing RTO and ISO procedures 
to satisfy concerns underlying the adoption of the conditional firm 
option.
    993. The Commission directs, however, RTOs and ISOs that already

[[Page 12394]]

provide planning redispatch pursuant to section 13.5 of the pro forma 
OATT to modify the relevant provisions of their tariffs consistent with 
our directives in this Final Rule.\624\ RTOs and ISOs need not amend 
their tariffs if the Commission has previously found that these tariffs 
were just and reasonable without the inclusion of pro forma section 
13.5 planning redispatch provisions. We will not require incorporation 
of the more limited planning redispatch obligations adopted in this 
Final Rule if RTOs and ISOs have already been excused from the planning 
redispatch obligations of the existing pro forma OATT.
---------------------------------------------------------------------------

    \624\ This includes the transmission provider's obligation to 
post monthly redispatch costs for each transmission facility over 
which planning and reliability redispatch are provided.

    (ii) Generation Resources Required for Planning Redispatch
Comments
    994. Most commenters agree that resources in addition to the 
transmission provider's resources can and should participate in the 
provision of planning redispatch. Commenters differ as to whether this 
participation should be mandatory or voluntary. A few commenters 
maintain that participation by resources outside the transmission 
provider's control area could have adverse impacts on reliability in 
the control area.\625\
---------------------------------------------------------------------------

    \625\ E.g., Ameren, PNM-TNMP, Xcel, and WAPA.
---------------------------------------------------------------------------

    995. In arguing for mandatory participation, EEI and others contend 
that all generation resources owned or operated by all jurisdictional 
transmission customers in the control area or balancing authority area 
should be obligated to redispatch to accommodate new requests for 
service in order to avoid undue discrimination.\626\ Exelon argues that 
transmission providers should redispatch resources of its network 
customers, subject to appropriate compensation. SPP contends that 
generation affiliated with transmission owners that have transferred 
functional control of their transmission assets to an RTO should not 
have any greater planning redispatch obligation than unaffiliated 
generation. In its reply comments, Entergy states that the Commission 
at a minimum should continue to allow network customers to request that 
transmission providers redispatch network customer resources in order 
for the customer to designate a new network resource.
---------------------------------------------------------------------------

    \626\ E.g., Southern, FirstEnergy, MidAmerican, and Community 
Power Alliance.
---------------------------------------------------------------------------

    996. Others argue for a least-cost economic dispatch to relieve 
real-time system constraints, including not only the transmission 
provider's own resources and those of its network customers, but also 
all non-affiliated resources both within and outside its footprint that 
choose to be included.\627\ EPSA explains that this redispatch would: 
Require transmission providers to solicit offers from resources to 
provide energy and perhaps ancillary services; be based on a resource's 
offer of service and take into account generating resource and 
transmission operating limits; include performance assurance terms, 
unit commitment procedures, billing, compensation and bidding 
protocols, confidentiality protections, and information-sharing 
protocols; and dispute resolution procedures to avoid disputes rising 
to the level that would require judicial or regulatory intervention. 
AWEA supports Deseret's OATT provisions that require the transmission 
provider to relieve constraints by the least cost means, whether by 
seeking a change in generation output from the transmission provider's 
merchant function or from any other feasible generator. Williams 
suggests that independent generators must be allowed to participate in 
the provision of planning redispatch service through submission of a 
formulary rate to the transmission provider. If the Commission intends 
to have non-affiliated generators participate in planning redispatch, 
PPL states that the Commission should require transmission providers to 
negotiate agreements with generators on their systems.
---------------------------------------------------------------------------

    \627\ E.g., AWEA, Project for Sustainable FERC Energy Policy, 
Exelon, Powerex, Constellation, Williams, Sempra Global, PJM, EPSA, 
and Entegra Reply. Sempra Global contends that the Commission should 
require transmission providers to offer redispatch of non-affiliated 
resources both within and outside its footprint, subject to pre-
existing contractual commitments.
---------------------------------------------------------------------------

    997. TranServ, MidAmerican, and Nevada Companies support a planning 
redispatch service similar to that employed by the Mid-Continent Area 
Power Pool, whereby customers arrange for their own redispatch through 
bilateral or centralized energy markets and submit plans for approval 
to their transmission provider and reliability coordinator.
    998. Several commenters discuss the need for market development in 
conjunction with the planning redispatch obligation. TranServ and Xcel 
state that the planning redispatch option may force transmission 
providers without generation assets to develop some form of energy 
market to arrive at the costs of redispatch. Southern and Progress 
Energy add that forced adoption of such a market would raise 
significant political opposition and be contrary to the Commission's 
commitment in the NOPR to avoid such restructuring.
    999. EPSA, AWEA and PJM support such market development. When a 
generator in another control area is called upon to relieve a 
constraint in regions not administered by an RTO, PJM states that the 
Commission must direct the development of an alternate LMP pricing 
scheme to establish ``system marginal costs'' that are consistent with 
transparent generator pricing in RTO markets. EPSA and PJM argue that 
vertically integrated utilities in non-RTO areas should turn over 
functional control of their dispatch function to a disinterested entity 
or replicate the transparency by publishing generation dispatch. EPSA 
suggests that the Commission require this transparency to ensure 
nondiscriminatory redispatch.
    1000. A few commenters state that any requirement for the 
transmission provider to purchase generation from outside the control 
area to facilitate planning redispatch is functionally unworkable and 
would adversely impact reliability.\628\ EEI supports the Commission's 
proposal to have transmission providers identify off-system resources 
that could provide planning redispatch but requests clarification that 
no additional investigations or studies are required to identify these 
additional options. MidAmerican adds that the coordinated, open and 
transparent planning provisions of the NOPR should provide customers 
with the ability to identify off-system resources. EEI and Southern 
state that any redispatch on adjacent systems should be arranged by 
transmission customers and the service should be curtailed prior to 
other firm uses of the system if the off-system generator fails to 
perform. WAPA and Bonneville argue against the use of off-system 
redispatch, stating that lack of control over these resources could 
cause reliability problems on the originating transmission system. WAPA 
also believes that off-system redispatch would not provide the price 
certainty needed by customers because the redispatched megawatts will 
differ based on the transmission system parameters, and customers would 
be required to pay for any loop flow resulting from the off-system 
redispatch.
---------------------------------------------------------------------------

    \628\ E.g., Xcel, PNM-TNMP, and Public Power Council Reply.
---------------------------------------------------------------------------

    1001. In its reply comments, EEI adds that a requirement for 
transmission providers to solicit planning redispatch

[[Page 12395]]

proposals from generators inside and outside their control areas would 
require that transmission personnel become involved in generation and 
power sales matters in violation of the Commission's Standards of 
Conduct. Duke argues on reply that such an approach would require that 
third party generators reveal their costs to the transmission provider 
and that a means of estimating costs for all generators subject to 
planning redispatch would need to be set forth in the pro forma OATT.
    1002. LPPC, APPA and TAPS oppose any requirement that transmission 
providers redispatch their network customer's resources as well as 
their own to provide planning redispatch, stating that this action 
would appropriate resources beyond the Commission's jurisdiction, 
result in endless conflict between transmission providers and resource 
owners, and interfere with network customer's use of their limited 
resources.
Commission Determination
    1003. Order No. 888 compelled transmission providers to provide 
planning redispatch from their own resources.\629\ The Commission 
declines to expand that obligation to require transmission providers to 
solicit third party resources in order to provide planning redispatch. 
We will, however, require transmission providers to identify in the 
system impact study (1) generation resources located within the 
transmission provider's control area, including its own resources, that 
can relieve the congested transmission facility at issue, and (2) the 
impact of each identified resource on the congested facilities, e.g., 
the generator shift factor. The resources identified in the system 
impact study need not be available to provide the redispatch. Customers 
must simply be provided with the set of generators that could, if 
available, make a significant contribution toward relieving the 
constrained facility at issue. This information, in addition to the 
information provided through congestion planning studies, will provide 
the necessary information to customers wishing to solicit third party 
resources to relieve congested facilities in order to accommodate long-
term firm point-to-point service. We note that this information is 
readily accessible by the transmission provider, as it is the same 
information used to determine pro rata curtailments of firm resources 
in contingency situations.
---------------------------------------------------------------------------

    \629\ See pro forma OATT section 13.5. With respect to SPP's 
assertion that transmission owners' affiliated generation should 
have no greater redispatch obligations than unaffiliated generation 
in RTOs, we find that relevant redispatch obligations in the RTO 
tariff and transmission owners' tariffs govern this issue. See 
Southwest Power Pool, Inc., 110 FERC ] 61,133 at P 17 (2005) 
(rejecting proposed provisions that would have removed the 
obligation for transmission owners to provide planning redispatch).
---------------------------------------------------------------------------

    1004. In addition to identifying generation resources within the 
control area, the Commission also requires identification of resources 
outside the control area that may be able to relieve congested 
transmission facilities. To the extent the transmission provider is 
aware of generation resources outside of its control area that can 
relieve the constraint, the transmission provider must inform the 
customer of these resources. To be clear, this does not require the 
transmission provider to undertake any additional investigation or 
study to identify generation options located outside of the control 
area. To the extent the transmission provider has such information, 
however, it must provide it to the customer.
    1005. The Commission will not mandate the use of network customer 
resources or other third party resources in the provision of planning 
redispatch.\630\ If they choose, network customers and third parties 
may voluntarily provide planning redispatch services. A seller is free 
to post its price to relieve a specific congested transmission facility 
and its ability to relieve the congestion. To facilitate provision of 
such service by third parties, we direct transmission providers to 
modify their OASIS sites to allow for posting of these third party 
offers. Accordingly, we direct transmission providers to work in 
conjunction with NAESB to develop this new OASIS functionality and any 
necessary business practice standards. Transmission providers need not 
implement this new OASIS functionality and any related business 
practices until NAESB develops appropriate standards.
---------------------------------------------------------------------------

    \630\ Network customers will continue, however, to be obligated 
to make their network resources available to the transmission 
provider for reliability redispatch in real time.
---------------------------------------------------------------------------

    1006. Customers may then contract in advance with these third 
parties or use their own resources to secure planning redispatch 
services in lieu of or in addition to service from the transmission 
provider. In this way, customers can arrange for their own planning 
redispatch through bilateral markets and submit plans for approval to 
their transmission provider and reliability coordinator. The 
arrangements must, however, be sufficiently detailed and coordinated 
with the transmission provider to ensure that reliability is 
maintained.
    1007. We therefore direct in this Final Rule that transmission 
providers work with customers to facilitate the use of third party 
generation, where available, in provision of planning redispatch. This 
entails review of redispatch plans submitted by customers, coordination 
between the transmission provider and reliability coordinator, and 
signaling third party generators when the redispatch is needed. These 
arrangements will require close coordination between the transmission 
provider, third party generators and transmission customers. The 
arrangements must be sufficiently detailed to allow the transmission 
provider to maintain reliability. Although we will not allow 
transmission providers to unreasonably deny customers the use of third-
party resources to provide planning redispatch, it is the customers' 
ultimate responsibility to ensure that all the necessary contractual 
and technical arrangements are in place to maintain reliability. We 
clarify for Entergy that this would allow transmission providers to 
continue to provide planning redispatch for network customers from the 
network customers' resources. We also clarify that transmission 
providers may curtail transmission customers if a third-party resource 
fails to perform its contractual redispatch obligation. This or any 
other remedy for non-performance must be specified in writing between 
the parties prior to commencement of the service.
    1008. For the reasons discussed below regarding the TDA proposal, 
we decline to adopt the bid-based redispatch model suggested by EPSA. 
In section V.C.1 of this Final Rule, we similarly reject proposals to 
impose LMP and independent control of the dispatch function. We believe 
that a bid-based generation market design is not necessary to remedy 
undue discrimination in the provision of transmission service. We also 
believe that our modifications to the planning redispatch requirement, 
including the OASIS changes directed herein and the requirement that 
transmission providers make available information on generators capable 
of providing planning redispatch, will provide potential customers with 
greater information about redispatch choices and enable greater 
opportunities for planning redispatch and comparable service.

[[Page 12396]]

(C) Pricing of Planning Redispatch
NOPR Proposal
    1009. In the NOPR, the Commission sought comment on which type of 
redispatch pricing would ensure effective use of the planning 
redispatch option. The Commission described one type of pricing, a 
formula rate, to include a MW quantity, the incremental cost of fuel at 
the point of delivery, and the decremental cost of fuel at the point of 
receipt capped at the price of fuel. The Commission sought further 
comment on whether it would facilitate planning redispatch to base 
calculations of the various costs for input into the formula on the 
difference between the cost of ramping up a generator at the point of 
delivery and ramping down a generator at the point of receipt. The 
Commission also described a redispatch pricing proposal to calculate 
redispatch charges monthly and charge the higher of actual redispatch 
costs or the OATT rate each month made by PacifiCorp in response to the 
NOI.
Comments
    1010. While many specific comments were received on the pricing of 
planning redispatch service, there is little consensus on this subject. 
Several commenters state that pricing challenges associated with 
planning redispatch are difficult if not insurmountable.\631\
---------------------------------------------------------------------------

    \631\ E.g., Powerex, Manitoba Hydro, Seattle, NRECA, Ameren, and 
E.ON.
---------------------------------------------------------------------------

    1011. MidAmerican and EEI argue that the current cap on planning 
redispatch at the costs of upgrades should be removed because a 
customer will always choose planning redispatch and the risks that 
redispatch costs exceed construction costs falls to the transmission 
provider and is either unrecoverable or passed on to other customers.
    1012. According to several commenters, requiring the transmission 
provider to establish a standard fee for planning redispatch, either on 
the overall system or on a path-by-path basis, would accomplish cost 
certainty for the customer and hold the transmission provider 
accountable for the accuracy of the studies used to assess redispatch 
requirements.\632\ These commenters support a standardized formula-rate 
for planning redispatch or a capped amount at, or close to, the 
embedded cost rate. Entegra and TransAlta state that the redispatch 
pricing proposal may allow transmission providers discretion to charge 
redispatch costs without providing customers a practical way to verify 
that claimed redispatch costs have actually been incurred. PGP states 
that the Commission should allow for regional differences in planning 
redispatch pricing. APPA does not support a departure from the current 
redispatch pricing approach, while Seattle states that the existing 
section 13.5 is unworkable because the cost of planning redispatch is 
difficult to calculate for both historical and near-term operating 
horizons, much less over a multi-year planning horizon.
---------------------------------------------------------------------------

    \632\ E.g., Utah Municipals, Public Power Council, PPM, Entegra, 
Constellation, TransAlta and TAPS.
---------------------------------------------------------------------------

    1013. EPSA and AWEA believe that the pricing mechanisms suggested 
in the NOPR would be open-ended and highly variable over the duration 
of the reservation and, thus, not meet the needs of customers. EPSA and 
AWEA assert that, consistent with Commission precedent,\633\ a utility 
must identify and justify its costs in excess of average system costs 
before service commences in a manner that meets the customer's needs to 
charge a rate in excess of average system costs, i.e., some customers 
may require a firm estimate upfront to obtain financing while others 
may be willing to negotiate a rate based on estimates.\634\ EEI states 
on reply that the policy in American Electric Power related to an 
expansion cost rate, which is inapposite to redispatch costs because 
the costs of new construction are easier to estimate in advance than 
are the costs of planning redispatch. EEI contends that the planning 
redispatch customer's interest in price certainty is not a sufficient 
basis for shifting costs to other customers or to the transmission 
provider.
---------------------------------------------------------------------------

    \633\ American Electric Power Service Corp, 64 FERC ] 61,279 
(1993) (American Electric Power).
    \634\ Id. at 62,976.
---------------------------------------------------------------------------

    1014. EPSA and AWEA suggest that, when the cost of planning 
redispatch is estimated to exceed the transmission rate, the 
transmission provider should offer either: a formula rate for 
incremental redispatch costs with the number of hours of redispatch, 
the resources to be redispatched and the conditions under which 
redispatch would occur defined in advance or, an incremental cost rate 
determined at the time of the reservation to cover the reservation 
period that may include a risk adder for the transmission provider. 
Morgan Stanley argues that planning redispatch options should include 
the following: Redispatch priced at a market index; where market prices 
are not available, the price should be the incremental costs; full cost 
pricing should be allowed for ``life of service'' (total dollar cost 
for unlimited redispatch over the term of a contract) or fixed rate 
contracts for actual redispatch agreed to at the time of contracting; 
and redispatch costs provided from a third-party provider. Morgan 
Stanley opposes ``higher of'' pricing that would allow for monthly 
charges for redispatch costs or long-term firm transmission service 
rate.
    1015. In contrast, many transmission providers and EEI ask the 
Commission to allow for recovery of actual costs of redispatch, rather 
than the estimated costs, with the customer obligated to pay all 
costs.\635\ Since providing accurate estimates of redispatch costs and 
hours are difficult, especially with respect to longer-term service 
requests given the variability of fuel costs, transmission providers 
contend that they should not bear the risks of inaccurate cost 
estimates for a service that benefits only the point-to-point 
customer.\636\ Indianapolis Power adds that planning redispatch should 
be priced to discourage inefficient dispatch of generation. In its 
reply comments, PPM agrees that planning redispatch is unworkable 
without certainty of cost recovery for the transmission provider, but 
believes that with enough information customers can evaluate the risks 
and gain certainty required for a workable product.
---------------------------------------------------------------------------

    \635\ E.g., Southern, MidAmerican, Entergy, FirstEnergy, Ameren, 
Nevada Companies, E.ON, and South Carolina E&G.
    \636\ E.g., EEI, Entergy, LPPC, NRECA, MidAmerican, Ameren, and 
FirstEnergy.
---------------------------------------------------------------------------

    1016. Southern argues that the current pro forma OATT language 
unreasonably places the risk of uncertainty in estimating redispatch 
costs on the transmission provider and its native load customers, 
contrary to basic cost causation principles and native load protections 
in Order No. 888. Southern suggests that the Commission follow the 
approach in the Deseret and SPP tariffs, which allow for the 
transmission provider to recover its actual costs of redispatch. Ameren 
states that a standard per kWh fee is simpler to administer, but should 
be structured to recover all of the costs of planning redispatch, 
including opportunity costs.
    1017. Various commenters argue that the Commission should allow the 
following redispatch costs to be recovered: Fuel; variable operations 
and maintenance; increased maintenance costs due to cycling; start-up 
and ramp-down costs; emergency purchases; costs of additional operating 
reserves; environmental costs; and lost opportunity costs.\637\ 
MidAmerican also argues that a transmission provider should be able to 
recover the costs of

[[Page 12397]]

redispatch energy purchased in response to a pre-schedule by a planning 
redispatch customer regardless of schedule changes by the customer and 
regardless of any pro rata curtailments affecting such customers due to 
system reliability.
---------------------------------------------------------------------------

    \637\ E.g., LDWP, EEI, Ameren, MidAmerican, and Southern.
---------------------------------------------------------------------------

    1018. EEI and Southern argue that customers that choose planning 
redispatch should pay the cost of transmission service and the cost of 
redispatch. EEI asserts that allowing recovery of both costs is not 
prohibited ``and'' pricing because the services differ, as one is 
provided by the transmission system and one is provided by generators, 
and native load and network customers pay pro rata shares of 
reliability redispatch costs to relieve constraints on the system as 
well as the basic costs of transmission service. TAPS and TDU Systems 
take the opposite view and state that the Commission should require 
planning redispatch pricing consistent with the Commission's ``higher 
of'' or ``or pricing'' policy. In addition, they state that the 
redispatch charges must be capped up front at fixed dollars and hours 
at or close to the embedded cost rate.
    1019. Arkansas Commission agrees with the PacifiCorp pricing method 
in which redispatch costs are recalculated monthly and customers are 
charged the higher of the redispatch cost rate or the monthly OATT 
transmission rate. TAPS states that this method avoids ``and'' pricing, 
but does not address the complexity or risks associated with 
determining redispatch costs over a long period. APPA argues that the 
PacifiCorp proposal, if applied after the fact, could lead to 
uncertainty and disruption of market transactions. Southern opposes any 
pricing method that caps the total costs that a planning redispatch 
customer would bear, including the PacifiCorp proposal, stating that 
caps allow the planning redispatch customer to shift costs to the 
transmission provider and its native load customers.
    1020. E.ON points to an inherent problem in planning redispatch 
pricing: Transmission providers should be kept whole with regard to 
actual real-time redispatch costs but customers may not know until 
after the fact that the planning redispatch was not economic for their 
purposes. E.ON foresees difficulty in allocating redispatch costs among 
multiple planning redispatch service customers and requests that the 
Commission adopt a specific methodology for calculating each request's 
impact on the system.
Commission Determination
    1021. Although there is no consensus regarding which form of 
pricing methodology is most appropriate for planning redispatch 
service, there is general agreement among the commenters that the 
current pricing rules fail to meet the needs of either customers or 
transmission providers and consequently fail to make planning 
redispatch an attractive means for customers to obtain access to the 
grid. Transmission providers and customers both express concern 
regarding the variability of redispatch costs. Customers worry that 
actual redispatch costs may greatly exceed estimates and thus seek cost 
certainty over the term of the service. Conversely, transmission 
providers claim that accurately estimating future redispatch costs for 
long duration service is extremely difficult. In fact, transmission 
providers state that the uncertainty in forecasting long-term 
redispatch costs is much greater than any uncertainty inherent in 
determining the costs of transmission upgrades.
    1022. The Commission has carefully considered these comments and 
agrees that the current method for pricing planning redispatch service 
is no longer just, reasonable or not unduly discriminatory. The 
Commission takes three principal actions to address the concerns of 
customers and transmission providers.
    1023. The Commission therefore adopts a new pricing method for 
planning redispatch service. We will no longer require the capping of 
redispatch costs over the term of the service at the costs of 
expansion. This change is inextricably linked with the change in the 
obligation to provide planning redispatch, i.e., the removal of the 
open-ended requirement to provide planning redispatch as long as it is 
more economical than transmission upgrades. We have shortened the 
planning redispatch obligation to apply before upgrades are built as a 
bridge product or to apply as part of a reassessment product. In prior 
cases, the Commission expressed the view that capping cost recovery for 
long-term transmission service at the costs of expanding the 
transmission system provides an incentive for transmission providers to 
undertake expansion when it is warranted.\638\ The expansion cost cap 
should not be applied to the bridge product because (1) upgrades will 
in fact be constructed and should be paid for by the customer under the 
``higher of'' policy, and (2) an expansion cost cap does not serve as 
an incentive for expansion because the transmission provider already 
will have started the process of building transmission facilities for 
the customer who opts for the bridge product. If planning redispatch is 
provided as part of a reassessment product, the customer has chosen not 
to pay for upgrades and thus, the expansion cost cap cannot provide an 
incentive for transmission expansion.
---------------------------------------------------------------------------

    \638\ See, e.g., Florida Power & Light Co., 70 FERC ] 61,158 at 
61,484 (1995).
---------------------------------------------------------------------------

    1024. We will therefore adopt a new pricing methodology. We believe 
that the PacifiCorp proposal described in the NOPR is the one that 
balances the competing concerns of transmission customers and 
transmission providers. Under this pricing methodology, customers will 
have the option of paying (1) the higher of (a) actual incremental 
costs of redispatch or (b) the applicable embedded cost transmission 
rate on file with the Commission or (2) a fixed rate for redispatch to 
be negotiated by the transmission provider and customer and subject to 
a cap representing the total fixed and variable costs of the resources 
expected to provide the service. If the customer selects the higher of 
incremental cost or the embedded-cost rate, the transmission provider 
shall calculate the costs of redispatch monthly and charge the higher 
of redispatch or the embedded cost rate each month.
    1025. We have selected a monthly comparison of embedded costs and 
redispatch costs on the basis of a number of factors. The Commission 
has rejected basing the comparison on the life of a long-term firm 
transmission contract.\639\ For administrative efficiency, a 
transmission provider should be allowed to close its books and not be 
subject to possible refunds or surcharges at the end of its billing 
cycle. The standard billing cycle in the industry is one month. 
Allowing transmission providers to finalize accounting entries will 
provide certainty to both the transmission provider with regard to 
revenue recovery and to the transmission customer with regard to cost 
exposure. We therefore find that a monthly comparison of embedded and 
incremental cost is appropriate. This method retains ``higher of'' 
pricing for customers, but does not subject transmission providers to 
open-ended liability for refunds and otherwise should make planning 
redispatch service more attractive for transmission providers to 
provide. Further, given that redispatch often occurs only in selected 
time periods within a year (e.g., during

[[Page 12398]]

the peak season, shoulder months, etc.), it is just and reasonable to 
allow the transmission provider to perform the higher of calculation in 
each month when the service is provided, not spread those costs over 
the entire year.
---------------------------------------------------------------------------

    \639\ Id. at 61,483.
---------------------------------------------------------------------------

    1026. For purposes of calculating planning redispatch charges, 
incremental costs shall include fuel or purchase power costs caused by 
ramping up generator(s) at the point of delivery and ramping down 
generator(s) at the point of receipt. Additionally, where applicable, 
transmission providers may specify in customer service agreements other 
incremental costs for inclusion in the monthly actual incremental 
costs, including opportunity costs. Identification and derivation of 
these costs must be included in the service agreement. We reiterate our 
existing requirement that all information necessary to calculate and 
verify opportunity costs must be made available to the transmission 
customer.\640\ We clarify that the actual costs of redispatch need not 
be determined annually or at the time that the service agreement is 
executed; rather, actual redispatch cost should be determined on a 
monthly basis.
---------------------------------------------------------------------------

    \640\ See Order No. 888 at 31,740.
---------------------------------------------------------------------------

    1027. With respect to MidAmerican's request to be able to recover 
the purchase power costs for a customer requiring planning redispatch, 
we reiterate that transmission providers are under no obligation to 
purchase power to provide planning redispatch services. Should the 
transmission provider take on the obligation to contract with a third 
party to provide planning redispatch at the customer's request, 
however, the customer should be obligated to pay the purchase power 
costs, including any reservation charge for the power. The flow-through 
of purchase power costs must be negotiated between customers and 
transmission providers in a stand-alone agreement if the transmission 
provider agrees to make purchases on the customer's behalf.
    1028. The Commission will not adopt proposals suggested by several 
transmission providers to allow for recovery of the embedded cost 
transmission rate and the full costs of redispatch. The Commission's 
``higher of'' pricing policy prohibits the transmission provider from 
charging both embedded costs and incremental costs such as redispatch 
costs.\641\ We reject EEI's assertion that we should adopt such pricing 
because native load and network customers pay a load ratio share of 
redispatch costs and the embedded cost transmission rate. Planning 
redispatch differs from the reliability redispatch for which 
transmission providers are only obligated to provide network customers 
with ability to avoid real-time curtailments. Rather, planning 
redispatch is a means of creating additional transmission 
capacity,\642\ not a generation service, and thus planning redispatch 
is appropriately priced by applying the Commission's ``or'' pricing 
policy. We decline to revisit that longstanding policy in this 
rulemaking.
---------------------------------------------------------------------------

    \641\ See Pennsylvania Electric Company, 58 FERC ] 61,278, 
62,871-75, reh'g denied, 60 FERC ] 61,034 (1992), aff'd sub nom. 
Pennsylvania Electric Co. v. FERC, 11 F.3d 207 (D.C. Cir. 1993); see 
also Entergy Services, Inc., 71 FERC ] 61,139, 61,452 (1995) 
(regarding the pricing of redispatch service, the Commission stated 
``[i]t is a well-settled matter that the Commission will not 
authorize ``and'' pricing, i.e., embedded cost pricing plus 
opportunity (incremental) cost pricing.'').
    \642\ Order No. 888A at 30,267.
---------------------------------------------------------------------------

    1029. With respect to concerns that the expansion cost cap was 
adopted to provide rate certainty to customers over the term of the 
service,\643\ we believe that the modified pricing policy adopted here 
will continue to provide appropriate certainty to customers, while also 
allowing transmission providers to recover just and reasonable costs. 
For customers purchasing the bridge product, the cost of redispatch 
will be incurred only during the initial term of the service agreement 
while new facilities are being constructed. During this term, the cost 
of redispatch service represents a legitimate cost of providing the 
service and therefore should be fully recoverable under the higher of 
policy. Although it is true that redispatch costs are difficult to 
project, and hence create uncertainty for customers, this does not mean 
that the transmission provider should not be allowed to recover the 
legitimate and verifiable costs of providing the service. Moreover, if 
the customer desires greater certainty regarding redispatch costs 
during this period, it can elect the fixed rate option discussed above 
and negotiate a fixed redispatch charge with the transmission provider. 
Once upgrades are constructed, however, the customer will receive the 
certainty of paying a fixed rate for transmission costs and, 
importantly, any expansion cost will be fixed at the time the initial 
service agreement is signed. Finally, for customers who do not select 
the bridge product because they do not want to fund upgrades, it would 
be unreasonable to cap the cost of redispatch at the cost of upgrades. 
In such an instance, the customer has elected to forego the price 
certainty that can be gained by funding the upgrades to remove the 
constraint that is causing the transmission provider to incur 
redispatch costs.
---------------------------------------------------------------------------

    \643\ Florida Power & Light Co., 70 FERC ] 61,158 at 61,483 
(1995).
---------------------------------------------------------------------------

(D) Standards of Conduct and Planning Redispatch
NOPR Proposal
    1030. In the NOPR, the Commission requested comment on the 
interaction of planning redispatch requirements with the Commission's 
Standards of Conduct.
Comments
    1031. Commenters generally argue that the independent functioning 
requirement and the information sharing prohibitions under the 
Standards of Conduct are irreconcilable with the expanded planning 
redispatch proposal in the NOPR.\644\ Southern, TranServ and Progress 
Energy contend that the planning redispatch option would require close 
coordination and communication with market participants including the 
marketing or energy affiliate, which may create confidentiality and 
Standards of Conduct problems. For instance, they state that close 
coordination and sharing of non-public transmission and customer 
information would be required to determine the generating units that 
can be redispatched, the impact that planned and forced outages of 
redispatched generators will have on the availability of transmission 
service and the transmission line loadings, and the costs of 
redispatch. Some commenters request that the Commission adopt an 
exception to the Standards of Conduct to permit communication between 
transmission providers and marketing and energy affiliates, acting as 
generation operators, for the transmission provider to instruct the 
generation operator to vary its generator's output.\645\
---------------------------------------------------------------------------

    \644\ E.g., Nevada Companies, Community Power Alliance, Progress 
Energy, LPPC, Southern, WAPA, and APPA.
    \645\ E.g., E.ON, Ameren, and APPA.
---------------------------------------------------------------------------

    1032. MidAmerican suggests that it is unlikely that any 
communication protocols could be established that would both comply 
with the Commission's current Standards of Conduct and permit a 
transmission provider to coordinate with its marketing affiliate 
employees to arrange planning redispatch. Rather, MidAmerican argues 
that the transmission customer would have to waive the Standards of 
Conduct to enable the transmission function employees to share the 
necessary information with their marketing affiliate counterparts.

[[Page 12399]]

    1033. Other commenters argue that violations of the Standards of 
Conduct can be avoided by various means. PPM suggests that publication 
of redispatch costs similar to ancillary service costs and elimination 
of case-by-case sharing of information between the transmission 
provider and the generation operators would avoid Standards of Conduct 
issues. MidAmerican states that sole reliance upon bilateral agreements 
with third parties to provide planning redispatch would resolve the 
need to modify the Standards of Conduct. In their reply comments, Utah 
Municipals state that they do not believe the Standards of Conduct pose 
a barrier to provision of planning redispatch since transmission 
providers redispatch to serve their own loads currently, but that if so 
the Commission should make small modifications to the standards.
Commission Determination
    1034. The Commission does not believe that any changes to its 
Standards of Conduct are required for transmission providers to 
implement the planning redispatch provisions adopted in this Final 
Rule. The information at issue, e.g., generation redispatch cost, is 
held by the marketing affiliate and there is no prohibition under our 
Standards of Conduct on the marketing affiliate transferring such 
information to the transmission provider. The information sharing 
prohibitions under the Standards of Conduct are ``one way,'' i.e., they 
restrict only communications of non-public transmission information 
from the transmission provider to the marketing affiliate, not vice 
versa. Therefore, the flow of information from marketing affiliates to 
transmission providers relating to the costs and availability of 
generation resources for planning redispatch is not prohibited under 
the Commission's Standards of Conduct.\646\
---------------------------------------------------------------------------

    \646\ 18 CFR 358.5.
---------------------------------------------------------------------------

    1035. We next turn to the flow of information from the transmission 
provider to the marketing affiliate. Initially, in order for 
transmission providers to evaluate planning redispatch options, they 
must identify the impacted transmission facilities, e.g., flowgates, 
and determine the marketing affiliate's generators that could provide 
redispatch over those facilities. Transmission providers already have 
this information to enable them to provide least cost reliability 
redispatch. However, transmission providers need not provide 
information regarding the impacted transmission facilities to its 
marketing affiliates. Rather, in order for transmission providers to 
evaluate the future availability of redispatch and estimate the costs 
of redispatch, they need only tell the marketing affiliate which of its 
generators would be suitable for redispatch, thus identifying those 
that require study. This sharing of information relating to the 
marketing affiliate's generation is not prohibited by the Commission's 
Standards of Conduct.
    1036. In addition, the transmission provider may also need to 
provide its marketing affiliate with transmission-related information 
from the transmission customer's service request, such as service 
quantity and term, to determine the required duration and amount of the 
redispatch required. We find that such information provided from the 
transmission provider to the marketing affiliate is not a prohibited 
transfer of non-public information because such details of the 
transmission customer's service request are available via OASIS. The 
only customer transmission request information not readily available 
via OASIS is the source and sink information.\647\ We see no need for 
the transmission provider to provide such masked source and sink 
transmission information to its marketing affiliate as part of this 
redispatch evaluation process. We do not believe that any further 
information need be provided by the transmission provider to their 
marketing affiliates to evaluate the generators available for planning 
redispatch and their costs. Accordingly, we find there is no need to 
create an exception to the Standards of Conduct for the sharing of this 
generation-related information and publicly available transmission 
customer request information.
---------------------------------------------------------------------------

    \647\ See Open-Access Same-Time Information System and Standards 
of Conduct, 83 FERC ] 61,360 at 62,456 (1998), reh'g denied, 86 FERC 
] 61,139, reh'g denied, 87 FERC ] 61,382 (1999).
---------------------------------------------------------------------------

(E) Attributes of Conditional Firm
NOPR Proposal
    1037. In the NOPR, the Commission described conditional firm 
service as a modified form of point-to-point service that includes non-
firm service in a defined number of hours of the year when firm point-
to-point service is not available. The Commission proposed that the 
conditional firm service agreement would identify the conditional 
curtailment hours and include an annual or monthly cap on those hours. 
The Commission further proposed that conditional firm service would be 
curtailed before firm uses until such times as the conditional 
curtailment hours were exceeded, after which time the service would be 
treated as firm. The curtailment priority during the conditional period 
was proposed as the same as secondary network service. The Commission 
proposed that customers using the conditional firm option would pay the 
long-term firm point-to-point rate. The Commission also proposed that 
conditional firm service qualify for rollover rights, provided that it 
meets the other rollover right conditions proposed in the Final Rule.
(i) General Terms and Conditions
Comments
    1038. Most commenters support pricing conditional firm service at 
the long-term firm OATT rate and no commenter suggested a different 
pricing method. Nevada Companies and Bonneville state that the customer 
seeking conditional firm service should pay the actual costs of the 
study required to provide the number of conditional curtailment hours.
    1039. EPSA and AWEA support the following components of the 
Commission's conditional firm proposal: Conditional firm is available 
only to customers that first request long-term service; it would 
provide a year round, long-term product that is firm during all hours 
of the year except at well-defined periods when the transmission 
provider is unable to provide the service; and, in all hours that are 
not conditional, conditional firm service would be treated as any other 
firm service with the same curtailment priority as long-term firm 
network and point-to-point rights.
    1040. EEI proposes that conditional firm service be firm in periods 
when firm service is available according to ATC calculations and non-
firm, with a monthly non-firm curtailment priority, for periods when 
firm ATC is not available. CREPC, Exelon and MidAmerican argue that the 
Commission should not require conditional firm service until all 
attributes of the service are clearly defined and key implementation 
issues are resolved, including modification of NAESB and NERC 
processes. NAESB states that the Commission can reduce the amount of 
time required to develop OASIS and transmission loading relief 
protocols by clearly defining the conditional firm service.
    1041. In its supplemental comments, EEI states that the Commission 
should not require all transmission providers to adopt terms and 
conditions for conditional firm service that are only workable for some 
systems, e.g., transmission providers in the Western Interconnection 
using the rated path

[[Page 12400]]

methodology compared to many in the Eastern Interconnection using a 
flow-based methodology; rather, the Commission should allow flexibility 
in the offer of conditional firm service so that transmission providers 
are not foreclosed from offering the service.
    1042. Several commenters state that transmission providers and 
customers collectively should design the conditional firm service that 
best accommodates their respective needs.\648\ In supplemental 
comments, Bonneville states that the transmission provider, not the 
customer, must determine the conditions to offer in response to a given 
request. Bonneville also requests that the Commission clarify that 
there would be no separate queue for conditional firm service.
---------------------------------------------------------------------------

    \648\ E.g., LPPC Supplemental, PPL Supplemental, Williams 
Supplemental, Community Power Alliance Supplemental, Entergy 
Supplemental, and Southern Supplemental.
---------------------------------------------------------------------------

Commission Determination
    1043. The Commission adopts the conditional firm option as a 
modified form of long-term firm point-to-point service that includes 
less-than-firm service in a defined number of hours of the year or 
during defined system conditions when firm point-to-point service is 
not available. The service can be curtailed solely for reliability 
reasons during the defined system conditions or defined number of 
hours. We reject EEI's suggestion to use a monthly non-firm curtailment 
because it would allow for curtailment of the conditional service for 
economic reasons.
    1044. In this Final Rule, we define the minimum attributes of the 
conditional firm option rather than allow individual transmission 
providers to develop any form of service that could conceivably be 
labeled conditional firm service. The Commission has been considering a 
conditional firm product and has been discussing it with the industry 
for some time. In early 2005, the Commission held a technical workshop 
to:

    Work with market participants to develop clear definitions for 
additional wholesale electric transmission services, e.g., 
conditional firm transmission service, develop applicable pro forma 
tariff language that could be included in public utilities' open 
access transmission tariffs and address attendant issues.\649\

    \649\ Potential New Wholesale Transmission Services, Notice of 
Final Agenda for Technical Workshop, 70 FR 12865 (Mar. 16, 2005).
---------------------------------------------------------------------------

    Although commenters in that proceeding stated that the Commission 
need not require new services in transmission providers' OATTs because 
they would be voluntarily developed,\650\ no individual transmission 
provider developed new services in response to the workshop. In fact, 
seemingly, only one transmission provider in the Eastern or Western 
Interconnection offers a service that is similar to the conditional 
firm service adopted in this Final Rule.\651\
---------------------------------------------------------------------------

    \650\ E.g., Bonneville Workshop Comments at 1-2 (April 13, 2005) 
(stating that Bonneville believes the result of the workshop ``will 
be the development of one or more new transmission products.''), 
TAPS Workshop Comments at 2 (April 13, 2005) (suggesting that the 
Commission should invite and consider proposals by individual 
utilities rather than act by rulemaking).
    \651\ In the NOPR, the Commission noted PacifiCorp's 2002 
modifications to partial interim service. See NOPR at P 319 n.298. 
PacifiCorp's service is similar to that proposed by EEI with the 
exception that customers are charged a pro rated long-term firm 
rate.
---------------------------------------------------------------------------

    1045. Since the issuance of the NOPR, the Commission has provided 
the industry with three formal opportunities to provide comments on 
implementation of the conditional firm option. The Commission held a 
technical conference on implementation issues after issuance of the 
NOPR and held many informal technical discussions with industry 
representatives. We have taken these steps in order to make the most 
reasoned decision concerning the minimum attributes of the conditional 
firm option. These conferences and workshops have been helpful and have 
informed our decision on the minimum attributes of conditional firm 
service. As noted herein, although we are establishing certain minimum 
attributes, we also allow for some measure of flexibility in provision 
of the service. We will not, however, approve conditional firm as a 
concept only. Given our past experience, this would provide little 
benefit to customers seeking to use the service and no certainty to 
transmission providers seeking to comply with our regulations.
    1046. Further, as discussed in more detail below, we disagree that 
NERC must modify its processes in order to allow transmission providers 
to implement this product. However, we will allow for a sufficient 
period of time for development of business practices and tracking 
mechanisms to implement the product. We recognize that there may be 
some regional variation in the way transmission providers approach the 
provision of conditional firm service beyond the minimum attributes 
that we establish in this Final Rule. Thus, we do not direct that 
transmission providers work with NAESB to develop business practices 
for implementation of the conditional firm service. Rather, we direct 
transmission providers located in the same region to coordinate such 
development among themselves. We also encourage participation of non-
public utility transmission providers in the region and interested 
transmission customers in the development of these business practices. 
Public utility transmission providers should make efforts to include 
these interested parties in their regional coordination efforts. We 
direct transmission providers to implement these mechanisms and 
business practices within 180 days after the publication of this Final 
Rule in the Federal Register.
    1047. The Commission adopts the proposal in the NOPR that customers 
using the conditional firm service pay the long-term firm point-to-
point rate. We will not allow complete flexibility in defining the 
conditional firm option as suggested by EEI because such an option 
could provide a substantially lower quality service for which 
transmission providers would be able to recover the long-term firm 
rate. We also reject EEI's proposal that the service be a mix of firm 
and non-firm periods. We envision the conditional firm option as one in 
which firm service is available most of the period of a year. EEI seems 
concerned about tailoring the product to situations where congestion is 
so acute that the ``conditions'' require frequent interruptions. We do 
not believe this concern is well founded. Because a conditional firm 
customer is obligated to pay the long-term firm point-to-point rate, we 
assume that few, if any, customers would accept the service in 
circumstances where the interruptions (or ``conditions'') are so 
frequent or pervasive to make the service unattractive.
    1048. Finally, we clarify for Bonneville that customers seeking the 
conditional firm option must first request long-term firm service. When 
ATC is unavailable, the transmission provider must study the 
conditional firm option at the customer's request. There is no separate 
queue for the conditional firm option.
(ii) Specified System Conditions and Conditional Hours
Comments
    1049. Several transmission providers state that they cannot 
accurately predict the conditional curtailment hours because there are 
too many variables to consider and ATC analysis does not provide this 
level of granularity.\652\ These commenters contend that load flow 
modeling for a wide range of

[[Page 12401]]

possible system conditions required to estimate the conditional 
curtailment hours would be complex, time-consuming and costly. Given 
this concern, Southern, PNM-TNMP, and MidAmerican state that any 
conditional firm service should be subject to a ``reasonable efforts'' 
standard and not represent a guarantee of service or a binding estimate 
of conditional curtailment hours from the transmission provider. 
Progress Energy states that it would be difficult to determine a 
specific number of hours that firm service is available, given that the 
industry uses seasonal models. Ameren states that the conditional 
curtailment hours should be spelled out in the transmission service 
agreement.
---------------------------------------------------------------------------

    \652\ E.g., Imperial, Duke, Progress Energy, MidAmerican, PNM-
TNMP, Southern, and EEI.
---------------------------------------------------------------------------

    1050. Several commenters state that the transmission provider 
should provide customers a choice between defined system conditions and 
conditional curtailment hours.\653\ In supplemental comments, EPSA and 
AWEA state that neither option should be arbitrarily excluded; rather, 
they argue that transmission providers should consult with each 
customer in determining the defined conditions that could form the 
basis of the conditional firm service. EPSA and AWEA propose that 
conditional firm should be firm during all hours of the year except in 
those hours in which a defined contingency occurs, and the transmission 
provider is actually unable to provide service. EPSA and AWEA also 
propose that the system impact study should describe the reliability 
contingency and the transmission service agreement should clearly 
define the contingency.
---------------------------------------------------------------------------

    \653\ E.g., Barrick Supplemental, Bonneville Supplemental, BP 
Energy Supplemental, and EPSA and AWEA Supplemental.
---------------------------------------------------------------------------

    1051. EPSA and AWEA state that conditional firm should only be 
curtailed after all non-firm services are curtailed on the same 
constrained path during the period of the defined contingency. Finally, 
AWEA and EPSA state that transmission providers must maintain the 
committed capacity subject to the defined contingency only, reflect 
capacity commitments for conditional firm service in their ATC 
calculations, and be prevented from further curtailing conditional firm 
service due to load growth after the execution of the initial service 
agreement.
    1052. AWEA proposes that if a service agreement specifies 
conditional curtailment hours, the transmission provider must provide 
firm service except in the curtailable hours defined in the service 
agreement and the service must be treated as firm unless the 
transmission provider is actually required to curtail transactions to 
meet reliability requirements and all non-firm transactions have been 
curtailed. Once the transmission provider has reached the annual cap on 
curtailable hours, AWEA argues the customer's service should convert to 
traditional firm service for the remainder of that annual period.
    1053. Utah Municipals reply that transmission providers should be 
bound by their calculations of the availability of firm service, even 
if the firm service is not available year-round.
    1054. FirstEnergy and Nevada Companies state that monthly caps, as 
opposed to annual caps of curtailment hours, would be preferable 
because they provide more information to the customer and are more 
appropriate for transmission systems with mostly seasonal constraints. 
According to Nevada Companies, a curtailment based upon the maximum 
number of hours per year, without taking into account the specific 
times or conditions for those curtailments, would be unworkable in the 
context of a seasonal peak system, such as exists with Nevada 
Companies.
    1055. Several commenters support a variation on conditional firm 
service that would allow a transmission provider to specify either the 
transmission facilities/elements that may become constrained or the 
operating conditions that will result in curtailments of a particular 
conditional firm service.\654\ Many of these commenters propose a 
defined system condition as the trigger for non-firm curtailment of the 
service rather than the use of conditional curtailment hours.\655\ 
Entergy and LPPC propose that such curtailments have the same priority 
as secondary network service. Entergy contends that this service would 
be superior to the conditional firm service described in the NOPR 
because it would be more comparable with the service transmission 
providers make available to network customers and would minimize the 
risk to other customers who might otherwise bear the cost of inaccurate 
conditional curtailment hours, as well as disputes between the 
transmission provider and the transmission customer regarding the 
number of conditional curtailment hours. Seattle and Santee Cooper 
suggest that defining the limitations on the service based on operating 
conditions, with non-binding estimates of hours of curtailment, would 
lead to more effective and reliable operation of the transmission 
system that is consistent with regional requirements.
---------------------------------------------------------------------------

    \654\ E.g., AWEA, EPSA, Project for Sustainable FERC Energy 
Policy, Santee Cooper, Seattle, Entergy, and LPPC.
    \655\ E.g., Santee Cooper, Seattle, Entergy, LPPC, and Nevada 
Supplemental.
---------------------------------------------------------------------------

    1056. In supplemental comments, Bonneville asserts that the 
transmission provider should have the option of offering conditional 
curtailment hours or specified system conditions in order that the 
transmission provider can make a prudent choice based on available 
historical system data.
    1057. In supplemental comments, TAPS argues that conditional firm 
service should be limited to 100 hours per year of conditional 
curtailment, subject to curtailment on the same basis as firm service 
beyond those hours, and made available to and integrated with network 
customers. In TAPS view, this would result in a more efficient use of 
the grid, provide customers sufficient certainty to sign long-term 
power purchase contracts and promote transmission construction. TAPS 
also believes that the customer should have the option of expressing 
the curtailment restriction on the basis of specified system conditions 
in the 100-hour range.
    1058. In its supplemental comments, Entergy suggests that the 
Commission allow more flexibility between the contracting parties to 
identify the conditional nature of the service, i.e., the Commission 
should not prescribe parameters of the conditional period that may 
ignore real-time conditions on the transmission provider's system that 
require a curtailment.
    1059. EEI, Duke, and PNM-TNMP object, in their supplemental 
comments, to specifying system conditions or the maximum number of 
curtailment hours per year, stating that requiring either would be 
incompatible with current curtailment procedures and unfairly shift 
risks of curtailment to other firm customers. EEI, Progress Energy and 
Duke argue that the service should be curtailable during a particular 
season, month or other defined period to provide more certainty to the 
transmission customer and the transmission provider as to when the 
service is subject to curtailment.
    1060. With regard to modeling methods for estimating the 
conditional curtailment hours, EEI asks the Commission not to require 
the transmission provider to use a specific methodology to evaluate 
whether it can provide conditional firm service. Bonneville argues that 
transmission providers need flexibility to modify their ATC 
methodologies to appropriately model the new service and avoid planning 
obligations to firm

[[Page 12402]]

up the conditional curtailment hours of a conditional firm reservation. 
Nevada Companies suggest that the transmission provider use the 
appropriate seasonal operating case with updated projections to 
determine the amount of requested service that can be provided without 
violating reliability criteria.
    1061. Ameren argues that when a transmission provider models system 
contingency events, the events are not interchangeable with a number of 
hours. According to Ameren, the two measurements will produce different 
impacts for the transmission system, and the transmission provider 
should not be required to make both options available at the customer's 
option. LPPC and Public Power Council state that transmission providers 
should not be required to limit the number of curtailments on a monthly 
or yearly basis because of the inherent unpredictability of future 
transmission constraints. APPA states that using curtailment based on a 
specified number of hours will cause the transmission provider to 
overestimate the number of curtailment hours.
    1062. NRECA believes that the Commission should allow for regional 
flexibility in the determination of the parameters of the service and 
transmission providers should have maximum flexibility to set 
conditions that use conservative assumptions (e.g., based on the driest 
weeks of the year, summer or winter peak period constraints). NRECA 
believes such service should be conditioned on operating conditions as 
well as with reference to a number of times of interruption. In 
contrast, MISO supports the election of a consistent method of 
curtailment applied to all customers, in order to make the service 
easier to implement.
    1063. Powerex states that conditional firm service should be 
offered only on paths where curtailment to existing long-term customers 
is not expected to occur.
Commission Determination
    1064. The Commission requires that, when conducting the system 
impact study for the conditional firm option, the transmission provider 
shall identify: (1) The specific system condition(s) when conditional 
curtailment may apply; and (2) the annual number of hours when 
conditional curtailment may apply. A customer must select either 
conditions or hours for incorporation into its conditional firm service 
agreement.
    1065. We require the offer of specific system conditions during 
which conditional curtailment may apply for several reasons. Specified 
system conditions give certainty to the customer that it will only be 
conditionally curtailed when forecasted reliability problems actually 
occur. Transmission providers benefit from this option because they can 
point to specific constraints on their system and implement a 
curtailment plan when those transmission elements are constrained. 
Additionally, designation of specific system conditions may allow for a 
better fit of the conditional firm service to a specific transmission 
provider's system. Consider the example of firm service that is not 
available on a specific system because a transmission line is taken out 
of service for maintenance about two weeks a year. The designation of 
this line as the specific condition for conditional firm service would 
allow the transmission provider to provide firm service without having 
to worry if the maintenance on the line takes an extra week. The 
conditional firm customer has fewer concerns about undue discrimination 
by the transmission provider and could benefit from maintenance on the 
line that was finished one week early. Additionally, we note that many 
commenters representing transmission providers and customers support 
this approach.
    1066. We will require specificity of system conditions. Acceptable 
system conditions include, but are not limited to, designation of 
limiting transmission elements, such as a transmission line, substation 
or flowgate. We do not believe, however, that designation of system 
load levels, standing alone, would qualify as an acceptable system 
condition. Rather, load levels would have to be linked to a specific 
constraint or transmission element that is associated with the request 
for service, e.g., load levels in a constrained load pocket. Otherwise, 
the system load level would not be specific to the part of the system 
over which service is requested and, hence, have no necessary relation 
to the problems, if any, created by the service being requested. 
Furthermore, because most system loads experience load growth every 
year, conditional curtailments would necessarily increase over a multi-
year conditional firm service term.
    1067. We recognize that modeling of the conditional curtailment 
hours entails difficulties beyond those encountered in modeling ATC. To 
address these difficulties we are allowing flexibility in determining 
the number of hours. We clarify that we will not require a standardized 
method of modeling the conditional curtailment hours. We also note that 
the Commission's examination of modeling methods in the NOPR was not 
meant to propose one method over another; rather, it was meant to 
examine possible ways to determine a number of conditional curtailment 
hours to encourage dialog on the issue. Additionally, we will allow 
transmission providers to add a risk factor to their calculation of 
annual curtailment hours to account for forecasting risks. Further, we 
note that our adoption of the conditional bridge and reassessment 
products, detailed above, address modeling difficulties by limiting the 
number of years that a transmission provider must model in determining 
both the number of hours and future system conditions. Moreover, we 
clarify that if the customer selects the annual hourly cap option, the 
transmission provider has the flexibility to conditionally curtail the 
customer for any reliability reason during those hours, including but 
not limited to, the system condition(s) identified in the system impact 
study. Without this flexibility the hourly cap option and the specific 
system condition option would be indistinguishable with a cap on the 
number of hours that the system conditions interruption could occur.
    1068. We will require annual caps on the number of hours because 
calculating an annual cap entails less risk for the transmission 
provider and its existing firm customers than monthly or seasonal caps. 
While we will not require monthly or seasonal caps, we encourage 
transmission providers to offer them if they can overcome modeling 
barriers because monthly or seasonal caps give more certainty to 
customers about the particular aspects of their service. Though we 
allow for flexibility in modeling and determining the number of 
conditional curtailment hours for a particular service request, we 
believe that this will have a minimal impact on conditional firm 
customers. Transmission providers will be allowed to curtail only for 
reliability purposes and conditional firm customers during conditional 
curtailment hours will be curtailed only after all point-to-point non-
firm customers have been curtailed.
(iii) Conditional Curtailment Priority
Comments
    1069. Some commenters agree with the Commission's proposal that 
conditional firm service should have secondary network curtailment 
priority during conditional curtailment hours,\656\ while others 
disagree. Bonneville supports the use of the secondary

[[Page 12403]]

network curtailment priority arguing that customers will value the 
service more with the secondary network priority, thus increasing the 
viability of conditional firm service as an alternative to transmission 
upgrades. EPSA and AWEA argue that conditional firm service during 
conditional curtailment hours should be curtailed after all non-firm 
uses. In their reply comments, TDU Systems oppose EPSA and AWEA's 
position, arguing that secondary network service should have at least 
as high a priority as conditional firm service. In contrast, EEI argues 
that setting the curtailment priority equal to secondary network 
service would adversely impact the reliability of firm service by 
reducing real-time redispatch options and contradict Order No. 888 
precedent that provides priority non-firm service only for network 
customers that pay a load ratio share of system costs.\657\ If 
conditional firm service is implemented, Powerex states that 
transmission providers should provide data and evidence demonstrating 
that the rights of existing long-term firm customers will be protected. 
EEI takes issue with the Commission's proposal to grant conditional 
firm customers priority non-firm service during conditional curtailment 
hours because they would pay for long-term use of the grid, stating 
that all long-term point-to-point customers pay for service on a long-
term basis but, unlike network customers, they do not get priority non-
firm service.
---------------------------------------------------------------------------

    \656\ E.g., Bonneville, AWEA Reply, and EPSA Reply.
    \657\ Citing Order No. 888 at 31,750.
---------------------------------------------------------------------------

    1070. Commenters address implementation issues related to the 
Commission's right of first refusal, tagging, tracking, and curtailment 
priority proposals, as well as other implementation issues implicated 
in the conditional firm service. Manitoba Hydro, Bonneville and Seattle 
support the Commission's proposal that conditional firm service would 
qualify for right of first refusal when firm service becomes available. 
Several commenters believe that the Commission's proposal with regard 
to right of first refusal should be refined to allow automatic 
assignment to conditional firm customers of firm capacity as it becomes 
available in the short term.\658\ Bonneville asserts that prior to 
implementation of the new service the industry must work with NAESB to 
develop a communications protocol to either employ automatic assignment 
or right of first refusal.
---------------------------------------------------------------------------

    \658\ E.g., EEI, EPSA, TranServ, Bonneville, Constellation and 
Seattle Reply.
---------------------------------------------------------------------------

    1071. Entergy and Exelon state that the standards for implementing 
transmission loading relief, including the NERC's Interchange 
Distribution Calculator (IDC), would need modification to allow for 
curtailment. Specifically, Entergy contends that the Commission should 
allow time for the IDC to be modified to specify a different 
curtailment priority for the same transaction depending on the identity 
of the constraining element. Imperial states that it may take over a 
year to develop computer software to correctly handle new curtailment 
priorities during an emergency. Bonneville disagrees and states that 
conditional firm service does not present unique issues with respect to 
curtailment and that it would be curtailable during real time like 
secondary network service.
    1072. EEI states that the conditional firm service as currently 
proposed would conflict with tagging protocols and NERC criteria 
because there is currently no way to tag service as both firm and non-
firm. EEI states that, if conditional firm service is subject to 
curtailment during a specific period, the tag can identify those 
periods and curtailments will be implemented in conditional periods and 
non-conditional periods in accordance with those tags. However, if 
conditional service is curtailable in a certain number of hours, or 
when specific conditions occur, the tag cannot be rewritten in a way 
that will provide for curtailment without personal involvement of 
balancing authority operators, which could lead to increased 
curtailments of firm transmission customers.
    1073. Xcel states that limiting curtailments to a specified number 
of hours per year could result in conditional firm service having 
greater value than firm, while strictly adhering to a maximum number of 
curtailment hours could potentially conflict with the reliability 
standards in section 215 of the FPA. NRECA argues that conditional firm 
service should be subject to pro rata curtailment with all other firm 
users during non-conditional times.
Commission Determination
    1074. We adopt a secondary network curtailment priority to apply 
for the hours or specific system conditions when conditional firm 
service is conditional. During non-conditional periods, conditional 
firm service is subject to pro rata curtailment consistent with 
curtailment of other long-term firm service. Thus, secondary network 
service and conditional firm service when it is conditional will share 
the same curtailment priority. Also, there is no conflict with 
reliability standards because conditional firm service will be subject 
to pro rata curtailment with all other firm uses of the system once 
conditional curtailment hours, if that is the option selected, are 
exhausted.
    1075. The secondary network curtailment priority is appropriate 
because the customer is paying the long-term firm point-to-point rate 
and thus should receive the highest non-firm curtailment priority 
during the conditional curtailment hours or during specified system 
conditions. Adoption of this curtailment priority overcomes what could 
otherwise be significant implementation hurdles. It allows for 
implementation of the service without changes to existing NERC TLR 
practices. NERC and members of the industry need not undertake the 
time-consuming and expensive process of establishing a new curtailment 
priority that is between firm and non-firm service as some commenters 
requested. Use of this curtailment priority also avoids attendant 
decisions relating to the method of curtailment that should apply, 
i.e., pro rata or transactional curtailment, for a quasi-firm 
curtailment priority. It is also consistent with existing interruption 
provisions of the pro forma OATT which provide that secondary service 
cannot be interrupted for economic reasons.\659\ This is consistent 
with our determination that conditional firm service when it is 
conditional is curtailable only to maintain reliable operation of the 
transmission system.
---------------------------------------------------------------------------

    \659\ See pro forma OATT section 14.7.
---------------------------------------------------------------------------

    1076. We reject EEI's argument that the curtailment priority for 
conditional firm service is inconsistent with Commission precedent 
regarding priority non-firm service only for network customers. EEI's 
argument is inapposite. Long-term firm point-to-point customers taking 
fully firm service without the conditional firm option do not need 
access to priority non-firm service as EEI suggests. They have 
assurance that their service will not be interrupted for economic 
reasons and will only be curtailed on a comparable basis with network 
service. This would not be the case for conditional firm customers. We 
also find that EEI has failed to explain the connection between the 
conditional firm transmission service and the availability of 
reliability redispatch options, i.e., generators on its system that can 
ramp up or down in response to a curtailment. We reject Powerex's 
request that transmission providers be required to show that existing 
long-term rights are protected. Each addition of a new long-term firm 
transaction impacts

[[Page 12404]]

the rights of existing firm customers to some extent.
    1077. We disagree with commenters' suggestion that the NERC IDC 
must be changed to accommodate conditional firm service. We reiterate 
that we are not creating a new curtailment priority in this Final Rule. 
We also disagree that new tags that combine a firm and non-firm 
priority must be developed in order to implement the conditional firm 
option. The curtailment priority in a tag can be changed ahead of the 
operating hour based on a near-term forecast of system conditions.\660\ 
We are cognizant that daily and hourly operations to change the tags 
for conditional firm customers likely involve the need for control room 
coordination and development of an appropriate tracking process. As the 
Commission described in the NOPR, new tracking and tagging business 
practices for this service must be developed by each transmission 
provider. Thus, we are allowing a sufficient period for the development 
of these business practices, i.e., 180 days from the date of 
publication of this Final Rule in the Federal Register. As directed 
above, transmission providers must coordinate with other transmission 
providers in their regions to develop these tracking and tagging 
business practices.
---------------------------------------------------------------------------

    \660\ For example, in the Eastern Interconnection, tags can be 
changed up to 35 minutes before the hour in which a TLR event is 
scheduled. See NERC Standard IRO-006-3, Transmission Loading Relief 
Procedures--Eastern Interconnection, section 6.2 (Communications and 
Timing Requirements) at 23-25 (August 2, 2006).
---------------------------------------------------------------------------

    1078. Finally, we address requests to allow for automatic 
assignment of short-term firm point-to-point service to conditional 
firm customers. We agree that transmission providers must take into 
account the conditional firm service in evaluating the availability of 
short-term firm service. Because conditional firm is a long-term firm 
use of the system, it should not be interrupted prior to short-term 
firm service. However, short-term firm service reserved prior to the 
reservation of conditional firm service should maintain priority over 
conditional firm service in the periods when conditional firm service 
is conditional, i.e., when specified system conditions exist or 
conditional curtailment hours apply. Because the assignment proposal 
meets both of these objectives, we direct transmission providers to 
assign short-term firm service to conditional firm customers as the 
service becomes available. Accordingly, we direct transmission 
providers to work with NAESB to develop the appropriate communications 
protocols to implement this attribute of conditional firm service. 
Transmission providers need not implement this requirement until NAESB 
develops appropriate communications protocols.
(iv) Rollover Rights
Comments
    1079. Several commenters support the Commission's proposal that 
conditional firm service would qualify for rollover rights.\661\ 
Manitoba Hydro, Bonneville and Seattle state that rollover rights are 
appropriate where the transmission provider does not have an obligation 
to plan for service to the conditional firm customer during the 
conditional curtailment hours. Bonneville adds that, in rolling over 
conditional firm service, the transmission service agreement should 
allow for no more than the same number of conditional curtailment hours 
than in the original service agreement and provide for fewer hours of 
curtailment if system conditions provide for more firm service. If 
conditional firm service is used as an interim product until 
transmission is built, APPA contends that rollover rights would be 
appropriate.
---------------------------------------------------------------------------

    \661\ E.g., AWEA, EPSA, Manitoba Hydro, Bonneville, TranServ, 
Seattle, and Utah Municipals Reply.
---------------------------------------------------------------------------

    1080. Others argue that rollover rights for conditional firm 
service are inappropriate.\662\ These commenters do not support the 
granting of rollover rights, nor do they support the designation of 
conditional firm service as long-term service. In order to accommodate 
conditional firm rollover rights, FirstEnergy contends that the 
transmission provider would be required to model a number of off-peak 
load flow cases and provide system reinforcements. Ameren states that 
the number of hours that the service will be available at some future 
date after the contract expires will not be known at the time the 
initial contract is executed. EEI adds that estimating conditional 
curtailment hours for 10 years of service is an impossible task. MISO 
states that rollover rights would add more complexity to the AFC/ATC 
calculation process and competition queues. Entergy and EEI state that, 
while subsequent firm transmission service should not be placed ahead 
of the conditional firm service, it is appropriate at the time of a 
rollover request, and perhaps more frequently, to allow the 
transmission provider to update the conditional firm service parameters 
in order to take into account load growth and changes in load for prior 
services.
---------------------------------------------------------------------------

    \662\ E.g., EEI, FirstEnergy, Ameren, SPP, and TDU Systems 
Reply.
---------------------------------------------------------------------------

Commission Determination
    1081. The Commission finds that rollover rights are appropriate for 
point-to-point service that is provided using planning redispatch or 
conditional firm options and would otherwise be eligible for rollover 
rights. The following discussion addresses only rollover rights for 
service that is paired with a transmission provider's biennial 
reassessment right. While the Commission agrees with commenters that 
subsequent firm transmission service requests should not be placed 
ahead of the conditional firm service, we note above our concerns with 
the modeling requirements and reliability impacts of an ongoing service 
that relies upon unchanging curtailment conditions or redispatch 
requirements. The biennial assessment right, discussed above, addresses 
the concern expressed by EEI that transmission providers cannot 
accurately determine conditional curtailment hours or estimate 
redispatch costs for a ten-year service. The biennial review in 
conjunction with rollover rights allows the transmission provider to 
update the parameters of the service in order to maintain reliable 
operations and allows customers to keep their place in the queue ahead 
of other customers seeking conditional firm, planning redispatch 
options, or other firm services.
    1082. Rollover rights for the reassessment product can provide 
significant value to the conditional firm customer. A conditional firm 
customer opting to roll over will retain priority claim to the portion 
of its service that is firm. For example, if a five-year conditional 
firm service initially has a 100-hour annual cap on curtailments, but 
the cap is later reassessed at 150 hours, the rollover right would 
continue to give the customer first call on all but the 150 hours as 
against all other subsequent requests for firm service.
    1083. We note that a customer taking conditional firm or planning 
redispatch options as part of a five-year point-to-point service must 
declare its intent to roll the service over in the fourth year of 
service, coincident with the second biennial review. Thus, we task 
transmission providers and customers, in negotiating their service 
agreement, with coordinating the timing of the biennial review with the 
deadline for declaring rollover intent. Specifically, customers 
deciding whether to renew their service should have information on 
additional conditions on the service or additional estimated redispatch 
costs

[[Page 12405]]

at least 30 days prior to the relevant rollover deadline.
    1084. Additionally, because the biennial review provides the 
transmission provider with the ability to plan for and maintain system 
reliability, we will not allow the rollover right to infringe upon this 
review. Thus, we direct that the transmission provider has a right to 
review the conditions or redispatch requirements at the end of the 
first year of a service that has been rolled over, i.e., year six of 
service, as consistent with a biennial review of service.\663\
---------------------------------------------------------------------------

    \663\ Such a review would occur in the first year of a rolled 
over service if the initial service term was for five years.
---------------------------------------------------------------------------

(v) Use of Conditional Firm Options in Designating Network Resources
Comments
    1085. Several commenters state that the Commission should not 
modify current OATT requirements for designating network resources to 
include resources delivered using conditional firm service; otherwise, 
reliability would be threatened because network customers could lean on 
the system during conditional periods.\664\ They oppose allowing a 
resource taking conditional firm service to qualify as a network 
resource when the associated resource is imported by a network customer 
from an adjacent system. EEI and Duke agree with the Commission's NOPR 
proposal that conditional firm service should not be available to 
network customers and further assert that a product that includes a 
non-firm portion is inappropriate for a load-following service like 
network service. EEI asserts that because the Commission requires that 
network resources be deliverable on a non-curtailable basis, resources 
using conditional firm service cannot be designated as a network 
resource until the maximum conditional curtailment hours have been 
reached. EEI and Duke contend that establishing a defined period of 
curtailment for conditional firm service, either seasonal, monthly, or 
specific dates, eliminates issues with respect to the designation of 
network resources because a resource using conditional firm service 
would be eligible for designation for the part of the year when the 
service was defined as firm. In its reply comments, Duke states that it 
cannot reliably operate its system if it is required to serve unplanned 
load when a network resource is undeliverable due to curtailment of 
conditional firm service.
---------------------------------------------------------------------------

    \664\ E.g., Entergy Supplemental, Southern Supplemental, MISO 
Supplemental, Community Power Alliance Supplemental, and Powerex 
Supplemental.
---------------------------------------------------------------------------

    1086. Other commenters assert that the Commission should create an 
exception to allow designation of network resources that use 
conditional firm service.\665\ AWEA adds that resources should not lose 
their designation when transactions are curtailed pursuant to 
conditional firm service because this is not the way similar resources 
with special protection systems are treated. Several commenters state 
that conditional firm service should qualify as a network resource when 
the associated resource is imported by a network customer.\666\ BP 
Energy adds that more coordination between the two systems with respect 
to specifying the set of conditions or specific set of hours is 
required.
---------------------------------------------------------------------------

    \665\ E.g., AWEA, EPSA, TAPS, APPA, Utah Municipals Reply, and 
Barrick Reply.
    \666\ E.g., Bonneville Supplemental, TDU Systems Supplemental, 
PPL Supplemental, and BP Energy Supplemental.
---------------------------------------------------------------------------

    1087. Some commenters state that conditional firm service should be 
made available to network customers because conditional firm service 
may trump the provision or scheduling of secondary network service and 
because network customers should have service that is at a minimum 
equivalent with point-to-point service.\667\ These commenters suggest 
that the Commission could permit network customers to designate a 
conditional network resource that would be a firm resource for the 
hours when a comparable conditional firm point-to-point service is 
firm. In supplemental comments, NRECA and TAPS argue that ``on-system'' 
LSEs should be allowed to designate a network resource where 
transmission is fully firm for all but the limited time each year, 
e.g., to 100 hours or less, and ``off-system'' LSEs should be allowed 
to treat a network resource supported by conditional firm service as a 
resource on the host system where it takes network service. NRECA 
believes that if the criteria for both network service resource 
designations and for the proposed conditional firm service are based on 
the physical, engineering characteristics of the transmission system, 
the network customer should be able to designate the resource as 
deliverable to load on a non-curtailable basis, except for the 
specified conditions.
---------------------------------------------------------------------------

    \667\ E.g., NRECA, TDU Systems, TAPS, and Utah Municipals Reply.
---------------------------------------------------------------------------

    1088. In its reply comments, Bonneville states that since secondary 
network service cannot be purchased on a long-term basis, the 
Commission should evaluate whether the design and implementation 
challenges of creating a conditional firm service for network customers 
can be overcome. Bonneville also states that other options such as 
seasonal firm and long-term reservation of secondary network service 
should be explored in order to allow network customers similar access 
to monthly ATC.
    1089. Nevada Companies state that network customers have load 
service obligations and should always have unconditional firm service, 
without exception. However, Nevada Companies state that network 
customers could benefit from a service similar to conditional firm 
service. According to Nevada Companies, if a network customer desires 
to deliver its resources to a point of receipt that is not available 
all seasons of the year, it could procure firm transmission capacity 
that is available on a seasonal basis for the delivery of a network 
resource.
    1090. Some commenters state that network customers should be 
permitted to designate as network resources third party power supplies 
that are supported by the supplier's conditional firm reservation.\668\ 
In supplemental comments, Xcel states that it does not oppose allowing 
conditional firm to qualify as a network resource, but it should be 
clear that the service is an exception to the otherwise ``firm is 
firm'' policy that requires all firm users to be curtailed pro-rata.
---------------------------------------------------------------------------

    \668\ E.g., APPA Supplemental, EPSA and AWEA Supplemental.
---------------------------------------------------------------------------

Commission Determination
    1091. The Commission will allow conditional firm point-to-point 
service to qualify as firm service that supports the designation of 
network resources imported from other control areas. As we explain in 
more detail in section V.D.6, the Commission has longstanding 
limitations on network resources. Network resources cannot be 
interrupted for economic reasons and third-party transmission 
arrangements to deliver the resource to the network must be non-
interruptible.\669\ EEI is incorrect that, under our precedent, a 
resource must be ``noncurtailable'' to qualify as a network resource 
under the OATT. All resources are ``curtailable''--e.g., if a unit 
trips off line, the resource is, by definition, curtailed. Network 
resources may also be unavailable due to other reasons besides an 
unplanned unit outage, such as unplanned transmission outages or 
environmental restrictions. It is appropriate to allow conditional firm 
service to support the

[[Page 12406]]

designation of network resources because the conditional firm option 
only affects the transmission of the resource to the network, not the 
interruptibility of the generating resource itself. Conditional firm 
service satisfies the Commission's requirement for the delivery of the 
resource to the network to be non-interruptible because such 
transmission service is curtailable only for specific reliability 
reasons, not economic reasons.
---------------------------------------------------------------------------

    \669\ Wisconsin Public Power Inc. v. Wisconsin Public Service 
Corp., 84 FERC ] 61,120 at 61,660 (1998) (WPPI).
---------------------------------------------------------------------------

    1092. We decline, however, to adopt the conditional firm option for 
network service. Commenters argue that conditional firm network service 
should be made available to prevent conditional firm point-to-point 
service from ``trumping'' the scheduling of secondary network service 
and to ensure that network service is at a minimum equivalent to point-
to-point service. Concerns regarding conditional firm point-to-point 
service ``trumping'' secondary network service would not be resolved by 
creating conditional firm network service. The ``as available'' nature 
of secondary network service will still permit all firm uses of the 
system, including conditional firm service, to have a higher 
reservation priority than secondary network service. Creating a 
conditional firm network service would not change that reservation 
priority.
    1093. Others argue that conditional firm network service should be 
required in order to ensure that network service is equivalent to 
point-to-point service. As noted above, however, the two services are 
not precisely the same, nor were they intended to be identical. In 
Order No. 888, the Commission attempted to strike a balance between 
competing interests in designing network and point-to-point 
transmission services, each service with its own costs and benefits. It 
is therefore appropriate that we consider the need for conditional firm 
service in each context. While we conclude that implementation of 
conditional firm network service is not necessary to remedy undue 
discrimination at this time, we note that allowing conditional firm 
point-to-point service will nonetheless provide substantial benefits to 
network customers by allowing the designation of network resources 
delivered to the network from other control areas using conditional 
firm point-to-point service. Conditional firm point-to-point service 
will thereby allow network customers to access new alternative power 
sources. Transmission providers are free to make a filing under FPA 
section 205 proposing conditional firm network service.
    1094. Finally, in light of our conclusions above that conditional 
firm service satisfies the Commission's requirements for designating 
network resources because the delivery of the resource to the network 
is not interruptible for economic reasons, we do not need to adopt a 
seasonal, monthly or periodic method for determining the conditions 
under which conditional service may be curtailed as suggested by EEI 
and others.
b. Proposals for Transparent Redispatch
NOPR Proposal
    1095. In the NOPR, the Commission explained that the major focus of 
this rulemaking was to strengthen the pro forma OATT in order to remedy 
undue discrimination rather than create new market structures. The 
Commission stated its intention to retain the use of an OATT to 
facilitate the development of competitive wholesale markets by reducing 
barriers to entry through the control of transmission assets, not 
impose any particular market structure on the industry.
Comments
    1096. Several commenters argue that the Commission should expand 
the planning redispatch requirements of the pro forma OATT to 
incorporate third party provision of redispatch and bidding 
protocols.\670\ In reply comments, Transparent Dispatch Advocates 
submitted a proposal that, among other things, would require 
transmission providers to (1) post the real-time cost estimate of 
providing redispatch service from their resources at congested 
locations, (2) accept offers from third parties to provide redispatch 
service, and (3) provide real-time redispatch to resolve transmission 
constraints. Transparent Dispatch Advocates argue that their proposal 
is consistent with the scope of the rulemaking because it would not 
require the adoption of LMP markets or other standardization; rather, 
it would simply provide cost visibility and proper cost assignment of 
the dispatch decisions made by transmission providers.
---------------------------------------------------------------------------

    \670\ See section V.C.1 of this Final Rule for a discussion of 
comments regarding independent dispatch and spot market development.
---------------------------------------------------------------------------

    1097. In a notice issued on November 15, 2006, the Commission 
sought further comment on the TDA proposal. The Commission asked, inter 
alia, about implementation impediments and confidentiality issues 
related to posting redispatch costs, whether the TDA proposal was 
required to remedy undue discrimination, and whether third party 
participation in redispatch would require market mechanisms.
Commission Determination
    1098. The Commission addresses below two distinct parts of the TDA 
proposal: (1) Expansion of transmission provider's real-time 
reliability redispatch obligation as well as inclusion of third-party 
resources in provision of redispatch and (2) posting of real-time 
redispatch costs or prices.\671\ The Commission has carefully 
considered both the TDA proposal and the comments respecting it. We 
agree with many of the public policy goals articulated by Transparent 
Dispatch Advocates, such as increasing the transparency of information 
and increasing the efficient use of existing infrastructure. However, 
we also agree with many of the commenters that certain aspects of the 
TDA proposal are unclear and, depending on its interpretation, may 
require the creation of new services under the pro forma OATT or new 
market structures. We are particularly cognizant of the arguments of 
customer groups such as APPA, NRECA and TAPS that the TDA proposal may 
be difficult to implement, contentious, and may not provide significant 
benefits to customers. These customers also are concerned that it may 
detract from other reforms considered in this proceeding that they 
believe provide greater benefits, such as transmission planning reform.
---------------------------------------------------------------------------

    \671\ Transparent Dispatch Advocates' proposal for mandatory 
coordination agreements between transmission providers for provision 
of redispatch service is addressed in section V.C.1 of this Final 
Rule.
---------------------------------------------------------------------------

    1099. After considering the views of all the parties, the 
Commission has sought to strike a reasonable balance between the 
positions of the commenters. On the one hand, we adopt certain reforms 
that will provide additional information regarding redispatch costs in 
a manner that benefits consumers. On the other hand, we will not adopt 
the portions of the TDA proposal that would require the creation of new 
services under the pro forma OATT or new market structures. We do not 
believe that such fundamental changes are necessary or appropriate at 
this time, nor do we have an adequate record upon which to adopt them.
    1100. Specifically, the Commission declines to adopt the TDA 
proposal to expand transmission providers' real-time reliability 
redispatch obligations and incorporate third party bids into 
redispatch. As discussed in detail above, transmission providers will 
continue to have an obligation to

[[Page 12407]]

perform reliability redispatch for network customers and provide the 
planning redispatch described above for point-to-point customers. 
Transmission providers will not be required, as Transparent Dispatch 
Advocates request, to incorporate third party resources when providing 
reliability redispatch or evaluating planning redispatch options for 
point-to-point or network transmission service. We will, however, 
institute a posting requirement so that the actual costs of redispatch 
under existing and future redispatch agreements is made transparent to 
potential customers. While we will not require posting of a real-time 
estimate of redispatch prices as proposed by Transparent Dispatch 
Advocates, the Commission concludes that the posting requirement 
required herein will provide important information regarding the costs 
of redispatch without revealing confidential information that might 
harm existing markets.
(1) Expansion of Reliability Redispatch Obligation and Inclusion of 
Third Party Resources
Comments
    1101. In reply comments filed September 20, 2006, Transparent 
Dispatch Advocates argue that the Commission must bring transparency to 
the dispatch function to make redispatch effective and fair and to 
thereby remedy the potential for discriminatory provision of 
transmission service. Transparent Dispatch Advocates assert that the 
Commission should require each transmission provider to publish a 
``dynamic real-time value of what it would charge to provide redispatch 
service at specified congestion locations within the transmission 
provider's system and at specified flowgates at the border of the 
transmission provider's system.'' \672\ Transparent Dispatch Advocates 
contend that the publication of this data would: Allow customers to 
assess available real-time redispatch options; allow customers to 
access redispatch at actual costs; allow customers to predict with 
reasonable certainty the costs of redispatch; allow all resource owners 
to voluntarily offer redispatch solutions and be properly compensated 
for their efforts; and over time, support long-term transmission 
service.
---------------------------------------------------------------------------

    \672\ Transparent Dispatch Advocates Reply at 5.
---------------------------------------------------------------------------

    1102. In reply comments, Transparent Dispatch Advocates further 
request adoption of rules that would either require the transmission 
provider to account for independent, third party resources in its 
control area in establishing redispatch costs, or allow independent 
resources to post real-time, cost-based price and quantity bids for 
redispatch plus the resource's impact on the constraint on the 
transmission provider's OASIS. Transparent Dispatch Advocates state 
that the published redispatch values would be cost-based in non-market 
environments.
    1103. On November 3, 2006, a summary of, and frequently asked 
questions regarding, the TDA proposal (TDA Summary) was attached to 
comments filed by San Diego G&E in response to the October 12 Technical 
Conference and in support of the TDA proposal. In the TDA Summary, 
Transparent Dispatch Advocates assert that the Commission need only 
revise the existing redispatch provisions of the pro forma OATT to 
require posting by the transmission providers of the nature of 
congestion at pre-designated flowgates and data concerning the response 
required to relieve congestion. Additionally, the TDA Summary states 
that the transmission provider would have no obligation to provide for 
real-time redispatch from its own or affiliated generation; rather, all 
generators wishing to provide redispatch could volunteer to submit 
bids. Transparent Dispatch Advocates state that these bids could be 
either market or cost based depending on whether the bidder has market-
based rates within the control area. The transmission provider would be 
obligated to evaluate the bids, publish the price for redispatch, and 
call on generators to provide the requested redispatch in real time. 
Transparent Dispatch Advocates suggest that transmission providers 
calculate the price for redispatch by taking the difference between 
bids received by those generators that the transmission provider would 
call upon to increase output (i.e., to redispatch) and the costs the 
transmission provider otherwise would have paid the generator whose 
output is lowered to relieve the constraint. Transparent Dispatch 
Advocates contend that their proposal differs from LMP markets because, 
while LMP sets system-wide clearing prices, their transparent 
redispatch proposal would apply only at selected flowgates and only 
with respect to those transacting at those flowgates.
    1104. On December 15, 2006, in supplemental comments filed in 
response to the Commission's November 15 Notice asking for comment on 
the TDA proposal, Transparent Dispatch Advocates sought to clarify 
their proposal. Transparent Dispatch Advocates propose that the 
Commission impose upon transmission providers an obligation to do the 
following: Provide reliability redispatch to point-to-point customers 
in real-time for comparable treatment to that currently provided to 
network customers and native load; consider their own resources, 
network resources, and offers from non-network resources in providing 
least cost redispatch in real-time; and, publish real-time information 
about the cost of redispatch (including the prices submitted by non-
network resources) on its OASIS site on a frequent and timely basis. In 
their supplemental comments, Transparent Dispatch Advocates propose a 
different method for calculating redispatch prices using the difference 
between the cost of the generation raised and the pre-redispatch 
transmission provider's system-wide marginal cost (e.g., system 
lambda). Transparent Dispatch Advocates further propose that point-to-
point redispatch customers taking this service would not be subject to 
curtailment along with other firm customers in accordance with the 
current OATT curtailment rules. Transparent Dispatch Advocates argue 
that their modified proposal would facilitate comparable access to 
redispatch service and ensure that the existing redispatch provisions 
of the OATT can be made effective.
    1105. Several parties offer comments in support of the TDA 
redispatch proposal.\673\ Constellation encourages the Commission to 
fully consider the TDA proposal in the appropriate context, whether in 
this docket or in a separate proceeding. California Commission states 
that a movement of OATT policy in the direction implied by the TDA 
proposal is necessary to improve efficiency of generation and 
transmission investment. BP Energy believes that a redispatch mechanism 
is necessary to minimize aggregate consumer costs and make redispatch 
equally available to all participants. PPM supports the TDA proposal 
noting that it would provide sufficient cost certainty for both the 
transmission provider and the customer and make more efficient use of 
the existing grid without impacting reliability. Although it opposed 
the proposal initially, MISO states that it now cautiously supports the 
TDA redispatch proposal, provided that RTOs do not bear an 
inappropriate share of costs to modify information technology systems.
---------------------------------------------------------------------------

    \673\ E.g., EPSA and AWEA Supplemental, Constellation 
Supplemental, California Commission Supplemental, PPL Supplemental, 
BP Energy Supplemental, PPM, and San Diego G&E.

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[[Page 12408]]

    1106. Many commenters oppose the TDA proposal stating that the 
record in this proceeding does not warrant implementing such a complex 
and uncertain proposal which imposes significant risks, costs and 
burdens on transmission providers and their native load customers.\674\ 
Public Power Council, Southern, and NRECA do not believe that the 
Commission should adopt the TDA proposal without an analysis of costs 
and benefits and note that no party has provided any such analysis. 
OG&E and Public Power Council state that the costs of congestion likely 
vary greatly by region and argue that Transparent Dispatch Advocates 
have provided no evidence that their industry-wide solution solves 
potential regional redispatch problems.
---------------------------------------------------------------------------

    \674\ E.g., LPPC Supplemental, Community Power Alliance 
Supplemental, Public Power Council Supplemental, Pacific Coast 
Parties Supplemental, EEI Supplemental, Duke Supplemental, Southern 
Supplemental, Southwest Utilities Supplemental, South Carolina E&G 
Supplemental, Ameren Supplemental, Alabama Commission Supplemental, 
Florida Commission Supplemental, Georgia Commission Supplemental, 
North Carolina Commission Supplemental, South Carolina Regulatory 
Staff, and SEARUC Supplemental.
---------------------------------------------------------------------------

    1107. Several state commissions oppose adoption of the TDA proposal 
or urge the Commission to impose significant conditions on the proposal 
to protect retail customers.\675\ SEARUC, Alabama Commission, Florida 
Commission, Georgia Commission, North Carolina Commission and South 
Carolina Regulatory Staff express concern that the TDA proposal would 
make competitively sensitive information available to the public on an 
inconsistent basis, compel the provision of additional services that 
risk increasing retail costs, harm reliable service to retail 
ratepayers that state commissions are obligated by state laws to 
protect, impose administrative difficulties and excessive 
implementation costs, and compel states or regions to change current 
practices or market structures in contradiction of EPAct 2005. SEARUC 
asks the Commission to make clear that implementation of a proposal 
targeted at enhancing transparency will not result in a federally 
imposed change in economic dispatch practices or lessen the amount of 
firm capacity available for service to native load customers. SEARUC 
also expresses concern regarding the imposition of incremental costs 
upon retail ratepayers without prior state approval or the 
implementation of any type of process or organization that has not been 
approved by state regulators as cost effective for retail customers. 
SEARUC opposes the mandatory use of LMP or LMP-like pricing, congestion 
management approach or organized wholesale market structure without 
prior state endorsement; and the mandatory posting of competitively 
sensitive, generation plant-specific costs or price information.
---------------------------------------------------------------------------

    \675\ E.g., Alabama Commission Supplemental, Florida Commission 
Supplemental, Georgia Commission Supplemental, North Carolina 
Commission Supplemental, South Carolina Regulatory Staff, and SEARUC 
Supplemental.
---------------------------------------------------------------------------

    1108. Georgia Commission states that radical restructuring is not 
necessary to achieve the goals stated by the Commission in the NOPR. 
Alabama Commission, Georgia Commission and South Carolina Regulatory 
Staff state that analyses associated with potential implementation of 
new market structures in the Southeast have demonstrated that the 
implementation costs associated with such structures vastly outweigh 
the benefits. North Carolina Commission argues that the TDA proposal 
fails to comply with the Commission's directive in the NOI. In its 
view, the Commission intended to focus in this proceeding on specific 
problems that continue to exist and targeted remedies.
    1109. North Carolina Commission states that the Transparent 
Dispatch Advocates' reply comments incorrectly equate the use of 
redispatch for economic purposes pursuant to 13.5 of the pro forma OATT 
with its use for reliability purposes. North Carolina Commission 
maintains that these services are not comparable, and thus the use of 
redispatch for reliability purposes does not justify requiring a 
transmission provider to provide it for economic purposes. North 
Carolina Commission asserts that implementation of the TDA proposal 
would result in substantial benefits accruing to PJM without 
commensurate benefits to non-RTO areas. North Carolina Commission, 
Southwest Utilities and Southern argue that the costs of implementing 
the proposal are not justified by any potential efficiency benefits and 
thus there is a compelling reason to reject the TDA proposal.
    1110. Several parties argue that the TDA proposal represents a move 
toward Standard Market Design (SMD).\676\ Alabama Commission, Georgia 
Commission and North Carolina Commission submit that the TDA proposal 
shares characteristics with the centralized dispatch and LMP proposals 
advanced in the SMD proceeding and thus conflict with state commission 
jurisdiction in much the same manner as the SMD proposal. Georgia 
Commission and others assert that the only difference between the SMD 
proposal and TDA proposal is that the TDA proposal would require 
transmission providers, but not third party merchants, to make their 
costs transparent.\677\ NRECA believes that a real-time pricing scheme 
based on some value other than actual costs constitutes the creation of 
a new product and an organized, bid-based market in regions that have 
not adopted such market structures. NRECA contends that it would be 
politically unacceptable to reform the OATT in a manner that 
necessitates the formation of regional bid-based markets in non-RTO 
areas.
---------------------------------------------------------------------------

    \676\ Commenters reference a proposal in a proceeding terminated 
by the Commission. See Remedying Undue Discrimination through Open 
Access Transmission Service and Standard Electricity Market Design, 
67 FR 55454 (Aug. 29, 2002), FERC Stats. & Regs. ] 32,563 (2003), 
terminated by, 112 FERC ] 61, 073 (2005).
    \677\ E.g., Community Power Alliance Supplemental, and Entergy 
Supplemental.
---------------------------------------------------------------------------

    1111. In contrast, California Commission supports the TDA proposal 
to the effect that transmission providers should be required to post 
redispatch cost information and to provide real-time redispatch. In 
supplemental comments, California Commission asserts that this effort 
is needed to prevent undue discrimination, for improved efficiency of 
generation and transmission investment and to improve the efficiency, 
transparency and openness of redispatch, and transmission access 
generally.
    1112. Some commenters argue that the TDA proposal is necessary to 
remedy undue discrimination.\678\ Others disagree.\679\ Transparent 
Dispatch Advocates contend that making real-time economic dispatch 
available to ``non-network transmission customers'' is necessary to 
remedy undue discrimination against those customers as compared with 
network customers. In their supplemental comments, EPSA and AWEA state 
that the TDA proposal is necessary to remedy the same undue 
discrimination targeted by the NOPR proposal pertaining to planning 
redispatch service. PPL suggests that the TDA proposal may permit 
transmission customers to benefit from redispatch, which transmission 
owners in non-RTO

[[Page 12409]]

areas now employ to benefit themselves or their native load customers.
---------------------------------------------------------------------------

    \678\ EPSA and AWEA Supplemental, BP Energy Supplemental, 
California Commission Supplemental.
    \679\ E.g., LPPC Supplemental, Community Power Alliance 
Supplemental, Public Power Council Supplemental, Pacific Coast 
Parties Supplemental, EEI Supplemental, Duke Supplemental, South 
Carolina E&G Supplemental, Ameren Supplemental, North Carolina 
Commission Supplemental, South Carolina Regulatory Staff 
Supplemental, and North Carolina Commission Supplemental.
---------------------------------------------------------------------------

    1113. A number of commenters assert that neither the record nor 
Transparent Dispatch Advocates present evidence of discriminatory 
treatment of transmission customers with regard to transparent 
redispatch.\680\ South Carolina E&G asserts that implementation of the 
TDA proposal should not be unjustifiably forced onto individual 
transmission providers given that there is no demonstration that there 
is a problem. MidAmerican and Progress Energy and others argue that 
unsupported assertions of undue discrimination are insufficient to 
support the TDA proposal. These commenters argue that pursuant to the 
recent National Fuel decision, the courts would likely require the 
Commission to overcome substantial hurdles in order to adopt the TDA 
proposal based on theoretical assertions of undue discrimination.\681\ 
These commenters contend that the National Fuel case would likely 
require the Commission to demonstrate how potential undue 
discrimination justifies a costly redispatch proposal, why section 206 
rights are insufficient to ensure redispatch is comparably provided, 
and why the comparability findings of Order No. 888 are no longer 
sufficient.
---------------------------------------------------------------------------

    \680\ E.g., LPPC Supplemental, Community Power Alliance 
Supplemental, Public Power Council Supplemental, Pacific Coast 
Parties Supplemental, EEI Supplemental, Duke Supplemental, 
MidAmerican and Progress Energy Supplemental, South Carolina E&G 
Supplemental, Ameren Supplemental, North Carolina Commission 
Supplemental, North Carolina Commission Staff Supplemental, and 
North Carolina Commission Supplemental.
    \681\ E.g., Entergy Supplemental, LPPC Supplemental, Public 
Power Council Supplemental, and OG&E Supplemental.
---------------------------------------------------------------------------

    1114. In response to assertions that utilities routinely redispatch 
to meet electric load, LPPC argues that there is nothing discriminatory 
about a vertically integrated utility's use of its own 
nonjurisdictional generation to support bundled sales service. LPPC 
states that the use of generation first to serve native load has been 
the fundamental operating principal for jurisdictional and 
nonjurisdictional utilities for decades, and certainly under Order No. 
888. LPPC concludes that this is not a problem calling for Commission 
attention. In response to assertions that TLRs are discriminatory, Duke 
notes that neither the Transparent Dispatch Advocates nor any other 
commenter has provided an analysis of the scope, location and magnitude 
of the TLR problem.
    1115. Many commenters contend that the TDA proposal is ambiguous, 
insufficiently developed or marked by inconsistencies.\682\ Pacific 
Coast Parties argue that the TDA proposal is too sweeping and contains 
too many uncertainties to allow for meaningful comment. Southwest 
Utilities believe that it would be premature for the Commission to 
adopt the TDA proposal without further development, comment, discussion 
and input from affected electric industry stakeholders. PPL and Xcel 
believes that the Commission needs to better define the proposed new 
service and allow comment on the service before detailed tariff 
language is developed to implement this proposed new service. Public 
Power Council contends that, although the proposal appears to seek only 
the posting of information, in reality, Transparent Dispatch Advocates 
ask that the Commission require reciprocal redispatch coordination. 
Public Power Council also argues that the TDA proposal is silent or 
ambiguous concerning critical issues associated with implementation; 
the proposal fails to explain the ``cost'' at which transmission 
providers would offer redispatch or the price, terms, and conditions of 
such a transaction.
---------------------------------------------------------------------------

    \682\ E.g., Pacific Coast Parties Supplemental, Southwest 
Utilities Supplemental, Entergy Supplemental, EEI Supplemental, PPL 
Supplemental, Public Power Council Supplemental, Florida Commission 
Supplemental, SEARUC Supplemental, Progress Energy and MidAmerican 
Supplemental, APPA Supplemental, NRECA Supplemental, and TAPS 
Supplemental.
---------------------------------------------------------------------------

    1116. Several parties refer to seeming discrepancies between 
Transparent Dispatch Advocates' explanations of the proposal and 
question whether the TDA proposal entails cost-based or market-based 
bidding.\683\ APPA notes that Transparent Dispatch Advocates state in 
reply comments that effective redispatch service must reflect actual 
costs. APPA adds that the TDA Summary, in contrast, provides that any 
generator with market-based rate authority in the transmission 
provider's control area could charge a market-based price for 
generation offered for redispatch service. LPPC, TDU Systems, TAPS, 
APPA and NRECA express concern about allowing redispatch providers to 
bid under market-based rate authority. These commenters argue that 
reliance on existing market-based rate authority to support redispatch 
offers no protection against the exercise of market power, given the 
high concentration of transmission provider-owned generation within its 
control area. If the Commission adopts the TDA proposal, APPA asserts 
that the Commission should limit all sellers of generation used for 
redispatch service to cost-based bids and require all parties to 
provide cost information.
---------------------------------------------------------------------------

    \683\ E.g., Progress Energy and MidAmerican Supplemental, APPA 
Supplemental, NRECA Supplemental, and TAPS Supplemental.
---------------------------------------------------------------------------

    1117. In supplemental comments, EEI and Public Power Council assert 
that the Commission in seeking comment on the TDA proposal has not 
proposed a rule with sufficient clarity to allow meaningful comment 
and, therefore, it would be inappropriate to adopt the TDA proposal 
based on this proceeding's record. Pacific Coast Parties add that the 
Commission cannot adopt the TDA proposal based on the sparse record in 
this proceeding. MidAmerican and Progress Energy contend that the 
Commission's notice here does not satisfy Administrative Procedure Act 
requirements for public notice and comments on the TDA proposal. In 
their view, the Commission must initiate a separate rulemaking 
proceeding to evaluate the TDA proposal.
    1118. Progress Energy and MidAmerican assert that, under the 
current pro forma OATT, redispatch is based on a ``careful'' evaluation 
of the reliability and cost impacts of using redispatch on a long-term 
basis and thus the transmission provider is able to serve transmission 
customers and wholesale load-serving obligations at least cost. In 
their view, the transmission provider's retail and wholesale customers 
would absorb the costs to serve transmission customers that obtain the 
forced real-time redispatch under the TDA proposal.
    1119. Community Power Alliance, North Carolina Commission, Progress 
Energy and MidAmerican contend that native load customers would be 
harmed by a requirement that transmission providers sell their excess 
generation to redispatch customers. They state that such a requirement 
would prevent or reduce the sale of generation in competitive markets 
and that these market sales would otherwise reduce costs to native load 
customers. Moreover, where the transmission provider is required to 
redispatch its own generation, Progress Energy and MidAmerican argue 
that Transparent Dispatch Advocates' proposed redispatch would either 
use more expensive units or cause the transmission providers to lose 
the opportunity to make higher valued sales, which also increases costs 
for native load customers.
    1120. In supplemental comments, E.ON, Progress Energy and 
MidAmerican assert that some generators face limits with regard to the

[[Page 12410]]

amount of time that they are allowed to operate due to air emissions 
caps and maintenance schedules. They contend that the TDA proposal 
could cause allowable run time to be ``used up'' prior to the time that 
the generator has fulfilled its planned native load obligation, thus 
requiring that the transmission provider resort to alternative, likely 
more expensive, power supplies for these obligations.
    1121. Several parties assert that Transparent Dispatch Advocates' 
proposal to substitute redispatch for transmission upgrades will 
depress transmission investment.\684\ LPPC argues that Transparent 
Dispatch Advocates' proposal conflicts with the Commission's policy of 
promoting transmission infrastructure development. NRECA states that, 
to the extent that redispatch is required to fulfill long-term point-
to-point service on a particular transmission provider's system, such 
providers have failed to meet their obligations under the existing OATT 
to plan and expand the system for those transmission customers' long-
term needs. NRECA envisions redispatch customers potentially requesting 
``ever more convoluted'' dispatch rules in order to avoid transmission 
upgrades. NRECA prefers better enforcement of section 15.4 of the OATT 
in conjunction with a more open and inclusive planning process. TAPS 
argues that transmission providers will profit from market-based prices 
for redispatch and will be discouraged from transmission expansion. 
TAPS contends that PJM has conceded that LMP signals have proven 
insufficient to create a robust grid. In TAPS view, this counters 
Transparent Dispatch Advocates' claims that their proposal will reveal 
the value of transmission upgrades and encourage investment.
---------------------------------------------------------------------------

    \684\ E.g., LPPC Supplemental, TAPS Supplemental, NRECA 
Supplemental, Southern Supplemental, South Carolina E&G 
Supplemental, and E.ON Supplemental.
---------------------------------------------------------------------------

    1122. Several commenters submit that the TDA proposal raises 
Standards of Conduct issues.\685\ They argue that requiring the TDA 
proposal would complicate if not undermine the functional separation 
and information sharing policies of the Standards of Conduct because 
the transmission function would be performing merchant, or at least 
merchant-related, functions. According to Community Power Alliance, the 
requirement that transmission providers allow merchant generators to 
offer to sell generation to alleviate constraints in order that other 
customers' transactions could flow would violate Standards of Conduct.
---------------------------------------------------------------------------

    \685\ E.g., Nevada Companies Supplemental, Community Power 
Alliance Supplemental, Southwest Utilities Supplemental, and 
Southern Supplemental.
---------------------------------------------------------------------------

    1123. TAPS argues that accurately forecasting the price of long-
term firm service may be difficult and thus the TDA proposal would not 
provide adequate levels of certainty to facilitate long-term service.
    1124. Mark Lively asserts that the TDA proposal fails to address 
other types of redispatch, including loop flow, reactive power, 
Inadvertent Interchange and intra-hour interchange, and as such will 
result in suboptimal operation of the network.
    1125. OG&E questions whether the TDA proposal would apply to RTOs 
but if so, OG&E argues that the proposal should be rejected. OG&E 
contends that the Commission explained in Order No. 2000 that 
congestion management is a regional function and that the TDA proposal 
should not apply to a transmission provider located within an RTO.
    1126. In supplemental comments, Transparent Dispatch Advocates 
contend that the transparent dispatch proposal would not involve the 
establishment of organized markets of any sort; rather, it simply would 
require the posting of redispatch costs. Transparent Dispatch Advocates 
state that the proposal only requires the consideration by the 
transmission provider of additional price data from non-network 
resources and minimal adjustments in transmission provider's reporting 
systems.
    1127. Several parties disagree with Transparent Dispatch Advocates 
and argue that the proposal would require the establishment and 
operation of markets by transmission providers.\686\ APPA and TDU 
Systems assert that under the TDA proposal transmission providers would 
select bids, from among a variety of affiliated and unaffiliated 
resources, that most effectively relieve constraints. Community Power 
Alliance, Georgia Commission, Southern and Entergy assert that the TDA 
proposal would result in the establishment of formal LMP markets in 
non-RTO/ISO areas, or at least start down the ``slippery slope'' to LMP 
markets. Community Power Alliance and Entergy contend that adoption of 
the TDA proposal is in conflict with the purpose of the rulemaking as 
stated in the NOPR and Congress' focus on protecting native load and 
ensuring reliability in EPAct 2005.
---------------------------------------------------------------------------

    \686\ E.g., APPA Supplemental, LPPC Supplemental, TDU Systems 
Supplemental, NRECA Supplemental, Progress Energy and MidAmerican 
Supplemental, Southern Supplemental, Duke Supplemental, OG&E 
Supplemental, Georgia Commission Supplemental, and North Carolina 
Commission Supplemental.
---------------------------------------------------------------------------

    1128. APPA argues that the implementation of the TDA proposal would 
require the following: designation and posting by the transmission 
provider of chosen flowgates; posting by the transmission provider of 
the desired characteristics of generation or demand-side responses that 
could alleviate such constraints; posting by the transmission provider 
of historical redispatch costs; resolution of whether public utility 
transmission providers can be required to provide generation resources 
for redispatch; resolution of whether transmission providers would be 
discriminated against if they were not permitted to charge market-based 
rates; administration by the transmission provider of short-term (daily 
or hourly) market for redispatch, notwithstanding a conflict of 
interest between the transmission provider's market-making and market-
participant roles and possibly third-party monitoring of market 
administration.
    1129. APPA, Xcel, North Carolina Commission, and NRECA raise 
concerns over the costs of establishing and administering redispatch 
markets and systems, including the costs of hardware, software, 
communication systems, billing and reporting systems. North Carolina 
Commission submits that the costs of implementing the TDA proposal 
would be substantial because there are no current practices or rules on 
which to model structures for the TDA proposal. Other commenters 
similarly assert that the TDA proposal would impose significant 
administrative burdens and expenses on transmission providers, 
especially if an independent entity were required for implementation, 
and that most of these costs would be shifted to native load 
customers.\687\ Xcel argues that redispatch cannot be cost-effectively 
managed unless done within the context of a regional Day 2 energy 
market.
---------------------------------------------------------------------------

    \687\ E.g., Community Power Alliance Supplemental, Southwest 
Utilities Supplemental, Florida Commission Supplemental, Ameren 
Supplemental, and Entergy Supplemental.
---------------------------------------------------------------------------

    1130. NRECA asserts that transmission providers would need an 
enormous amount of data, including resource status, marginal generation 
costs, start up costs, ramp rates, and environmental costs of 
operation, to redispatch resources. NRECA asserts that the allocation 
of redispatch costs for multiple customers taking redispatch may be 
difficult.

[[Page 12411]]

    1131. Xcel, APPA, and TDU Systems assert that the TDA proposal 
would not address concerns about subjective redispatch decisions by 
transmission providers. TDU Systems argue that the proposal would allow 
for the functional equivalent of an RTO market, without a market 
administrator that satisfies the independence criteria of Order No. 
2000 or Order No. 888. APPA asserts that posting of information 
concerning the nature of congestion at designated flowgates would be 
followed by differences of opinion as to how the dispatch entity is 
exercising its judgment in calculating the costs and in redispatching 
resources.
    1132. Southwest Utilities and Southern assert that the proposal 
raises significant questions regarding commercial, operational, 
economic, and compliance issues that remain unanswered. For example, 
Southwest Utilities argues that it would appear that under the TDA 
proposal a transmission provider accepting a third party bid would be 
required to assume the commercial obligation, including credit risk 
associated with the bid and the posting of collateral, and would 
execute the contract with the third party bidder under currently 
unspecified terms and conditions. Southwest Utilities and Southern 
further argue that the proposal fails to resolve how operational and 
economic liability to the redispatch customer would be impacted in the 
event of non-performance by a third party supplier. Southwest Utilities 
also asserts that it is unclear whether the TDA proposal could function 
within the rated path/contract path model of much of the Western 
Interconnection.
    1133. Many parties argue that implementation of the TDA proposal 
would raise jurisdictional issues.\688\ Community Power Alliance, South 
Carolina E&G, Progress Energy, MidAmerican and Southern assert that the 
TDA proposal conflicts with state and federal laws in that it forces 
transmission providers to use generation (that was built, dedicated and 
dispatched to serve retail and wholesale customers at least cost) to 
serve other wholesale suppliers and customers. Community Power Alliance 
argues that states, not the Commission, have authority to regulate how 
utilities dispatch generation and procure resources. Further, Community 
Power Alliance asserts that requiring utilities to establish platforms 
for third-party generators' offers would convert the transmission 
function into a generation procurement function, violating the scope of 
the Commission's jurisdiction. Southern, LPPC and North Carolina 
Commission add that the TDA proposal would be in violation of section 
201 of the FPA that expressly limits the Commission's jurisdiction to 
matters which are not subject to regulation by the States. Southern 
further asserts that this is made clearer by the exclusion in section 
201 of ``facilities used for the generation of electric energy'' from 
the Commission's jurisdiction. Southern contends that mandated cost-
based sales would also constitute an unlawful taking of private 
property under the Fifth Amendment of the Constitution.
---------------------------------------------------------------------------

    \688\ E.g., APPA Supplemental, LPPC Supplemental, Community 
Power Alliance Supplemental, South Carolina E&G Supplemental, 
Progress Energy and MidAmerican Supplemental, and Southern 
Supplemental.
---------------------------------------------------------------------------

    1134. LPPC states that Transparent Dispatch Advocates seek to 
reason around section 201 of the FPA in arguing that redispatch ``does 
not involve the sale of electricity for re-sale or consumption; it 
involves the provision of a service to support transmission service.'' 
\689\ LPPC counters that, in redispatch, generation is used instead of 
transmission service rather than in support of transmission service. 
North Carolina Commission, LPPC and APPA argue that the courts have 
previously rejected Commission attempts to extend regulation to matters 
specifically excluded, statutorily, from regulation on the grounds that 
they are the functional equivalent of a jurisdictional service.\690\ 
LPPC also asserts that section 217 of the FPA specifies that utilities 
have a right to use their transmission facilities on a priority basis 
in order to meet their core service obligations.
---------------------------------------------------------------------------

    \689\ Transparent Dispatch Advocates Reply at 17.
    \690\ Citing Northwest Pipeline Corp. v. FERC, 905 F.2d 1403, 
1410-11 (10th Cir. 1990); Detroit Edison Co. v. FERC, 334 F.3d 48, 
54-55 (D.C. Cir. 2003).
---------------------------------------------------------------------------

    1135. North Carolina Commission asserts that in Order No. 888 the 
Commission interpreted its authority under sections 205 and 206 of the 
FPA to include the effect the Rule may have over generation facilities 
because preventing undue discrimination is one of the matters 
specifically provided for in Part II. North Carolina Commission argues 
that California Independent System Operator v. FERC,\691\ however, 
establishes limits on how broadly sections 205 and 206 can be 
interpreted. North Carolina Commission contends that sections 205 and 
206 historically have been interpreted to apply to the rates for 
wholesale sales and purchases, rather than to the underlying generating 
facilities. As a result, North Carolina Commission argues that the 
adoption of the TDA proposal could not be justified under these 
provisions of the FPA.
---------------------------------------------------------------------------

    \691\ 372 F.3d 395 (D.C. Cir. 2004).
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Commission Determination
    1136. The Commission agrees with the Transparent Dispatch Advocates 
proponents that greater transparency of reliability redispatch 
information can provide benefits to consumers, as well as increase 
efficient use of the existing transmission grid. We are therefore 
adopting certain reforms, as explained in the section below, that will 
increase the availability and transparency of redispatch costs. 
However, we are adopting these reforms in the context of the existing 
obligation to provide network and point-to-point transmission service 
under the pro forma OATT. We will not adopt the portion of TDA proposal 
that would require the creation of new services or any broader market 
reforms.
    1137. The TDA proposal has generated controversy for several 
reasons, including the lack of clarity in the proposal, certain 
inconsistencies that appear in Transparent Dispatch Advocates' various 
submissions, and concerns that Transparent Dispatch Advocates' true 
intent is to restructure bilateral markets. We believe that many of the 
concerns regarding the TDA proposal are overstated, but we do agree 
that it lacks clarity and consistency in many important respects. For 
example, it is not clear whether the proposed service would be 
available to all customers, any point-to-point customer including those 
taking non-firm service, or solely to long-term firm point-to-point 
customers.\692\ Additionally, while Transparent Dispatch Advocates 
contend that ``the one step'' required of the Commission is to 
implement a redispatch cost posting requirement,\693\ the TDA proposal 
also would require the Commission to expand the current redispatch 
obligations under the pro forma OATT and adopt complex settlement 
mechanisms to account for third party redispatch. The different TDA 
proposals also vary as compared with each other. For instance, the TDA 
Summary states that transmission providers would not be obligated to 
provide their resources for real-time redispatch, but the Transparent

[[Page 12412]]

Dispatch Advocates Supplemental Comments make clear that the 
transmission provider would be obligated to use its own (or affiliated) 
resources to provide this redispatch.
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    \692\ Compare Transparent Dispatch Advocates Supplemental at 2 
n.4 (stating that the proposed service would supplement the existing 
OATT requirement to provide redispatch to long-term firm point-to-
point customers) and Transparent Dispatch Advocates Supplemental at 
5 (discussing the proposal as a remedy for undue discrimination 
against firm point-to-point customers) with Transparent Dispatch 
Advocates Supplemental at 14-15 (demonstrating the redispatch 
pricing mechanism for a non-firm transaction).
    \693\ Transparent Dispatch Advocates Reply at 18.
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    1138. We first address the contention of Transparent Dispatch 
Advocates that the real-time reliability redispatch obligation of 
transmission providers must be extended to ``non-network transmission 
customers'' to remedy undue discrimination. We disagree. In order to 
remedy undue discrimination, we have made changes to the pro forma OATT 
to implement a new conditional firm option for point-to-point service 
and we make changes to the existing planning redispatch obligation. 
However, Transparent Dispatch Advocates have failed to show that the 
unavailability of reliability redispatch for point-to-point 
transmission customers amounts to undue discrimination. Order No. 888 
provided for reliability redispatch for network customers but not for 
firm point-to-point customers.\694\ There is a good reason for this 
distinction. The pro forma OATT requires network customers to make 
their generation resources available to the transmission provider to 
provide reliability redispatch to maintain the reliability of service 
to both native load and network customers. There is no corresponding 
obligation on point-to-point customers to make their generation 
resources available to provide reliability redispatch. Therefore, the 
two services are not comparable in this respect, which is why 
reliability redispatch service was not required for point-to-point 
customers. However, if a reliability problem does arise, any 
curtailment of firm point-to-point transmission service must be on a 
nondiscriminatory and pro rata basis with the treatment of network 
service and native load customers.\695\ The Commission has found that 
this treatment meets the comparability requirements enunciated in Order 
No. 888.\696\
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    \694\ See pro forma OATT section 33.2; see also Midwest 
Independent Transmission System Operator, Inc., 84 FERC ] 61,231 at 
62,168 (1998) (``redispatch will be utilized to avoid the 
curtailment of firm point-to-point services, a requirement that is 
not imposed under the pro forma tariff.''); Mid-Continent Area Power 
Pool, 87 FERC ] 61,190 at 61,726-27 (1999) (finding no obligation to 
offer reliability redispatch to point-to-point customers and no 
obligation for point-to-point customers to participate in 
reliability redispatch).
    \695\ See, e.g., North American Electric Reliability Council, 88 
FERC ] 61,046 at 61,123-24 (1999) (explaining that pro rata 
curtailment is consistent with comparability even if network/native 
load reduction is accomplished by redispatch and point-to-point 
customer reduction is not); Northern States Power Co., 83 FERC ] 
61,338 at 62,369 (1998) (the existence of redispatch options is not 
a criterion under the pro forma OATT for disproportionate 
curtailments), reh'g, clarification and stay denied, 84 FERC ] 
61,128 (1998), remanded on other grounds sub nom. Northern States 
Power Co. v. FERC, 176 F.3d 1090 (8th Cir. 1999) (Northern States 
Power).
    \696\ Northern States Power, 83 FERC ] 61,338 at 62,369.
---------------------------------------------------------------------------

    1139. Next, we also decline to adopt a requirement for transmission 
providers to incorporate offers to redispatch from third parties into 
their reliability redispatch or planning redispatch. Mandatory 
inclusion of third party offers is not necessary to remedy undue 
discrimination. The pro forma OATT obligates transmission providers to 
use their resources to provide, where available consistent with 
reliability, redispatch service because they do so when serving their 
native load customers. Third party generators do not have this 
obligation, nor do the Transparent Dispatch Advocates propose to create 
such an obligation. Rather, under the TDA proposal, transmission 
providers would remain obligated to provide redispatch service, but 
third party generators would have only the option of doing so. 
Transparent Dispatch Advocates are therefore not proposing comparable 
treatment and we decline to adopt the proposal. This notwithstanding, 
we believe that redispatch offers by third party generators can 
increase system reliability and reduce costs to customers by increasing 
the planning redispatch options available to transmission providers. We 
therefore are adopting, as explained above, a requirement that 
transmission providers modify their OASIS to allow for the posting of 
third party offers to supply planning redispatch. This OASIS posting 
requirement does not obligate transmission providers to incorporate 
bids from third parties into their redispatch; rather, posting of third 
party offers to provide redispatch may be used by transmission 
customers to secure planning redispatch provided the appropriate 
agreements are reached between the customer, third party redispatch 
provider, transmission provider and reliability coordinator.
    1140. We disagree with Transparent Dispatch Advocates and their 
supporters that their proposal for real-time redispatch and third party 
generation participation would allow for additional long-term rights 
through planning redispatch. If third party participation in the offer 
of redispatch is voluntary, transmission providers would not be able to 
depend upon third party resources in evaluating the availability of 
resources during the term of the planning redispatch service. 
Transmission providers therefore would only be able to evaluate the 
availability of their own resource as they do today. Thus, Transparent 
Dispatch Advocates have failed to show how its proposal would 
supplement provision of long-term rights.
    1141. Because we find that the TDA proposal for real-time 
redispatch and third party participation is unnecessary to remedy undue 
discrimination or comparability issues, we need not address the issue 
of the scope of the Commission's jurisdiction as it relates to the TDA 
proposal.
(2) Redispatch Rate Transparency
Comments
    1142. PJM argues that if the Commission does not provide for 
independently administered real-time spot markets, it should require 
transmission providers to ``make public their dispatch sequence and the 
real-time marginal costs of electricity.'' \697\ In reply comments, 
Transparent Dispatch Advocates request that the Commission require 
publication of ``dynamic real-time value of what [each transmission 
provider] would charge to provide redispatch service at specified 
congestion locations within the transmission provider's system and at 
specified flowgates at the border of the transmission provider's 
system.'' \698\ In supplemental comments, Transparent Dispatch 
Advocates state that ``[t]he essence of the TDA proposal is to require 
transmission providers to make real-time information about the cost of 
redispatch available on their OASIS in order to allow more efficient 
use of the transmission system.'' \699\ Transparent Dispatch Advocates, 
EPSA and AWEA state that the posting requirement should be limited to 
pre-determined flowgates and that the estimated price for redispatch 
should be posted frequently and sufficiently in advance of the hour in 
which the price would be effective in order to allow the transmission 
customer to change its schedule and avoid redispatch charges.
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    \697\ PJM at 6.
    \698\ Transparent Dispatch Advocates Reply at 5.
    \699\ Transparent Dispatch Advocates Supplemental at 7.
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    1143. EPSA, AWEA and Transparent Dispatch Advocates state that 
since this information is available today and considered by 
transmission providers in serving their own native load, there are no 
impediments to implementing their proposed posting requirement. 
Transparent Dispatch Advocates argue that concerns about release of 
confidential data can be addressed by

[[Page 12413]]

using system costs instead of unit-specific cost data to calculate the 
posted redispatch price. EPSA and AWEA state that there are not 
confidentiality issues with the Transparent Dispatch Advocates' posting 
proposal because redispatch costs are not the costs that the 
transmission provider is incurring to sell energy into the market: they 
contend that redispatch costs are the net cost incurred by the 
transmission provider, e.g., the difference between the costs of 
ramping up and ramping down resources. EPSA and AWEA also state that 
there would be no competitive concerns over the posting of this 
information from third party suppliers because the suppliers names need 
not be used.
    1144. Some commenters do not believe that making certain 
information publicly available will result in confidential information 
disclosure.\700\ PPL states that while confidentiality concerns must be 
considered, the nature and type of information that is publicly 
provided may be structured so as to alleviate or minimize such 
concerns. PPL argues that rather than posting specific generator cost 
information the all-in price for redispatch may be posted instead. BP 
Energy argues that posting redispatch prices at specified locations 
reveals the economic value of adding transmission/generation at those 
locations, but does not reveal the production cost associated with 
specific generation resources. BP Energy states that hourly redispatch 
costs should be posted for all ``significant congested interfaces'' 
within a transmission provider's control area and for all interfaces at 
control area boundaries. PGP asserts that transmission providers with 
OATTs should post any available information on hourly redispatch 
costs.\701\ PGP and PPL argue, however, that there should be an 
appropriate lag in the disclosure of actual redispatch costs in order 
to address confidentiality concerns. Williams states that increased 
transparency and proper monitoring are immediate, real solutions to 
``issues'' with the posting of the cost of redispatch. Williams asserts 
that those customers requesting redispatch should be provided the cost 
differential between the original dispatch and the redispatch and that 
post audit redispatch data and system models can be made available 
(after the expiration of a non-disclosure period) to provide market 
certainty of least cost redispatch and appropriate bid selection.
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    \700\ E.g., EPSA and AWEA Supplemental, BP Energy Supplemental, 
and California Commission Supplemental.
    \701\ PGP asserts that the transmission provider should be 
required to post redispatch information by event and by entity to 
address concerns about anticompetitive behavior.
---------------------------------------------------------------------------

    1145. PGP states that the redispatch option should be available 
irrespective of time frame, but must recognize the limited ability of 
the transmission provider to identify likely redispatch costs further 
out in time. Thus, PGP argues, posting redispatch costs in areas 
without organized markets should focus initially on real-time 
reliability redispatch, later expanding to longer time frames. PGP 
asserts that redispatch should be undertaken only when firm bids are 
available and the transmission customer has accepted responsibility for 
redispatch costs, which should be based on just and reasonable prices 
and must be known with a degree of certainty. PGP adds that the 
transmission provider should establish protocols that support firm 
bids, which would be published and, if accepted, result in binding 
obligations on the part of the bidders. PGP argues that it is 
reasonable for transmission providers to post real-time bids on 
constrained paths that are otherwise subject to curtailments to ensure 
compliance with reliability criteria. PGP contends that postings should 
take place on the transmission providers' OASIS and that all 
information should be retained by the transmission provider. PGP 
submits that redispatch bids should be explicitly added to the 
Commission's Electric Quarterly Reports filing requirements if not 
already required.
    1146. Constellation argues that the Commission should require each 
transmission provider to post two values to the market on its OASIS 
site, in order to enhance transparency: historical costs of redispatch 
at certain specified flowgates (perhaps those most congested 
historically) and real-time redispatch costs at the same flowgates. 
Constellation submits that each transmission provider engages in 
redispatch and thus can readily ascertain the cost of redispatch at 
various locations. Constellation argues that posting such costs will 
enable transmission customers to more accurately assess the potential 
costs of redispatch prior to deciding to incur redispatch costs. 
Constellation adds that the customer receiving redispatch should be 
obligated to pay the actual costs of redispatch, regardless of the 
costs reflected in the postings, which, Constellation contends, should 
reflect the transmission provider's most accurate and up-to-date 
information.
    1147. Williams believes that Transparent Dispatch Advocates' 
redispatch proposal offers a partial remedy to transmission congestion 
caused by insufficient infrastructure and undue discrimination. 
Williams proposes that affiliate and third-party generators submit 
either a pre-established rate structure or formulary pricing 
methodology prior to the provision of redispatch service. Williams 
states the primary implementation impediment to greater transparency of 
redispatch cost information is the accuracy and availability of 
redispatch costs.
    1148. BP Energy submits that posting the costs of redispatch is not 
the same as posting operational cost curves of specific generating 
units. BP Energy adds that, given the availability of redispatch costs, 
there is no reason to post the differential in unit-specific costs as a 
supplement to marginal prices posted at significant locations 
throughout the control area. PGP states that there is no need to 
establish markets to provide real-time redispatch. Rather, PGP asserts 
that limited protocols can be established for specific locations or 
types of congestion that may be directly relieved via redispatch. PGP 
believes that the Commission should avoid establishing detailed rules 
governing redispatch protocols, but rather should permit regional 
practices to be developed that result in ``just and reasonable'' 
charges for redispatch service.
    1149. In its reply comments, Southern states that requiring 
vertically integrated utilities to post their real-time marginal costs 
of electricity would be discriminatory and violate the Trade Secrets 
Act.\702\ Southern states that RTOs do not make public the marginal 
costs of the utilities participating in their markets, thus requiring 
other transmission providers to do so would be discriminatory. Southern 
states that marginal costs information is commercial or financial 
information protected by federal statute that if released would put it 
at a competitive disadvantage and harm its customers by allowing 
competing generators to price their power just below the published 
marginal costs.
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    \702\ 18 U.S.C. 1905.
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    1150. Several parties assert that the TDA proposal would require 
the posting of vertically integrated utilities' generation costs and 
thus would provide competitors and buyers with commercially-sensitive 
information.\703\

[[Page 12414]]

Many of these parties assert that posting a utility's incremental costs 
publicizes the price at which the utility elects to operate resources 
rather than purchase from a third-party.\704\ EEI and South Carolina 
E&G assert that making this information public may adversely affect 
competition and markets. Duke argues that having the transmission 
provider post daily and hourly generator costs assigns it 
responsibilities that are beyond the typical transmission function. 
Duke urges the Commission to consider voluntary alternatives to 
resource-specific cost information that would divulge competitively-
sensitive data. SEARUC argues that any incremental transparency 
improvements not be implemented in such a manner as to make 
competitively sensitive information available to the public on an 
inconsistent basis. Nevada Companies assert that the requirement to 
make such information publicly available to the transmission provider 
would have to be imposed upon all generators, including independent 
power producers, so that such information would lose the value it 
derives from not being publicly known.
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    \703\ E.g., Entergy Supplemental, Community Power Alliance 
Supplemental, Progress Energy and MidAmerican Supplemental, Southern 
Supplemental, Southwest Utilities Supplemental, Nevada Companies 
Supplemental, OG&E Supplemental, Florida Commission Supplemental, 
PPL Supplemental, Ameren Supplemental, North Carolina Commission 
Supplemental, and SEARUC Supplemental.
    \704\ E.g., Entergy Supplemental, Community Power Alliance 
Supplemental, Southern Supplemental, Duke Supplemental and South 
Carolina E&G Supplemental.
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    1151. Entergy argues that the Commission is statutorily prohibited 
from requiring the disclosure of information that undermines fair 
competition under the electric market transparency provisions in 
sections 220(b)(1) and (2) of the FPA.\705\ South Carolina E&G submits 
that the TDA proposal is inconsistent with this provision of the FPA. 
Southern further contends that mandating that transmission providers 
post and offer their generation on an at-cost basis, while allowing 
third party generators to submit bid prices would also be 
discriminatory. TAPS asserts that the proposed real-time disclosure of 
bid and cost information runs contrary to the Commission's policy of a 
6-month delay for release of bid information.
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    \705\ Entergy refers to the following language:
    (1) The Commission shall exempt from disclosure information the 
Commission determines would, if disclosed, be detrimental to the 
operation of an effective market * * *; and (2) [i]n determining the 
information to be made available under this section and the time to 
make the information available, the Commission shall seek to ensure 
that consumers and competitive markets are protected from adverse 
effects of potential collusion and other anticompetitive behaviors 
that can be facilitated by untimely public disclosure of 
transaction-specific information.
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    1152. NRECA asserts that the Transparent Dispatch Advocates fail to 
explain why transmission providers coordinating with third parties or 
neighboring transmission providers will not run afoul of anti-trust and 
collusion concerns that they are colluding in price setting; and how to 
verify providers are selecting the lowest bid unless they are required 
to post all third party generator bids as well as their own or their 
affiliates' cost of providing the service.
    1153. Ameren asserts that the existing OATT contains requirements 
for information to be posted by transmission providers, and does not 
believe that additional posting ought to be required. Ameren provides 
several recommendations were the Commission to adopt some or the entire 
TDA proposal. First, Ameren asserts that there are many different ways 
to estimate this cost and, in order to avoid the creation of competing 
methods for estimating redispatch costs, the Commission must consider 
and provide guidance on several questions.\706\ Second, so that 
transmission providers are not disadvantaged by this new obligation, 
Ameren urges the Commission to develop detailed requirements, including 
uniform timelines for posting, guidelines for estimating cost, and 
inclusion of all dispatchable generation in the relevant footprint. 
Ameren further argues that posting only the difference in costs would 
not address the potential for anticompetitive impacts. Finally, Ameren 
contends that the Commission may wish to consider implementing the 
changes only on an interim basis, then to observe whether there is any 
market benefit or any competitive harm as a result of the new 
requirements.
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    \706\ Ameren raises several questions to this effect: Does the 
transmission provider estimate cost effect across all market LMPs or 
just the congested points? Should the analysis take into account 
credits and adjustments to which some participants may be entitled? 
For what period should the transmission provider provide this 
estimate? For those transmission providers within a centralized 
market, how should they treat market costs such as losses or RSG 
(Revenue Sufficiency Guarantee in MISO) in calculating the 
redispatch cost?
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    1154. Duke believes that the posting of hourly redispatch costs 
would create near-constant off-OASIS communications between the 
transmission provider and merchant function employees, which, Duke 
asserts, would raise Standards of Conduct concerns.
    1155. NRECA argues that allocated costs may vary significantly 
regardless of methodology, which devalues the posting of costs. North 
Carolina Commission argues that publishing indicative redispatch costs 
in real time would require a determination as to how such costs are 
determined and whether each component of such costs are appropriately 
charged to customers.
Commission Determination
    1156. After careful consideration of the comments of the parties, 
we adopt a posting obligation that balances several competing 
considerations. First, we agree with Transparent Dispatch Advocates and 
supporting parties that the increased availability of information 
regarding redispatch costs can benefit consumers and increase the 
efficient use of the grid. Second, we are cognizant, however, that 
increased posting and reporting can impose cost burdens on transmission 
providers or otherwise harm market participants. For example, the 
reporting obligations can reveal confidential information that could 
harm market participants or increase the cost of serving native load 
customers. We also recognize that the posting or reporting obligation 
should be reasonably tailored to provide useful information to 
consumers without, at the same time, imposing unnecessary burdens on 
transmission providers, either in the frequency of the posting 
obligation or the scope of information provided.
    1157. In balancing these considerations, we will, as explained 
further below, adopt a requirement that transmission providers post 
certain redispatch cost information associated with the existing 
redispatch services that must be provided under the pro forma OATT. We 
find that providing customers with additional transparency and greater 
information regarding the cost of congestion, will facilitate their 
consideration of planning redispatch options which in turn will provide 
for more efficient use of the grid. We stress, however, that this 
posting requirement relates only to the existing redispatch services 
required under the pro forma OATT; it does not expand those service 
obligations. The primary purpose of the posting requirement is to 
ensure that all customers have access to this information, not only the 
customer receiving the redispatch service.
    1158. Moreover, the costs of the dynamic posting requirement 
proposed by Transparent Dispatch Advocates outweigh the benefits of 
such a requirement. Transparent Dispatch Advocates propose that the 
posting requirement be limited to specified congestion locations within 
and at the border of each transmission provider's system. Transparent 
Dispatch Advocates have not proposed ex ante criteria to determine 
which flowgates would require posting. In fact, some members of the 
Transparent Dispatch Advocates coalition would have the posting 
requirement apply to all transmission facilities, whether or not they 
were


[[Continued on page 12415]]


From the Federal Register Online via GPO Access [wais.access.gpo.gov]
]                         
 
[[pp. 12415-12464]] Preventing Undue Discrimination and Preference in Transmission 
Service

[[Continued from page 12414]]

[[Page 12415]]

congested and whether or not customers were seeking service over those 
facilities. Such an open-ended obligation to post costs for all 
facilities on a transmission provider's system would unnecessarily 
impose uncertainties and unbounded administrative costs on transmission 
providers. Additionally, depending on the frequency of publication and 
the method used to calculate the estimates, the publication of these 
estimates could reveal sensitive confidential information about 
transmission providers' generation costs that would likely harm 
existing markets and native loads. There is no simple formula for 
estimating the costs that would fully mask this confidential 
information and at the same time provide practical information about 
the costs of redispatch.
    1159. While we agree that transparency can benefit customers, 
Transparent Dispatch Advocates have not demonstrated the benefits of 
its posting requirement to customers seeking reliability or planning 
redispatch. Transparent Dispatch Advocates would have transmission 
providers frequently post an estimate of the cost of the next increment 
of redispatch. Customers seeking redispatch would not know the actual 
costs customers paid for redispatch. Nor would they be able to apply 
the estimate of cost to their transactions since most transactions 
would involve more than a single increment of redispatch service and 
there might be multiple redispatch transactions over a single 
transmission facility. Thus the estimate would only be of value to the 
marginal customer taking a small amount of redispatch service. 
Transmission providers would expend time and money determining the 
correct formula to use to estimate costs, collecting data for the 
inputs to the calculation and frequently posting estimates throughout 
each day that could have little or no correlation to the actual costs a 
transmission customer would pay for the redispatch service.
    1160. Third party participation in redispatch is one of the 
benefits Transparent Dispatch Advocates point to in support of its 
proposed posting requirement. Transparent Dispatch Advocates would have 
transmission providers act as the conduit for service from third party 
redispatch providers, collecting from customers and paying third party 
providers. As described above, we are allowing third party 
participation in planning redispatch without requiring transmission 
providers to act as bill collectors for third party redispatch 
providers or requiring coordination agreements among each transmission 
provider and all potential third party providers. This OASIS 
modification, described above, will provide third parties seeking to 
provide redispatch with the opportunity to frequently update the price 
of their offers as suggested by Transparent Dispatch Advocates.
    1161. We do believe, however, that information regarding actual 
redispatch costs should be made more widely available. Currently, when 
a transmission provider provides reliability or planning redispatch, 
the associated cost information is provided only to the customer 
receiving the service through its invoices. This ignores the fact that 
information regarding the cost of redispatch can benefit all customers 
and increase the efficient use of the grid. We therefore find that it 
is no longer just, reasonable and not unduly discriminatory to limit 
the provision of this information only to the individual customers 
receiving the service.
    1162. Accordingly, to provide greater availability of redispatch 
information, the Commission adopts certain additional posting 
requirements for transmission providers. Specifically, we direct each 
transmission provider to post on OASIS its monthly average cost of 
redispatch for each internal congested transmission facility or 
interface over which it provides redispatch service using planning 
redispatch or reliability redispatch under the pro forma OATT.\707\ 
Additionally, to demonstrate the range of redispatch costs each month, 
the Commission directs transmission providers to post a high and low 
redispatch cost for the month for each of these same transmission 
constraints. The transmission provider shall calculate the monthly 
average cost in $/MWh for each congested transmission facility by 
dividing monthly total redispatch costs (at the facility) by the total 
MWhs that would otherwise be curtailed (at the facility) in the month 
absent the redispatch.\708\ Transmission providers shall post internal 
constraint or interface data for the month if any planning redispatch 
or reliability redispatch is provided during the month, regardless of 
whether the transmission customer is required to reimburse the 
transmission provider for those exact costs. Thus, if the transmission 
customer pays for redispatch pursuant to a negotiated fixed rate, the 
transmission provider is required to post and calculate the monthly 
average redispatch costs and the high and low costs in the month even 
though the transmission provider will bill the customer the fixed rate. 
The same posting requirement applies if the customer is paying a 
monthly ``higher of'' rate.\709\ The transmission provider shall post 
this data on OASIS as soon as practical after the end of each month, 
but no later than when it sends invoices to transmission customers for 
redispatch-related services. We direct transmission providers to work 
in conjunction with NAESB to develop this new OASIS functionality and 
any necessary business practice standards.
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    \707\ The relevant reliability redispatch costs for posting 
purposes are those costs the transmission provider invoices network 
customers based on a load ratio share pursuant to section 33.3 of 
the pro forma OATT. The transmission provider need not perform new 
calculations of out-of-merit dispatch costs; rather the reliability 
redispatch invoices should form the basis of information from which 
the transmission provider determines monthly average reliability 
redispatch costs.
    \708\ For example, if reliability redispatch is used by the 
transmission provider to prevent curtailment of 10 MW of 
transmission provider or network customer load for 5 hours during 
the month across flowgate A, the transmission provider would use 50 
MWh as the divisor to determine the monthly average cost of 
redispatch for flowgate A.
    \709\ This is not a new calculation for the transmission 
provider because the transmission provider must determine the 
redispatch costs to know whether to charge higher of the embedded 
rate or the redispatch costs.
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    1163. There are several benefits to this posting requirement. First 
and foremost, it will give customers fairly current information 
regarding the cost of redispatch of the congested transmission 
facilities over which redispatch is provided, presumably some of the 
most congested facilities on transmission providers' systems. Second, 
it will limit posting only to those congested transmission facilities 
over which redispatch has actually been sought and granted and for 
which redispatch charges have been billed to customers. This addresses 
commenters' concerns about the posting of information that is valuable 
only hypothetically. Third, because we require the posting of average 
redispatch costs, not real-time redispatch costs or real-time system 
lambda or system incremental costs, it will not be harmful to native 
load or reveal otherwise competitively sensitive information.
    1164. Finally, in addition to the above posting requirement, we 
note that, as part of the transmission planning provisions adopted in 
this Final Rule, we are providing customers with a right to request a 
study of a defined number of congested transmission facilities on an 
annual basis. This will provide customers an additional opportunity to 
evaluate redispatch costs, including costs for those congested 
transmission facilities for which redispatch service has not been 
granted.

[[Page 12416]]

c. Other Requested Service Modifications
NOPR Proposal
    1165. In the NOPR, the Commission summarized requests for various 
new services made in response to the NOI. The Commission's proposed 
solutions evaluated solely the planning redispatch and conditional firm 
options.
Comments
    1166. Commenters make several suggestions with regard to additional 
services or modifications to existing services. Most popular among the 
suggested new services is long-term, seasonally-shaped firm point-to-
point service. Several commenters support this service for 
circumstances in which the transmission provider determines that the 
requested service is available during some, but not all, months of each 
year of a single or multiyear request.\710\ Commenters suggest that the 
long-term, seasonally-shaped service would provide an option for the 
transmission customer in lieu of costly upgrades without the 
operational difficulties of conditional firm service. In its reply 
comments, Powerex states that this product would have less of an 
adverse impact on existing firm rights holders. Northwest IOUs propose 
that the transmission customer pay the long-term point-to-point 
transmission service rate prorated for the portion of the year for 
which it receives the service. Public Power Council states that the 
transmission customer would be free to purchase non-firm or secondary 
service for the periods when firm service through the seasonally-shaped 
service was unavailable. Northwest IOUs argue that ``cream-skimming'' 
is avoided by processing only requests for long-term service and having 
the transmission provider determine the availability of the service.
---------------------------------------------------------------------------

    \710\ E.g., MidAmerican, Public Power Council, Northwest IOUs, 
Xcel, Powerex Reply, PPL, and Seattle Reply.
---------------------------------------------------------------------------

    1167. Powerex supports the implementation of a long-term non-firm 
point-to-point service. Tacoma believes priority non-firm or partial 
firm transmission services are alternatives to planning redispatch. 
Entegra proposes an additional service that would allow the customer, 
in the event of a constraint, to agree to either pay for redispatch or 
have its service curtailed. In contrast to these request for new 
services, TranServ states that simplified services and a reduction in 
the number of services would increase the transparency and fluidity of 
electricity trading.
    1168. MidAmerican urges the Commission to allow for dynamic 
scheduling service between control areas on a case-by-case basis, by 
including and pricing the service in the service agreement. MidAmerican 
states that this service would be similar to point-to-point service, 
but would allow the transmission customer to dynamically monitor its 
loads in neighboring control areas and dispatch its own remote resource 
to meet the load fluctuations in load pockets served by other 
transmission providers. MidAmerican further states that this new 
service is necessary in the Western Interconnection because neither 
point-to-point nor network service meets the needs of loads that are 
not confined to a single geographic area served by a single 
transmission provider.
    1169. Barrick states that the Commission should require 
transmission providers to confirm the availability of secondary service 
for network customers on a monthly or quarterly basis so that network 
customers can plan ahead for the use of secondary service. In its reply 
comments, Seattle supports the development of short-term redispatch 
service, currently under discussion for provision in the Pacific 
Northwest. TranServ requests that the Commission clarify whether 
sequential reservation of 12 consecutive months of monthly firm service 
is long-term service. TranServ requests that the Commission direct the 
development of business practices by NAESB to allow customers to 
designate minimum term and capacity for partial interim service, 
similar to the practice employed by Bonneville.
Commission Determination
    1170. The Commission rejects the requests to order new services or 
modifications to existing services suggested by commenters. We believe 
that the modifications to point-to-point transmission service adopted 
herein best address the issues raised by these requests. The planning 
redispatch and conditional firm options provide a means of remedying 
undue discrimination, and increasing transparency and access to the 
grid by point-to-point customers. We note that there is considerable 
overlap between these options and the new services suggested by 
commenters. However, we find that the introduction of the requested new 
services may create greater complexities than those present in the 
planning redispatch and conditional firm options. For example, several 
commenters propose a long-term seasonally shaped firm point-to-point 
service as a superior option to the conditional firm service. However, 
requestors have not adequately addressed concerns about the service, 
including the potential for hoarding transmission and the reliability 
issues related to evaluating the availability of the service or 
granting the service over many years. A seasonally shaped service could 
exacerbate the lumpiness of transmission investment by preventing 
customers willing to pay for transmission upgrades from obtaining all 
twelve months of service. While we will not reduce the number of 
services required as suggested by TranServ, the Commission must limit 
the number of new services adopted and modifications to existing 
services to a reasonable number that transmission providers can 
reliably implement. For these reasons, we decline to adopt any 
additional proposals or modifications to firm point-to-point service 
beyond those directed above in this Final Rule. Of course, transmission 
providers remain free to voluntarily propose additional services that 
are consistent with or superior to the pro forma OATT, as modified by 
this Final Rule.
    1171. The Commission rejects the request to adopt long-term non-
firm service because there is no indication that customers would find 
such a service useful and it would be inconsistent with the policy in 
the pro forma OATT that values firm service over non-firm service.
    1172. MidAmerican requests that the Commission allow a point-to-
point service that would let a transmission customer monitor its load 
and dispatch its remote resources to meet load fluctuations. In Order 
No. 888-A, the Commission clarified that this type of dynamic 
scheduling was not mandated Order No. 888, but that nothing in Order 
No. 888 precludes a transmission provider from offering it as a 
separate service.\711\ Thus, MidAmerican may propose such a service 
pursuant to an FPA section 205 filing with the Commission, and we will 
consider it, as we would any new service proposal, on a fact-specific, 
case-by-case basis.
---------------------------------------------------------------------------

    \711\ Order No. 888-A at 30,235-36.
---------------------------------------------------------------------------

    1173. Barrick requests that the Commission require the confirmation 
of the availability of secondary service for network customers on a 
monthly or quarterly basis so that network customers can plan ahead for 
the use of secondary service. As we stated in the NOPR, secondary 
network service refers to transmission service for network customers 
from resources other than designated network resources and is provided 
on an ``as available'' basis. Since the secondary service is provided

[[Page 12417]]

on an as available basis, Barrick's request seeks to allow secondary 
network service to pre-empt firm uses of the system, such as short-term 
firm point-to-point service, for what is a less than firm service. 
Barrick has not clearly articulated why this proposal is necessary to 
prevent the exercise of undue discrimination or why service from 
designated network resources would not meet its need for firmer 
secondary service. Thus, we reject Barrick's request.
    1174. With regard to Seattle's support for redispatch being 
developed in the Pacific Northwest, we believe that this type of 
redispatch shares many of the attributes of the Transparent Dispatch 
Advocates proposal rejected above. Although we acknowledge that market 
mechanisms that provide hour-ahead or real-time redispatch for all 
transmission customers can provide benefits to customers and efficient 
use of the transmission grid, for the reasons stated in the prior 
section, we will not require in this Final Rule that all transmission 
providers implement such market mechanisms. We note that nothing 
prevents the Commission from reviewing proposals for such market 
mechanisms on a case-by-case basis. We note that the conditional firm 
and planning redispatch options adopted in this Final Rule will provide 
some of the flexibility Entegra seeks. Customers taking service under 
these options will be able to choose, when executing the service 
agreement, between curtailment and redispatch.
    1175. Also, the Commission clarifies for TransServ that twelve 
months of consecutive monthly firm service, where the term of any 
particular monthly service agreement is for less than a year, is not 
long-term service.\712\ The Commission rejects TranServ's request that 
NAESB develop particular business practices regarding partial interim 
service as TranServ has not shown a need for such a requirement.
---------------------------------------------------------------------------

    \712\ See pro forma OATT section 1.18 (defining long-term firm 
point-to-point transmission service as service with a term of one 
year or more).
---------------------------------------------------------------------------

    1176. The Commission continues to encourage transmission providers 
to propose other services that are consistent with or superior to the 
pro forma OATT that meet customers' needs and make more efficient use 
of the transmission system. We will not mandate that transmission 
providers provide any service other than the services set forth in the 
pro forma OATT since they may not be applicable in all circumstances. 
However, if transmission providers seek to provide any modifications to 
the required pro forma OATT services or new services, they may submit 
an FPA section 205 filing to propose such modifications and the 
Commission will evaluate such proposals on a case-by-case basis.
2. Hourly Firm Service
NOPR Proposal
    1177. In the NOPR, the Commission proposed to add point-to-point 
hourly firm service to the pro forma OATT. The Commission stated its 
belief that adding this service would eliminate a barrier to the 
development of markets and thereby decrease opportunities for undue 
discrimination. The Commission further stated that the concerns 
expressed in Order No. 888 regarding the unduly discriminatory effects 
of hourly firm service have proven unfounded. Consistent with our 
precedent, the Commission proposed to use the ``IES Method'' to price 
hourly firm service and apply different pricing based on whether the 
service is taken during peak or off-peak hours.\713\ The Commission 
explained that this pricing method would ensure that hourly firm 
customers pay a fair share of the costs of the transmission system.
---------------------------------------------------------------------------

    \713\ See IES Utilities, Inc., 81 FERC ] 61,187 at 61,833-34 
(1997), reh'g denied, 82 FERC ] 61,089, aff'd on other grounds sub 
nom. Wisconsin Public Power Inc. v. FERC, No. 98-61,089, 1999 U.S. 
App. LEXIS 3998 (Feb. 23, 1999) (unpublished opinion) (adopting peak 
and off-peak pricing to hourly non-firm transmission service); see 
also New York State Electric & Gas Corp., 92 FERC ] 61,169 at 
61,593-94 (2000) (approving application of the IES Method for time-
differentiated hourly non-firm rate design), order on reh'g, 100 
FERC ] 61,021 (2002).
---------------------------------------------------------------------------

    1178. The Commission proposed allowing transmission customers to 
batch requests and schedules for hourly firm service that will be 
provided within the same calendar day. Schedules for firm hourly 
service, like all other firm schedules, would be due by 10 a.m. the day 
before the service is to commence. The Commission also proposed that, 
consistent with other durations of service, the confirmation period for 
hourly firm service specified in section 13.2 of the pro forma OATT 
would allow longer term requests for service to preempt shorter hourly 
firm requests for service until one hour before the commencement of 
hourly firm service.
Comments
    1179. Commenters are split on whether to require hourly firm 
service. Varied interests express some support of the requirement, 
while mostly IOUs, cooperatives, and public power providers oppose the 
requirement. Supporters, which include several entities that currently 
offer hourly firm service, foresee increased use of transmission 
facilities and market efficiencies. Chief among the arguments cited by 
those objecting to the required service is the potential adverse effect 
on those serving native load or taking longer term service due to 
increased frequency of curtailments. Other objections to the required 
service include reliability concerns and the unjustified curtailment 
priority that would be afforded to short-term customers that have not 
financially committed to long-term grid service. To the extent hourly 
firm service is required, commenters generally support use of the IES 
Method for pricing, although some commenters ask the Commission to 
allow pricing to vary according to regional practice. As for batching 
and scheduling, many parties request that the Commission clarify 
specific details of each of these proposals to prevent future disputes.

Mandatory Hourly Firm

    1180. Various commenters state their general support of, or non-
opposition to, the proposal to require hourly firm service.\714\ Among 
those who support it, several state that they already supply the 
service themselves.\715\ Such commenters argue that hourly firm service 
would decrease opportunities for undue discrimination, enhance the 
customer's ability to participate in the real-time energy markets, 
encourage trade and marketing liquidity, increase firm uses of the 
grid, allow greater customer choice, increase efficiencies in wholesale 
markets, and help maximize use of existing transmission 
facilities.\716\ WAPA states that its experience indicates that the 
current provisions for preempting shorter-term transmission service 
with longer-term service, as codified in OATT section 13.2, adequately 
serve to discourage speculative hoarding of hourly capacity.
---------------------------------------------------------------------------

    \714\ E.g., Ameren, Arkansas Commission, Bonneville, BP Energy, 
Constellation, FirstEnergy, MidAmerican, MISO/PJM States, Morgan 
Stanley, Nevada Companies, Newmont Mining, NorthWestern, Pinnacle, 
PPL, CREPC, and Suez Energy NA.
    \715\ E.g., Bonneville, Pinnacle (noting Arizona Public Service 
Company's adoption of the service), PNM-TNMP, and WAPA (in its 
Desert-Southwest region).
    \716\ E.g., Arkansas Commission, BP Energy, FirstEnergy, Morgan 
Stanley, Pinnacle, PNM-TNMP, and PPL.
---------------------------------------------------------------------------

    1181. Numerous commenters objecting to the proposed service cite 
the effect of curtailment on customers taking network or longer term 
service, especially in the service of native load.\717\ Specifically, 
they argue that the inclusion of an additional short-term firm service 
would increase the

[[Page 12418]]

likelihood that longer-term service would be curtailed and degrade the 
reliability of service to native load, since all firm service (point-
to-point and network), regardless of duration, would be curtailed pro 
rata. Objecting commenters argue that such a result is unfair to 
customers that have made a long-term commitment to taking service, 
including expanding the system;\718\ inconsistent with FPA section 
217(b)(4), which requires the Commission to promote the availability of 
transmission for native load service;\719\ and inconsistent with the 
Commission's commitment in the NOPR to maintain existing native load 
protections.\720\
---------------------------------------------------------------------------

    \717\ e.g., APPA, Duke, EEI, MISO, and Southern.
    \718\ e.g., MISO and Southern.
    \719\ e.g., APPA, NRECA, and Southern.
    \720\ e.g., Southern.
---------------------------------------------------------------------------

    1182. Although transmission providers plan for their native load 
needs when calculating ATC, Imperial argues that they cannot always 
accurately predict these needs. Imperial states that transmission 
providers have been able to rely on the release of unscheduled capacity 
when balancing their schedules to meet fluctuating needs (such as 
during heat waves). In view of the decline in transmission 
infrastructure relative to load throughout the country, NRECA objects 
to the reduction in ATC that would result from dedicating transmission 
capacity to hourly firm service. NRECA argues that designated network 
resources may no longer be regarded as such because firm transmission 
to support them is not available on constrained transmission systems 
(i.e., most transmission systems). If hourly firm service is to be 
required, Imperial proposes also requiring transmission providers to 
make available all but 20 percent of non-reserved transmission as firm 
so that non-firm service will be available for the use of network 
customers and native load providers.
    1183. Southern argues that the provision of hourly firm service 
would require the transmission provider to predict the exact hour on 
which expected peak conditions will occur in order to be able to post 
the amount of hourly firm service that will be available for each hour 
of a given day. If system conditions then change, Southern continues, 
reliability could be placed in jeopardy, which would result in long-
term service being curtailed. Southern also argues that the provision 
of this hourly firm service would complicate real-time operations and 
negatively impact reliability since, if curtailments on a specific path 
prove necessary, it is more difficult to curtail a large number of 
transactions on a very short-term notice.
    1184. Many argue that the justifications provided in Order No. 888 
for not requiring this service remain valid, such as the argument that 
the service will invite cream skimming.\721\ MISO sees a likelihood 
that an ``hourly priority war'' would ensue on constrained interfaces 
between firm and non-firm requests and that resolving these conflicts 
would be time consuming and stretch its resources. MISO argues that an 
hourly firm product would degrade the value of non-firm service and 
that the introduction of this new, logistically challenging service, 
further compounds the task of rooting out undue discrimination. MISO 
argues that the proposed mandatory introduction of this service will 
have serious adverse implications for many functioning RTOs. MISO 
contends that hourly firm service should remain strictly optional for 
RTOs arguing that weighing the pros and cons of this new service can 
best be addressed within each RTO's stakeholder process.
---------------------------------------------------------------------------

    \721\ e.g., LDWP, MISO, Southern, TAPS, TDU Systems.
---------------------------------------------------------------------------

    1185. TVA argues that hourly firm reservations would likely end up 
being bumped by requests for longer service (such as daily firm), 
consuming valuable transmission provider staff time and resources on 
administrative tasks with no real benefit and potentially significant 
costs. Similarly, Southern argues that hourly firm service would likely 
result in the transmission provider receiving less revenues (because 
fewer customers would take daily firm service) while incurring higher 
costs (due to implementation complexities), the net effect of which 
would raise OATT charges.
    1186. Among commenters offering qualified support for mandatory 
hourly firm service,\722\ ELCON and FirstEnergy ask the Commission to 
monitor the use of this service and to reconsider its continued need if 
it impairs the quality or availability of long-term firm services. 
Powerex argues that hourly firm point-to-point service could increase 
opportunities for undue discrimination unless the conditions under 
which the non-firm transmission service can be interrupted are 
clarified. South Carolina E&G argues that the Commission should give 
the service a lower curtailment priority than any longer term firm 
service (citing as support the lower reservation priority for short 
term firm service in section 13.2(iii)) and adopt the proposal to 
require that hourly firm service be scheduled the day before service is 
to commence.
---------------------------------------------------------------------------

    \722\ E.g., ELCON, FirstEnergy, Powerex, and South Carolina E&G.
---------------------------------------------------------------------------

    1187. Duke explains that the current 10 a.m. deadline for firm 
schedules need not be enforced in the absence of hourly firm service 
and often is not enforced (with transmission providers acting on a 
comparable basis in waiving the deadline). Thus Duke identifies as a 
drawback to the addition of hourly firm service the likelihood that 
transmission providers will enforce the 10 a.m. deadline and thereby 
reduce existing flexibility.
    1188. Some commenters objecting to the new service requirement 
argue that, if the Commission retains this service, certain 
modifications should be made.\723\ These modifications include: giving 
the service a lower curtailment priority, pricing it at a premium above 
the IES methodology, requiring that the firm hourly postings be based 
upon the daily firm ATC (with the additional capacity that might be 
available in ``shoulder'' hours of the day being made available only as 
hourly non-firm), and giving secondary network service a higher 
priority over hourly firm. Duke argues on reply that, if the Commission 
determines that hourly firm service should be required, a technical 
conference should be held to develop appropriate, workable tariff 
language in light of the implementation issues raised by commenters.
---------------------------------------------------------------------------

    \723\ e.g., APPA, NRECA, Southern, and TAPS.
---------------------------------------------------------------------------

Voluntary Hourly Firm Service
    1189. Various commenters ask that hourly firm service not be 
required and, instead, continue to be allowed on a voluntary basis by 
willing transmission providers.\724\ These commenters generally argue 
that the service's effect on reliability, curtailment priority, longer 
term service, transmission expansion, and the ability to serve native 
load counsels against mandating the service. NRECA argues that hourly 
firm service would unduly interfere with the ability of network 
customers (and the transmission provider on behalf of its native load 
customers) to use secondary network service, which is offered only on 
an ``as available'' basis and therefore would have a lower reservation 
and curtailment priority than hourly firm service.
---------------------------------------------------------------------------

    \724\ E.g., APPA, Duke, East Texas Cooperatives, EEI, Imperial, 
LDWP, LPPC, Northwest IOUs, NRECA, PJM, Southern, and TDU Systems.
---------------------------------------------------------------------------

    1190. NRECA notes that the Western Interconnection, where hourly 
firm service has proven to be a useful product, differs from the 
Eastern

[[Page 12419]]

Interconnection in a number of respects, in particular, by virtue of 
extensive reliance on point-to-point service by LSEs to serve native 
load. For this reason, NRECA continues, public utility transmission 
providers should only be allowed to voluntarily offer hourly firm 
transmission service if the service is available equally to all 
transmission customers and the new service does not undermine the 
quality of, and flexibility of, the transmission provider's existing 
network service (including secondary network service) and point-to-
point transmission service. NRECA also requests that the Commission 
clarify that the only circumstance in which hourly firm service could 
be offered would be if daily service were not being fully used.
    1191. Northwest IOUs suggest that the Commission develop 
standardized point-to-point hourly firm service provisions for the 
voluntary provision of this service by those transmission providers 
that determine such service would be appropriate to offer on their 
systems. TDU Systems argue that the Commission should condition 
approval of an hourly service on requirements that a lower curtailment 
priority is established for hourly firm service than other firm 
services, including secondary network service; and, it may only be sold 
in the hour preceding the start of service to ensure that hourly 
service would not impede the provision of service to other firm 
services, including secondary network service. In light of comments, 
Powerex abandoned its initial conditional support for the proposal to 
support voluntary provision of the service.
Alternative Proposals
    1192. PJM recommends adding a service similar to PJM's non-firm 
willing to pay congestion (NF-WPC) service which may serve the same 
purpose as, and be an alternative to, hourly firm service. NF-WPC 
service would be evaluated for ATC and curtailed by transmission 
customers if the effective price of congestion were too high. Thus, NF-
WPC service will result in a reduction in all TLR curtailments. To add 
this service to the OATT, PJM explains, all transmission providers with 
control over dispatch would have to provide a transparent means for 
redispatch to clear congestion and maintain reliability on either side 
of a border.
    1193. Xcel argues that it is possible that hourly firm service 
would not be needed if the existing OATT were clarified as it relates 
to priority of non-firm service. Xcel proposes that the Commission 
could clarify that non-firm service is not interruptible during the 
hour due to other non-reliability driven requests, but rather at the 
start of the next hour, provided sufficient scheduling notice is given. 
Xcel continues that this clarification would also stipulate that non-
firm service (and all other types of service) may be curtailed without 
notice at any time for reliability reasons.
Pricing
    1194. Many commenters support the Commission's proposal to use the 
IES Method to price hourly firm service.\725\ Several commenters 
suggest that the Commission allow transmission providers to define 
their own peak and off-peak hours under the IES methodology, with some 
suggesting that it should be allowed as a regional variation to account 
for the different peak times in regions such as the WECC.\726\ East 
Texas Cooperatives asks the Commission to require that revenue from 
hourly firm service be applied as a credit to network service revenue 
requirements like other point-to-point services. PGP supports the IES 
Method, but recommends that the Commission be open to other approaches.
---------------------------------------------------------------------------

    \725\ E.g., Ameren, EEI, NorthWestern, PGP, and PNM-TNMP.
    \726\ E.g., Northwest IOUs, Public Power Council, and CREPC.
---------------------------------------------------------------------------

Reservations, Scheduling, Preemption and Right of First Refusal, 
Batching
    1195. Some commenters support the proposed reservation or 
scheduling requirements for hourly firm service.\727\ Others commenters 
express concerns regarding, or object to, this aspect of the hourly 
firm proposal.\728\ As discussed below, several commenters suggest 
modifications to different components of the proposal.
---------------------------------------------------------------------------

    \727\ E.g., Ameren, Duke, NorthWestern, PNM-TNMP, and WAPA.
    \728\ E.g., Bonneville, Southern, and TVA.
---------------------------------------------------------------------------

    1196. Some commenters state that hourly firm should be a means of 
selling unused capacity in hours not purchased for longer-term 
transactions and, as a result, it will be important to establish a 
sequencing for sales that accomplishes this so that cream skimming does 
not occur.\729\ Tacoma recommends that the Commission establish hourly 
firm service as the lowest priority in the service request queue. 
Tacoma also suggests that the Commission limit the purchase of hourly 
firm in such a way as to assure that the purchase is not an attempt to 
manipulate a market, such as making the service available only to LSEs, 
which Tacoma states would ensure that capacity is utilized to meet a 
real market need.
---------------------------------------------------------------------------

    \729\ E.g., Public Power Council and Tacoma.
---------------------------------------------------------------------------

    1197. SPP urges the Commission to apply the same reservation 
deadline to hourly firm as used for daily firm service in order to make 
the service easier to administer (and limit the impact on non-firm 
service). Bonneville also suggests that reservation timing requirements 
be the same as those for hourly non-firm service and, with respect to 
competing reservations, hourly firm service be classified as Short-Term 
Firm. TVA notes that although the scheduling deadline for service is 10 
a.m. the day before service is to commence, the NOPR also states that 
longer-term requests may preempt shorter requests until one hour before 
the commencement of service. TVA sees an inconsistency in that it 
appears firm service can be reserved and scheduled after 10 a.m. on the 
day prior all the way up until one hour before the service is to 
commence. TVA argues that no service that could preempt the hourly 
service should be sold after the 10 a.m. day-ahead deadline, and 
requests that the Commission clarify this ambiguity.
    1198. If the Commission requires hourly firm service, Progress 
Energy requests that it be offered on a day-ahead basis only, as 
proposed in the NOPR, to allow transmission providers sufficient time 
to analyze the reliability impacts of the requested hourly firm 
service. Nevada Companies recommend that any hourly firm service have 
the same scheduling deadlines as daily firm and that customers not be 
permitted to submit hourly firm schedules throughout the day. In Nevada 
Companies' view, this would enable transmission customers to schedule 
firm transmission only for the part of the day that it is needed while, 
at the same time, transmission providers would not be overwhelmed with 
the task of administering the reservation process.
    1199. Some recommend that scheduling conform to the existing 
scheduling practices in each region, such as in the WECC.\730\ For its 
part, MISO argues that the proposed scheduling deadline for hourly firm 
service is before the deadline for the submittal of the MISO daily firm 
service, which would require a substantial change to its Energy Markets 
Tariff, firm service evaluation process, and other firm and non-firm 
timing requirements. MISO argues that this could adversely affect the 
current Joint and Common Market Alignment of Business Practices 
initiative with PJM. Public Power Council offers

[[Page 12420]]

Bonneville's scheduling timeline as an example in which longer blocks 
get priority over the shorter blocks within the 10 a.m. to 2 p.m. 
preschedule-day reservation period, and hourly firm is bought within 
the day at the same times as hourly non-firm transmission (i.e., up to 
20 minutes prior to the delivery hour).
---------------------------------------------------------------------------

    \730\ E.g., MidAmerican, Northwest IOUs, Public Power Council, 
and CREPC.
---------------------------------------------------------------------------

    1200. Occidental requests that the Commission change the 10 a.m. 
day-before scheduling timeline to be as close to real-time as possible. 
It contends that under the pro forma OATT, merchant generators still 
will be relegated to making non-firm reservations and sales, because 
the 10 a.m. prior day firm service scheduling timeline would cause them 
to incur expensive reservations to the sales point, but not be able to 
have the transaction tagged with source and sink (as required under the 
NERC tagging procedure), before consummation of the firm hourly 
transaction. Occidental further contends that the change in scheduling 
timeline will not be problematic to the transmission providers, 
particularly if the transaction takes place in a single control area. 
Occidental also argues that the OATT benefits the transmission 
provider, which can favor its own or affiliated generation when 
balancing with other control areas and dispatching in real time.
    1201. Bonneville, which has provided hourly firm service since 
2002, takes issue with the fact that the Commission proposes that the 
service would become unconditional only one hour before the 
commencement of delivery. Bonneville argues that its own timeline, 
under which hourly firm service becomes unconditional at the close of 
the preschedule window for the day of delivery (currently, at 2 p.m. of 
the preschedule day or as soon as practicable thereafter), is superior 
and should be adopted by the Commission. Bonneville explains that, in 
its experience, customers place great value on having unconditional 
firm rights before they reach the real-time scheduling window, and an 
hour leaves little or no time to make alternative arrangements if the 
hourly firm reservation is preempted. Finally, Bonneville foresees 
potential reliability effects if a customer using hourly firm 
transmission for operating reserves is preempted the hour before 
delivery, and is unable to make transmission arrangements elsewhere.
    1202. Ameren argues that a later request for hourly firm service 
should not be able to preempt an earlier request, even if it is for a 
greater number of hours. According to Ameren, this will provide 
certainty to users of this service since they will know they will not 
be bumped by other customers using the service.
    1203. Duke requests guidance on how long the hourly firm customer 
has to respond to a competing request. Since hourly firm could be 
preempted up to an hour before the schedule starts, Duke argues that in 
many cases there will not be 24 hours available and the scheduling 
deadline (of 10 a.m. of the day prior to commencement of such service) 
may have passed. For example, if a pre-confirmed, longer-term, 
competing request is received just prior to the deadline (one-hour 
prior to service commencing), Duke questions whether the transmission 
provider is required to offer the right of first refusal at all.
    1204. Joined by TranServ, Duke also requests that the Commission 
provide guidance on how to administer the right of first refusal when, 
for example, three different hourly customers have confirmed 
reservations on a constrained interface for different hours in a day 
and the transmission provider then receives a pre-confirmed request for 
daily service on the same path for the same day. Alternatives solutions 
for this scenario offered by Duke include offering the shorter-term 
customers simultaneous or consecutive opportunities to exercise the 
right of first refusal, prohibiting the preemption of multiple 
overlapping requests, or denying shorter term customers a right of 
first refusal. Duke recommends NAESB develop appropriate business 
practice standards after the Commission's decision on this issue.
    1205. With the NOPR's potential for adding more complexity with 
hourly firm service under similar conditions as other short-term firm 
services, TranServ requests that the Commission either eliminate the 
conditional nature of short-term firm point-to-point service under the 
OATT (and the reservation window would be set to not interfere with 
requests for daily firm service) or allow hourly firm service to be 
preempted without a right of first refusal.
    1206. Duke requests that, whether or not the Commission requires 
hourly firm service, the Commission clarify how the ``short-term rights 
of first refusal'' should be implemented in section 13.2(iii) of the 
OATT, since there already is some lack of clarity with regard to this 
right for daily, weekly, and monthly service.
    1207. Based on its experience, WAPA suggests that the Commission 
institute limits on the allowable time period in which customers may 
contact the transmission provider for the purpose of withdrawing an 
hourly firm request in order to avoid potential ``gaming'' issues that 
may arise from entities requesting transmission on a pre-scheduled 
basis and then asking for the request to be withdrawn during real-time. 
To simplify real-time administration of hourly firm service, WAPA 
suggests that the Commission explicitly include in the revised pro 
forma OATT a statement waiving the Order No. 638 displacement rules for 
hourly requests during the hour before the service is to commence.
    1208. Several commenters support the Commission's batching 
proposal.\731\ WAPA argues that the proposed limitation on batching 
hourly firm requests and schedules to within the same day would 
alleviate the workload issues associated with evaluating individual 
hourly firm reservations in order to identify conflicting schedules 
across congested paths.
---------------------------------------------------------------------------

    \731\ E.g., PGP, PNM-TNMP, and WAPA.
---------------------------------------------------------------------------

    1209. MidAmerican objects to the batching proposal, arguing that 
transmission requests should be evaluated in queue order and schedules 
linked to a specific OASIS request. MISO argues that the batching 
proposal may interfere with the established protocols for transmission 
service request processing. In MISO, for example, there is no interface 
for Available Share of Total Flowgate Capability, which would seem to 
suggest that batch processing could infringe on the various Commission-
approved seams agreements.
    1210. Some commenters offer modifications or request 
clarifications. Bonneville proposes that NAESB develop industry 
standards for defining and processing batched reservations and 
schedules. EEI argues that transmission providers who offer hourly firm 
service should permit their customers to batch multiple requests for 
service that have the same points of receipt and delivery; are for the 
same quantity of service, and are for the same day. Otherwise, EEI 
explains, batching will complicate the ability of the transmission 
provider to study requests for hourly service. NorthWestern explains 
that it cannot fully support the Commission's recommendation to allow 
``batching'' of requests without a more clear definition of what may be 
batched and a determination that requests of a longer increment preempt 
shorter increment requests (e.g., a request for daily service preempts 
a request for hourly service) regardless of how many hours are batched 
together.
    1211. TranServ states support for the ability to batch requests and 
schedules for multiple hours of firm service with

[[Page 12421]]

varying capacity over the hours. However, with respect to competing 
requests and the right of first refusal, TranServ suggests that the 
preempting request must be for a fixed capacity over the term of the 
request to be considered a competing request. According to TranServ, 
this would prevent potential gaming by a customer submitting a request 
for one extra hour at 1 MW to gain priority over another reservation.
Commission Determination
    1212. In light of the potential for market disruption and the 
scheduling complications that would arise from providing hourly firm 
service, we decline to adopt in the Final Rule the proposal to require 
transmission providers to offer hourly firm service. While there is 
some industry support for hourly firm service, we conclude that the 
downsides associated with requiring transmission providers to offer 
hourly firm service outweigh the benefits of the proposal due to the 
significant issues raised by commenters. Commenters opposing mandatory 
hourly service raise a number of legitimate concerns with respect to 
the service's potential to adversely affect reliability and create 
additional complexity and inefficiency in scheduling and administering 
the right of first refusal. We do not believe that the modifications 
suggested by commenters supporting the service adequately resolve these 
concerns. Given regional differences and varying system constraints, a 
solution that may be appropriate for resolving scheduling, reservation 
or other issues resulting from hourly firm service on one transmission 
system may not be appropriate for another transmission system. 
Moreover, even the commenters supporting the proposal do not 
demonstrate a clear need for an hourly firm service product. The 
Commission therefore concludes that requiring hourly firm service is 
not needed to address undue discrimination, the goal of this 
rulemaking.
    1213. To the extent they deem it appropriate, transmission 
providers will continue to have the option to propose offering hourly 
firm service in an FPA section 205 filing with the Commission. Because 
we are not adopting the mandatory hourly firm service proposal, we 
believe that the most serious concerns regarding scheduling short-term 
service and administering the right of first refusal are alleviated. We 
address scheduling and right of first refusal issues relating to 
existing services in section V.D.5.b.
3. Rollover Rights
    1214. Section 2.2 of the pro forma OATT allows existing firm 
transmission service customers--wholesale requirements and 
transmission-only customers with contracts of one year or more--the 
right to continue to take transmission service from the transmission 
provider when the customer's contract expires. The pro forma OATT 
provides that the transmission reservation priority is independent of 
whether the existing customer continues to purchase capacity and energy 
from the transmission provider or elects to purchase capacity from 
another supplier. This transmission reservation priority for existing 
firm transmission service customers, which is also referred to as a 
right of first refusal or a rollover right, is an ongoing right that 
currently may be exercised at the end of all firm contract terms of one 
year or longer. A transmission customer must give notice of whether it 
will exercise its right of first refusal 60 days before the expiration 
of its service agreement.
    1215. In Order No. 888, the Commission provided that, if a 
transmission customer subject to the rollover right selects a new power 
supplier that substantially changes the location or direction of its 
power flows, the customer's right to continue taking service from the 
transmission provider may be affected by transmission constraints 
associated with the change.\732\ The Commission also provided that a 
transmission provider may reserve existing capacity for retail native 
load and network load growth reasonably forecasted within the 
transmission provider's current planning horizon, but that any capacity 
so reserved must be posted on the transmission provider's OASIS and 
made available to others until the capacity is needed for the 
anticipated network or retail native load use.\733\ The Commission also 
has held that a transmission provider may restrict a right of first 
refusal based on pre-existing contracts that commence in the future if 
the transmission provider knows at the time of the execution of the 
original service agreement that ATC used to serve a customer will be 
available for only a particular time period, after which time it is 
already committed to another transmission customer under a previously 
confirmed transmission request.\734\ Once a transmission provider 
evaluates the impact on its system of serving a long-term firm 
transmission customer and grants the transmission customer existing 
capacity, the transmission provider must plan and operate its system 
with the expectation that it will continue to provide service to the 
transmission customer should the transmission customer exercise the 
right of first refusal. If constraints arise after a transmission 
provider enters into a long-term agreement with the transmission 
customer (and that agreement does not contain an allowed restriction on 
the transmission customer's right of first refusal), the obligation is 
on the transmission provider to either curtail service to all affected 
customers or build more capacity to relieve the constraint.\735\ A 
transmission provider is obligated to curtail service pursuant to its 
OATT or expand its system when its system becomes constrained such that 
it cannot satisfy existing transmission customers, including the 
exercise of their rollover rights, because it should have planned and 
operated its system with the expectation that each long-term firm 
transmission customer will exercise its rollover rights.\736\
---------------------------------------------------------------------------

    \732\ Order No. 888 at 31,665 n.176.
    \733\ Id. at 31,694.
    \734\ E.g., Southwest Power Pool, Inc., 109 FERC ] 61,041 at P 6 
(2004).
    \735\ Id. at P 9.
    \736\ Id.
---------------------------------------------------------------------------

    1216. If a transmission provider's transmission system cannot 
accommodate all of the requests for transmission service at the end of 
the contract term, the existing long-term transmission customer must 
agree to match the rate offered by the potential customer, up to the 
transmission provider's maximum rate, and to accept a contract term at 
least as long as that offered by the potential customer. However, a 
competitor's offer does not have to be ``substantially similar in all 
respects'' to the existing transmission customer's.\737\
---------------------------------------------------------------------------

    \737\ Idaho Power Co. v. FERC, 312 F.3d 454, 462 (D.C. Cir. 
2002).
---------------------------------------------------------------------------

NOPR Proposal
    1217. In the NOPR, the Commission proposed to revise the right of 
first refusal provision in the pro forma OATT to apply to firm 
wholesale requirements and transmission-only contracts that have a 
minimum term of five years, rather than the current minimum term of one 
year. In addition, a transmission customer under a rollover agreement 
would be required to provide notice of whether it intended to exercise 
its right of first refusal no less than one year prior to the 
expiration of its contract, rather than the current 60 days. The 
Commission proposed to maintain the requirement that an

[[Page 12422]]

existing transmission customer match competing offers as to term and 
rate. The Commission discussed whether native load restrictions should 
be reevaluated with each rollover and, if so, whether native load 
should then be required to compete with rollover customers for the 
capacity. The Commission also asked for comment on whether there is a 
sufficiently clear, consistent, and transparent method that could be 
implemented on a generic basis to address the need for a transmission 
provider to demonstrate its forecast of native load growth and its 
effect on capacity reserved by rollover customers. The rollover reforms 
were proposed to be effective as to new transmission contracts upon 
Commission acceptance of the transmission provider's coordinated and 
regional planning process required by the Final Rule, with existing 
rollover contracts becoming subject to the new rules on the first 
rollover date after the effective date of the revisions.
a. Five-Year Minimum Contract Term
Comments
    1218. Many commenters support the increase in the contract term 
eligible for a rollover right.\738\ These commenters support the 
increase to five years based largely on the Commission's rationale for 
proposing it, i.e., an increase to five years would encourage longer-
term use of the grid and assist in long-term planning. Many also point 
out that a longer minimum term reduces the universe of contracts 
transmission providers must assume will exist in perpetuity, thereby 
increasing certainty and reducing speculation. These commenters also 
argue that rollover reform will improve reliability and provide 
increased revenues to perform upgrades. Some also argue that this is 
consistent with the native load protections in new section 217 of the 
FPA.
---------------------------------------------------------------------------

    \738\ E.g., APPA, Barrick Reply, Bonneville, Community Power 
Alliance, Constellation, Dominion, Duke, EEI, Entegra, Entergy, 
E.ON, FirstEnergy, Great Northern, Imperial, Indianapolis Power 
Reply, LPPC, LDWP, MidAmerican, MISO, MISO Transmission Owners, 
Nevada Commission, Nevada Companies, North Carolina Commission 
Reply, Northwest IOUs, NorthWestern, NPPD, PGP, Pinnacle, PNM-TNMP, 
Progress Energy, Public Power Council, Sacramento, Salt River, Santa 
Clara, Seattle, South Carolina E&G, Southern, SPP, Tacoma, TAPS, 
TransServ, TVA, Utah Municipals, and Xcel. The Commission notes that 
several of these commenters have conditioned or qualified their 
support on the adoption of a number of modifications, which will be 
discussed below.
---------------------------------------------------------------------------

    1219. E.ON, for example, notes that system expansions may have been 
limited in the past because transmission providers did not want to 
commit resources to accommodate a service guaranteed for only one year, 
and Xcel and TVA note that the increase in term should encourage 
investment and expansion of the grid by providing improved certainty of 
cost recovery. EEI stresses that there is no single minimum rollover 
term that works for all parties, as power purchase contract terms vary 
and some state planning obligations require purchases for longer or 
fewer than five years, but that five years represents a reasonable 
balance. Southern emphasizes that the reforms should also improve 
reliability, promote the provision of service to native load 
transmission customers, and increase market efficiencies by releasing 
transmission capacity to the market. In its reply, Southern expresses 
its belief that the current policy of requiring transmission planners 
to assume that all agreements having a minimum term of one year will 
continue taking service in perpetuity threatens reliability. In 
Southern's view, this policy results in planning that is based on 
speculation and guesswork that can signal a need for inappropriate and 
expensive transmission upgrades and mask the need for appropriate 
expansion.
    1220. However, several modifications and clarifications were sought 
by some commenters before they could agree to an increase in the 
minimum term to five years. APPA, Sacramento, and TAPS contend that 
transmission customers making this long-term commitment should be 
permitted to change their designated resources and receipt points as 
their power supply needs change.\739\ APPA also asserts that 
transmission customers that agree to a five-year contract term should 
not be forced to compete with other transmission customers for firm 
capacity whenever their contracts come up for renewal. Without such 
assurances of continued service, APPA argues that the Commission's 
proposals would not comport with section 217 of the FPA.\740\
---------------------------------------------------------------------------

    \739\ See also TDU Systems Reply.
    \740\ See also NCEMC and Arkansas Municipal (opposing the 
increase in the minimum term to five years).
---------------------------------------------------------------------------

    1221. In order to further ensure continued service, TAPS seeks the 
following modifications: Transmission providers should be required to 
redispatch if necessary to accept a ``reasonably foreseeable'' and 
timely designated network resource with costs shared on a load ratio 
basis; transmission providers should be required to offer cost-based 
sales to embedded transmission-dependent utilities that cannot reach 
alternative suppliers; and exceptions should be permitted to the five-
year minimum term and matching exposure for small embedded 
transmission-dependent utilities and full or near-full requirements 
customers to ensure a continued right to service. Additionally, TAPS 
asserts that the minimum rollover in the absence of a competing request 
should be one year, rather than five.
    1222. TDU Systems, which generally opposes the increase to five 
years, believes that the Commission should clarify that rollover 
customers retain their rights to transmission capacity in the event of 
competing bids from either the transmission provider or another 
transmission customer if the rollover customer matches up to a five-
year contract term. Lastly, Seattle is concerned that with a five-year 
minimum, the risk in multi-segmented transmission transactions of one 
segment being undone by refusal of another is increased. Seattle 
suggests that acceptance and confirmation of one segment be made 
contingent on coordinated acceptance and confirmation on all other 
required segments.
    1223. In its reply to the arguments that rollover rights should be 
extended to accommodate service at new receipt or delivery points, EEI 
argues that this would allow a rollover customer to have priority over 
higher-queued customers on transmission paths other than the path over 
which the rollover customer is currently taking service, even if the 
new service would have different impacts on the transmission system. 
EEI argues that such service would be new service and not a rollover of 
existing service. EEI also urges the Commission to reject TAPS's 
assertion that it should require the transmission provider to accept 
rollover customers' designations of any network resources that are 
reasonably foreseeable and to redispatch its system if necessary to 
accommodate that resource, because among other things this would 
require providers to build the transmission system with sufficient 
redundancy to permit any customer to take service from any resource. 
Moreover, EEI argues that TAPS does not provide any suggestion as to 
what should be considered a reasonably foreseeable resource and that 
sharing costs on a load ratio basis would result in eighty to ninety 
percent of the redispatch costs being borne by the transmission 
provider's native load customers.
    1224. EEI also argues in its reply that TAPS's proposal to exempt 
all small customers from the five-year minimum term would interfere 
with transmission providers' ability to plan their systems to meet 
their customers' needs, as the

[[Page 12423]]

aggregated loads of several small customers can have a substantial 
impact on the system. EEI contends that TAPS's proposal to exempt all 
full and near-full requirements customers is also unreasonable, as the 
transmission provider would be forced to provide preferential service 
to certain groups of customers. As for the proposal to allow customers 
to exercise rollover rights with only one-year contracts if there is no 
competing request, EEI contends there is no need for a rollover if 
there is no competing request, since there is enough capacity for all 
and the transmission provider will grant the customer's new request for 
service for one year.\741\
---------------------------------------------------------------------------

    \741\ In their replies, Entergy, MidAmerican, and Progress 
Energy note many of these same concerns.
---------------------------------------------------------------------------

    1225. The increase in the minimum contract term eligible for a 
rollover right was opposed outright by several commenters for a variety 
of reasons.\742\ Many of these commenters oppose the increase to five 
years because they claim it is difficult under current market 
conditions to secure a five-year power supply agreement to underpin a 
five-year transmission contract, particularly in organized markets 
where the focus is on spot transactions or where the grid is very 
weak.\743\ They also argue that changes in the market (e.g., fuel 
costs) could significantly change the options available to customers 
within a five-year period and that a service extension of less than 
five years may be needed to manage delays in generation construction or 
some other unforeseeable event. TDU Systems urge the Commission to 
require any transmission provider seeking an increase in the minimum 
contract term to demonstrate that sufficient economic power supplies 
are available under longer-term contracts. EEI replies that such an 
approach would be inconsistent with the separation of functions between 
generation and transmission.
---------------------------------------------------------------------------

    \742\ E.g., Alberta Intervenors, Alcoa, Ameren, AMP-Ohio, 
Arkansas Municipal, AWEA, Dynegy Reply, Eastern North Carolina, 
EPSA, Exelon, Fayetteville, Manitoba Hydro, Morgan Stanley, NCEMC, 
NRECA, MISO/PJM States, PJM, Powerex, PPM, Reliant, TDU Systems, 
TransAlta, Williams, and Wisconsin Electric.
    \743\ E.g., Alcoa, AMP-Ohio, Arkansas Municipal, AWEA, Eastern 
North Carolina, EPSA, Exelon, Fayetteville, Manitoba Hydro, NCEMC, 
NRECA, MISO/PJM States, Reliant, TDU Systems, and Wisconsin 
Electric. TAPS also notes the difficulties, particularly for small 
transmission-dependent utilities, of locking in a five-year supply 
contract a year in advance of rollover.
---------------------------------------------------------------------------

    1226. Some commenters also argue that five years is incompatible 
with retail procurement processes in some states, such as Illinois and 
New Jersey, which they assert limit power supply agreements to three 
years.\744\ AWEA and PPM suggest that the Commission increase the 
minimum term to three years, because five years is beyond the term for 
many shorter-term power sales transactions and it would be cost 
prohibitive to lock up service for five years. Manitoba Hydro suggests 
a two- to three-year minimum term and that guaranteed redirects be 
permitted. Constellation, while generally supportive of a five-year 
minimum term, would prefer a three-year minimum term because it says 
three years is more closely aligned with much of the commercial 
activity in the energy commodity markets. Wisconsin Electric supports 
the current one-year term, but proposes three years as an alternative. 
In its reply, Duke indicates that it would support a three-year minimum 
term for rollover, but only if the notice period is required to match 
project lead time.
---------------------------------------------------------------------------

    \744\ E.g., EPSA, Exelon, Reliant, and MISO/PJM States.
---------------------------------------------------------------------------

    1227. In their replies, several commenters dispute the assertion 
that customers may not be able to obtain generation supplies for five-
year periods. They contend that generators in a competitive market will 
have to offer five-year contracts or risk losing their sales if LSEs 
begin requesting five-year contract terms in order to obtain rollover 
rights.\745\ SPP states on reply that it has not been its experience 
that suppliers have refused to enter into power supply agreements in 
excess of three years. EEI also argues that, even if a transmission 
customer has to accept the risk that its term of service exceeds the 
term of its power purchase in order to obtain rollover rights, the cost 
of the transmission service that is at risk is small in comparison to 
the cost of the power because the cost of transmission service is only 
a small portion of the delivered price of energy. EEI and Bonneville 
also note in their replies that unneeded transmission service can be 
sold in the secondary market.
---------------------------------------------------------------------------

    \745\ E.g., EEI Reply and Southern Reply.
---------------------------------------------------------------------------

    1228. NCEMC opposes the increase in contract term because it would 
inhibit the ability to pursue its prudent portfolio approach to 
mitigate price risks by providing for a mix of shorter and longer-term 
power supply contracts. If the Commission increases the minimum term, 
NCEMC argues that all existing rollover contracts should be 
grandfathered. EPSA also believes that existing one-year contracts 
should be grandfathered, otherwise it argues that market participants 
that relied on the current policy will be harmed. In its reply, EEI 
urges the Commission to reject EPSA's proposal that all currently 
effective one-year power supply contracts be grandfathered because, in 
EEI's view, it would interfere with good utility planning. EEI also 
argues that extending the minimum term to five years does not abrogate 
a customer's power supply contract because transmission and supply are 
unbundled and, therefore, changing the terms of transmission service 
does not interfere with contract rights under power sales agreements.
    1229. Exelon argues that limiting rollover rights to contracts that 
are five years or greater will discriminate against merchant generators 
that do not have load linked to generation, lead to stranded generation 
investments that were based on the current rules, and unfairly 
advantage local utilities wanting to build their own generation as 
opposed to seeking competitive alternatives. Exelon suggests that an 
approach similar to that utilized in PJM be adopted, in which PJM 
evaluates new requests for service that cannot be granted without 
utilizing an existing customer's service by notifying the existing 
customer and requiring it to match the new request within thirty days 
or release the service. PJM explains further that its approach would 
allow transmission customers two rollover options: long-term service 
for less than five years with no rollover right, or service for one 
year with indefinite rollover rights conditioned on either future 
limitations or an agreement to pay for necessary upgrades to maintain 
the rollover. In its reply, TAPS opposes the PJM approach stating that 
it would invite discrimination by transmission owners.
    1230. Other commenters that oppose the increase to five years 
assert that they are already long-term customers that simply take 
service year-to-year and should therefore already be included in 
planning, based on the fact that they are either a generator or load 
and cannot simply pick up and leave the system.\746\ Several other 
commenters likewise oppose the increase to five years because they do 
not believe that it will result in an increase in long-term contracting 
and planning as suggested by the Commission.\747\ For example, Williams 
notes that it currently has a ten-year transmission contract and argues 
that its transmission provider has done nothing to improve the grid in 
its area. TransAlta believes that a five-year minimum contract term 
will limit market participation to deep-pocketed market participants 
who can afford long

[[Page 12424]]

contracts. TransAlta also believes that the current option to contract 
for just one year and obtain a rollover right is often the benefit that 
prompts market participants to buy yearly service instead of shorter-
term products and, therefore, is an incentive to purchase longer-term 
service. Alberta Intervenors believe that a longer minimum term will 
provide a disincentive for long-term trading since the increased time 
commitment of five years will significantly increase the trading 
party's risk.\748\ The Organizations of MISO and PJM States believe 
that the current rollover policy generally results in an increase in 
investment in transmission and is only detrimental if service is 
terminated and the capacity goes unused.
---------------------------------------------------------------------------

    \746\ e.g., Morgan Stanley and Manitoba Hydro.
    \747\ e.g., Alberta Intervenors, TransAlta, and Williams.
    \748\ See also Morgan Stanley.
---------------------------------------------------------------------------

Commission Determination
    1231. The Commission finds that the current rollover policy is no 
longer just, reasonable, and not unduly discriminatory. The rights and 
obligations of a rollover customer should bear a rational relationship 
to the planning and construction obligations imposed on the 
transmission provider by the rollover rights. We find, for the reasons 
explained below, that the current policy no longer meets this standard 
and that a five-year term will ensure greater consistency between the 
rights and obligations of customers and the corresponding planning and 
construction obligations of transmission providers. We also believe 
that an increase to a five-year term is consistent with the native load 
protections contained in new section 217 of the FPA, primarily because 
requiring longer-term agreements ensures that the rollover right is 
used by transmission customers with long-term obligations to purchase 
capacity.\749\ Accordingly, the Commission adopts a five-year minimum 
contract term in order for a customer to be eligible for a rollover 
right. At the end of its initial five-year contract term, a 
transmission customer must, within the one-year notice period 
(discussed more fully below), agree to another five-year contract term 
or match any longer-term competing request in order to be eligible for 
a subsequent rollover.
---------------------------------------------------------------------------

    \749\ See EPAct 2005 sec. 1233(a) (to be codified at section 
217(b)(4) of the FPA, 16 U.S.C. 824q), which provides that ``[t]he 
Commission shall exercise the authority of the Commission under [the 
FPA] in a manner that facilitates the planning and expansion of 
transmission facilities to meet the reasonable needs of load-serving 
entities to satisfy the service obligations of the load-serving 
entities, and enables load-serving entities to secure firm 
transmission rights (or equivalent tradable or financial rights) on 
a long term basis for long term power supply arrangements made, or 
planned, to meet such needs.''
---------------------------------------------------------------------------

    1232. Our decision to adopt a five-year minimum term will remedy 
many of the problems associated with the current policy. Under our 
current policy, a customer can secure transmission service for one year 
and, in so doing, require the transmission provider to plan and upgrade 
its system on the assumption the rollover right will be continually 
renewed. For example, if a transmission provider's planning horizon is 
10 years, a one-year reservation would require the transmission 
provider to plan and upgrade the system as if the customer had 
purchased 10 years' service (i.e., would exercise its rollover right 
every year during that 10-year period). Because of this, the customer 
receives a guarantee of service beyond what it has contracted to pay 
for and the transmission provider must plan for service that may not 
actually be used.
    1233. By failing to link the customer's rights and obligations with 
those of the transmission provider, the current policy can have several 
detrimental effects. For example, it requires the transmission provider 
to plan and construct facilities that may not be necessary to serve 
load. Given the difficulty of siting new transmission, it is 
inappropriate to require transmission providers to use finite resources 
to finance and construct facilities that may not be necessary. 
Additionally, the current policy harms OATT customers by allowing 
rollover customers to tie up capacity that may be needed by other 
customers. This is because the current policy allows a rollover 
customer to lock up existing capacity, regardless of whether the 
rollover customer intends to use that capacity. This reduces the 
availability of existing capacity for other customers and, in turn, 
reduces competitive alternatives for customers.
    1234. Some commenters have argued that the Commission should use a 
shorter period, such as three years, that is more aligned with auctions 
in retail access markets or existing commercial practices. We disagree. 
The purpose of our reform of the rollover rights policy is to ensure 
that the rights and obligations of the customer are better aligned with 
the planning and construction obligations of the transmission provider. 
It is not to link the term of the rollover right to any particular 
commercial practice in any particular region. We do not believe that 
such a policy could be fairly implemented in any event. Commercial 
practices vary between the regions and change over time, and it would 
therefore be impractical to tailor the rollover rights in the OATT to 
the varying commercial practices across the country.
    1235. We also do not believe that adopting a five-year minimum term 
will have an adverse effect on participation in retail auctions that 
use three-year solicitations. At the outset, we note that retail 
auctions use solicitations of varying length and, hence, the fact that 
some states may use three-year auctions does not provide a basis to 
establish a generic standard for rollover rights under the OATT. Some 
states use shorter term auctions (e.g., one year) and, as indicated, we 
cannot reasonably tailor an OATT rollover obligation to the varying 
commercial practices across the country. We also do not believe that 
our policy will have an adverse effect on any such auctions. The 
winners in a retail solicitation are determined anew in each auction, 
based on the bids submitted in that auction. A prospective bidder 
therefore does not need a ``rollover right'' to compete in an auction. 
It only needs transmission service over the term of the solicitation 
(e.g., three years). The fact that it may not have an automatic right 
to transmission capacity in the next auction simply places it on the 
same footing as any other bidder.
    1236. In response to those commenters who argue that transmission 
customers making this long-term commitment must also be permitted to 
change their designated resources and receipt points as their power 
supply needs change, we believe that such an approach is unworkable. 
Allowing rollover customers to change their designated resources and 
receipt points in this manner would inappropriately result in rollover 
customers having priority over other transmission customers in the 
queue that may have already requested service over a given transmission 
path. This could result in substantial disruptions to transmission 
service to higher-queued customers requesting long-term service over 
these paths.\750\ Moreover, transmission customers are not currently 
guaranteed the ability to turn to other suppliers at other designated 
resources and receipt points and, therefore, we do not understand how 
simply increasing the minimum contract term to five years should

[[Page 12425]]

necessarily result in allowing transmission customers this increased 
flexibility. Likewise, we do not understand why an increase in the 
minimum contract term should result, as argued by APPA, TAPS, and 
others, in a transmission customer not having to compete with other 
transmission customers for firm capacity whenever its contract comes up 
for renewal. As discussed below, we will continue to require 
transmission customers to match competing requests for service as to 
term and rate, ensuring that transmission customers that value the 
service the most receive it.
---------------------------------------------------------------------------

    \750\ We agree with EEI that requiring transmission providers to 
ensure rollover customers the ability to change their designated 
resources and receipt points without disrupting service to other 
customers would, taken to its logical conclusion, require 
transmission providers to construct the transmission system with 
sufficient redundancy to permit any customer to take service from 
any resource.
---------------------------------------------------------------------------

    1237. We reject TAPS' proposal to exempt all small customers from 
the five-year minimum, since this would interfere with transmission 
providers' ability to plan their systems to meet their customers' 
needs. As EEI points out, the aggregated loads of several small 
customers can have a substantial impact on the system. We therefore 
believe it would be inappropriate to categorically exempt small 
customers. We also reject TAPS' proposal to exempt all full and near-
full requirements customers, because it would force transmission 
providers to provide preferential service to certain groups of 
customers. Additionally, we reject TAPS' proposal to allow customers to 
exercise rollover rights with only one-year contracts if there is no 
competing request. Without a competing request, a rollover right is not 
necessary in order to continue service as long as capacity remains 
available. Additionally, allowing a rollover for a one-year contract 
would continue to impose planning and construction obligations on the 
transmission provider that bear no reasonable relation to the rights 
and obligations of the rollover rights customer. We further reject TDU 
Systems' proposal that transmission providers demonstrate the 
availability of long-term supplies before moving to a five-year term. 
To do so would effectively require transmission providers to engage in 
the business of procuring supplies for their transmission customers, 
which is clearly outside the scope of their obligation to provide 
transmission service, and could implicate Standards of Conduct issues.
    1238. We also reject the proposal of EPSA and others that all 
currently effective one-year power supply contracts be grandfathered 
because this would disrupt transmission planning. For example, such an 
approach would require that a large portion of existing capacity be 
planned for on a significantly different timeline than that subject to 
the reformed rollover right. This also would detract from one of the 
primary goals of rollover reform, which is to improve transmission 
planning and encourage longer-term contracting. As discussed below, 
existing transmission contracts will be permitted to roll over under 
their existing terms until the first such rollover opportunity 
following the effectiveness of the reforms required by this Final Rule.
    1239. Lastly, we note that many of the reforms adopted elsewhere in 
this Final Rule will be beneficial to customers that no longer receive 
rollover rights, as well as to customers with rollover rights that wish 
to use their rollover rights to turn to alternative suppliers using 
different transmission paths. First, greater consistency and 
transparency in ATC calculations will provide greater assurance of 
nondiscriminatory access to existing transmission capacity. Second, our 
reforms relating to conditional firm and redispatch service will help 
to maximize the use of existing capacity, consistent with reliability, 
thereby providing customers without rollover rights greater flexibility 
to purchase existing transmission capacity. Third, our clarifications 
regarding our policy on redirects should improve the ability of 
transmission customers to redirect their service to new receipt or 
delivery points. Fourth, lifting the price cap on reassigned 
transmission capacity should assist transmission customers in 
reassigning any capacity that may not be needed on a given path because 
of a change in suppliers that requires service over new transmission 
paths. This will also necessarily result in the unneeded capacity being 
freed up for use by other transmission customers, thereby further 
assisting them in obtaining capacity that they need to access 
alternative suppliers. Lastly, and most importantly, greater openness 
and coordination in transmission planning should provide all customers 
better information regarding future resource options and access to 
competitive alternatives. We also believe that improved transmission 
planning should help to address allegations made by certain 
transmission customers (e.g., Williams) that even though they have 
signed up for ten years of service, they have not seen their needs 
planned for adequately.
b. One-Year Notice Provision
Comments
    1240. Many commenters support an increase in the notice period to 
one year or some other greater time period.\751\ Most support the 
increase based on the argument that the current 60-day notice period 
makes it very difficult to plan the system, because transmission 
providers often do not know until 60 days before the end of a contract 
whether a transmission customer will roll over its service, resulting 
in potential overbuilding of the system (e.g., because a transmission 
provider must plan its system assuming a transmission customer will 
roll over but sometimes it does not). They also argue that it is 
difficult to re-market capacity in only 60 days if rollover is not 
sought and that potential transmission customers are often 
unnecessarily turned away because transmission providers are unaware of 
the availability of capacity until 60 days before the end of a contract 
subject to a rollover right. In general, these commenters view a one-
year notice period as an improvement. However, many of these same 
commenters do not believe one-year notice is appropriate if the 
transmission provider must construct facilities to accommodate a 
rollover and, therefore, the notice should instead be tied to the start 
date for any necessary upgrades.\752\
---------------------------------------------------------------------------

    \751\ E.g., Ameren, Barrick Reply, Bonneville, Community Power 
Alliance, Constellation, Dominion, Duke, East Texas Cooperatives, 
EEI, E.ON, Entegra, Entergy, FirstEnergy, Great Northern, Imperial, 
LDWP, LPPC, MidAmerican, MISO, MISO Transmission Owners, Nevada 
Commission, Nevada Companies, North Carolina Commission Reply, 
NorthWestern, Northwest IOUs, NRECA, PGP, Pinnacle, PNM-TNMP, 
Progress Energy, Public Power Council, Salt River, Santa Clara, 
Southern, South Carolina E&G, SPP, Tacoma, TranServ, TVA, Utah 
Municipals, and Xcel. Both APPA and TAPS support a one-year notice 
provision, but only on the condition that the clarifications and 
modifications they suggest are made.
    \752\ E.g., Barrick Reply, Duke, EEI, Entergy, Indianapolis 
Power Reply, LPPC, Nevada Commission, Nevada Companies, Pinnacle, 
Progress Energy, South Carolina E&G Reply, Southern, and TVA.
---------------------------------------------------------------------------

    1241. EEI, for example, believes that notice should be tied to the 
start date of any necessary transmission upgrades, because the 
transmission provider may be left with stranded transmission capacity 
if it must begin construction on upgrades necessary to accommodate a 
rollover before the transmission customer has even indicated whether it 
will in fact seek a rollover. EEI also argues that a competing customer 
could be required to pay an incremental rate for network upgrades that 
could have been avoided if the rollover customer had provided earlier 
notice of its intention not to seek a rollover. EEI further contends 
that some state commissions will not allow upgrades where there is only 
the potential for a rollover. Finally, EEI states that a one-year 
notice period does not ensure that the transmission provider will be 
able to re-market the capacity, forcing other

[[Page 12426]]

transmission customers to bear the increased costs associated with the 
newly constructed transmission facilities. EEI proposes that a date be 
included in the initial service agreement by which the transmission 
customer must exercise its rollover rights if upgrades are needed to 
accommodate the rollover. If there is a pre-confirmed competing request 
or newly projected growth in native load, EEI suggests that the 
rollover customer must exercise its rollover and match by the later of 
the project start date for any new transmission facilities needed or 60 
days after the transmission provider notifies the transmission customer 
of the competing request.\753\ Additionally, if more than one-year 
notice is required because of the need for upgrades, EEI proposes that 
the transmission provider be required to notify the transmission 
customer if subsequent events delay the project start date, in which 
case the notice period would be revised. EEI asserts that any disputes 
can be dealt with by protesting the filing of an unexecuted agreement. 
EEI stresses that better, more inclusive planning, and more transparent 
ATC calculations, will provide transmission customers with greater 
assurances that project start dates are accurate.
---------------------------------------------------------------------------

    \753\ Ameren, Pinnacle, Southern, and TranServ agree that the 
submission of a competing request should trigger an accelerated 
timeline for the original customer to exercise or release its 
rollover rights.
---------------------------------------------------------------------------

    1242. Southern suggests that partial rollover be permitted if 
notice is not given in time for construction of an upgrade needed to 
provide full service. Duke, Nevada Commission, and Southern suggest 
that providing for one-year notice without a link to the start date for 
any upgrades falls short of the native load protections found in 
section 217 of the FPA. As an alternative, the Nevada Commission 
suggests tying the notice requirement to the amount of capacity subject 
to rollover, i.e., below a certain threshold, one year would be deemed 
per se sufficient.
    1243. APPA argues in reply that many customers may not know even 
one year in advance if they will have firm power supplies under 
contract that would enable them to roll over their corresponding firm 
transmission agreement and, therefore, requiring them to exercise their 
rollover rights even earlier in the contract term would only exacerbate 
an already impossible situation. In their replies, NRECA, TAPS, TDU 
Systems, and Utah Municipals urge the Commission to reject the 
recommendation that notice periods be expanded to be commensurate with 
construction lead times. They argue, among other things, that LSE 
transmission customers need a reasonable amount of certainty so that 
they may plan their power supply arrangements without fear that they 
may become unraveled due to unforeseeable circumstances. Utah 
Municipals also assert that the proffered justification for the 
proposal--to prevent overbuilding--is questionable at best as even the 
current policy which requires only a one-year contract minimum for 
rollover and 60-days notice has not resulted in wasteful overbuilding 
of the system. TDU Systems also point out that under section 28.2 of 
the pro forma OATT, transmission providers should be planning and 
expanding their systems to accommodate their network customers' current 
and future needs.
    1244. The one-year notice provision is opposed by several 
commenters, who argue that having to give one-year notice constitutes 
an undue burden.\754\ In general, these commenters argue that under 
current market conditions, transmission customers do not typically 
renew supply contracts one year in advance of expiration.\755\ Alberta 
Intervenors argue that a one-year notice provision does not aid in re-
marketing capacity, as any unused long-term firm service is already re-
marketed as short-term firm or non-firm service. Alberta Intervenors 
also argue that the increased lead time increases risk and creates 
uncertainty making it less likely that customers will enter into long-
term contracts. EPSA and Exelon suggest a flexible notice rule that 
depends on the length of the underlying contract or requiring more than 
60-days notice if there is insufficient capacity for a new long-term 
firm transmission service request, as is done in PJM. They also suggest 
PJM's approach whereby a transmission customer must inform PJM whether 
it will roll over within thirty days of being notified of a competing 
request. PPM and Wisconsin Electric suggest a six-month notice period, 
which complements their alternative suggestion of a three-year minimum 
contract term.
---------------------------------------------------------------------------

    \754\ E.g., Alberta Intervenors, Alcoa, Arkansas Municipal, 
EPSA, Exelon, Manitoba Hydro, Morgan Stanley, PPM, TransAlta, 
Williams, and Wisconsin Electric.
    \755\ E.g., Arkansas Municipal, Williams, and Wisconsin 
Electric.
---------------------------------------------------------------------------

Commission Determination
    1245. The Commission finds that the current 60-day notice period 
should be modified to reflect the longer term (five years) of the 
rollover rights. Currently, a customer with a one-year rollover right 
has 60 days to provide notice of whether it intends to rollover its 
capacity. This 60-day period was reasonable for a rollover right of 
short duration (one year), but it is no longer reasonable for a 
rollover right with a minimum five-year term.
    1246. In selecting a new notice period, the Commission has 
attempted to balance the circumstances faced by customers in renewing 
power supply contracts and the interests of transmission providers in 
attempting to plan their system. The Commission recognizes that no 
single notice period can perfectly balance these considerations, but 
chooses the one-year notice period as most appropriate under the 
circumstances. Given that the minimum rollover term has been lengthened 
to five years, it is reasonable to expect that customers will consider 
renewing such long term obligations in advance of 60 days prior to the 
expiration of their current obligation. We do not believe it is 
reasonable to fashion our notice period for customers that wait until 
the last minute to evaluate whether to extend their long-term 
contracts.
    1247. Many transmission providers argue that a one-year notice 
period is too short because it is not consistent with the transmission 
provider's planning horizon. We disagree. The Commission is extending 
the minimum term for rollover rights to five years to ensure greater 
consistency between the customer's rights and obligations and the 
planning and construction obligations of the transmission provider. We 
believe that this modification satisfies the principal concerns of 
transmission providers regarding the current policy on rollover rights. 
We recognize that a one-year notice period is shorter than the typical 
planning horizon, but we decline to extend the notice period to a time 
that coincides with the typical planning horizon or the time it takes 
to construct new facilities. Doing so would effectively eliminate 
rollover rights altogether, given that the resulting notice period 
could be three-to-five years. We do not believe it is reasonable to 
expect customers to have decided on new sources of supply three years 
in advance of the expiration of their current contracts. We therefore 
find that a one-year notice period most appropriately balances the 
interests of customers and transmission providers.
c. Matching and Rollover Restrictions Based On Native and Network Load 
Growth
Comments
    1248. As noted above, the Commission proposed to maintain the 
requirement that an existing rollover

[[Page 12427]]

transmission customer match competing offers as to term and rate. Some 
commenters argue that a competing customer be required to execute a 
contingent service agreement that becomes effective if the rollover 
customer does not match.\756\ Given the increase in the minimum 
contract term to five years in order to be eligible for a rollover 
right, TAPS argues that matching must be structured to recognize that a 
network customer must extend its power supply by at lease five years as 
well, in order to match a competing point-to-point customer that can 
simply extend its reservation. To ensure that network customers are not 
disadvantaged by matching, TAPS suggests that the Commission restrict 
reservations qualified to compete against a network customer's 
reservation to customers with long-term power contracts, so they are on 
more equal footing with network customers. TAPS also proposes a cut-off 
for requests with which the network customer will need to compete, such 
as three months prior to when the network customer exercises its 
rollover right, so that the network customer can structure its power 
supply commitments with some degree of advance knowledge of the 
competing requests. In its reply, Bonneville suggests allowing network 
transmission customers to compete based on the duration of their 
network transmission service request rather than on the duration of 
their resource commitments. As such, the transmission provider would 
assume that existing designated resources would continue to be used 
after the rollover unless informed otherwise.
---------------------------------------------------------------------------

    \756\ E.g., MidAmerican and Powerex.
---------------------------------------------------------------------------

    1249. The Commission also discussed in the NOPR whether native load 
restrictions should be reevaluated with each rollover and, if so, 
whether native load should then be required to compete with rollover 
customers for the capacity. Several commenters argue that a 
transmission provider's native and network loads should not be forced 
to compete with other transmission customers, as opposed to allowing 
the transmission provider to continue to reserve capacity for its 
native and network load at the time of granting a rollover.\757\ Most 
also stress that requiring a transmission provider to compete would 
violate the native load protections in section 217 of the FPA. LDWP 
contends that there should be no limitation on a transmission 
provider's right to recall capacity based on revised forecasts of 
native load growth.
---------------------------------------------------------------------------

    \757\ E.g., Allegheny, Entergy, FirstEnergy, Imperial, Nevada 
Companies, Progress Energy, Salt River, Santa Clara, and Seattle.
---------------------------------------------------------------------------

    1250. APPA contends on reply that transmission customers could find 
it very difficult to line up a new firm power supply of a term long 
enough to match the power supply arrangements of its vertically-
integrated investor-owned transmission provider (which is likely to 
have owned, rate-based generation in its power supply portfolio and, 
therefore, could agree to a very long-term transmission agreement). TDU 
Systems argue that transmission providers should be forced to compete 
for capacity and that this is, in fact, required by section 217 of the 
FPA, as the native load preference does not distinguish between the 
retail native loads of transmission providers and the native loads of 
other LSEs dependent on their systems. Powerex and PPM also support 
requiring transmission providers to compete. NorthWestern and Southern 
support requiring transmission providers to compete, but only when a 
restriction is not included in the original agreement. APPA also notes 
in its reply comments that, if Southern included LSEs' loads in its 
transmission planning and construction program along with its own 
native load, there would be no need to reclaim the LSEs' capacity at 
the close of the initial contract term or the renewal terms.
    1251. Several commenters also addressed the Commission's request 
for comment on whether there is a sufficiently clear, consistent, and 
transparent method that could be implemented on a generic basis to 
address the need for a transmission provider to demonstrate its 
forecast of native load growth and its effect on capacity reserved by 
rollover customers. Many of these commenters support the development of 
a clear and transparent method for demonstrating native load 
growth.\758\ Some commenters point to the need for accurate and 
transparent ATC calculations to aid in this process.\759\ If the 
transmission provider's calculation of ATC is consistent with the 
requirements the Commission adopts in this proceeding yet there is 
insufficient capacity to accommodate the customer's rollover, EEI 
recommends that the provider may include in the service agreement a 
limitation of rollover rights. AWEA recommends that transmission 
providers adopt the same transparent and consistent methods used to 
compute the Existing Transmission Capacity component of ATC to develop 
native load growth reservations that support rollover restrictions. 
AWEA, NorthWestern, and TAPS suggest posting forecast information on 
the OASIS, and TAPS goes on to stress that this information should be 
included in state planning documents as well as the transmission 
provider's coordinated and regional planning process. EPSA stresses 
that native load capacity must follow native load and not only be made 
available for the transmission provider and its affiliates. EPSA 
believes this is required by the native load protections found in FPA 
section 217.
---------------------------------------------------------------------------

    \758\ E.g., AWEA, Duke, EEI, Entergy, EPSA, Imperial, Nevada 
Commission, Powerex, Salt River, Seattle, South Carolina E&G, 
Southern, SPP Reply, and TAPS.
    \759\ E.g., AWEA, EEI, EPSA, and MISO.
---------------------------------------------------------------------------

    1252. Duke asks the Commission to address the possibility that 
capacity subject to a rollover right might be needed to serve native 
load outside of the ten-year planning horizon. The Nevada Commission 
and Southern suggest that the Commission give deference to state 
resource planning processes in attempting to verify native load growth 
forecasts. Southern also asks that the Commission clarify that rollover 
rights can be restricted based on rollover rights belonging to higher-
queued transmission customers. If transmission studies show no problems 
without the presence of a rollover, but then problems are identified 
with the rollover included, Southern contends that placing a 
corresponding limitation in the service agreement would be appropriate. 
Pinnacle requests clarification that when rollover rights are 
restricted based on native load growth, the transmission customer must 
pay for upgrades to continue its service.
    1253. Several commenters also suggest that transmission providers 
should be permitted to evaluate rollover restrictions at the time of 
each rollover.\760\ These commenters argue that it is impossible to 
identify all potential limitations upfront as system conditions change 
in unforeseeable ways (e.g., fluctuations in fuel prices can change 
dispatch decisions). They also argue that allowing a re-evaluation is 
consistent with the native load protections in FPA section 217.
---------------------------------------------------------------------------

    \760\ E.g., Nevada Companies, South Carolina E&G, and Southern.
---------------------------------------------------------------------------

    1254. In its reply, TAPS argues that a transmission provider should 
not be permitted to avoid its planning and expansion obligations by 
treating load growth not anticipated and documented in the original 
service agreement as a competing request to be matched. TAPS points out 
that section 217 of the FPA treats all LSEs--whether they are 
transmission providers or transmission-dependent utilities--the same, 
without

[[Page 12428]]

distinction, and therefore provides no basis to allow one LSE to claim 
transmission rights currently used by another LSE.\761\ Lastly, TAPS 
argues that when a provider is reclaiming capacity for load growth 
reserved in the initial service agreement, rollover customers should be 
allowed to match the request, thereby imposing an additional 
requirement on the provider.
---------------------------------------------------------------------------

    \761\ See also APPA Reply and TDU Systems Reply.
---------------------------------------------------------------------------

Commission Determination
    1255. The Commission will not adopt any changes to its matching 
policies at this time. At the time of rollover of their contracts, 
transmission customers will continue to be required to match competing 
requests for service as to term and rate in order to roll over their 
service. This preserves the current policy goal of providing a 
mechanism for awarding capacity to those who value it most, as well as 
providing for a tie-breaking mechanism when needed that gives priority 
to existing customers so that they may continue to receive transmission 
service.\762\ Absent the requirement that the customer match the 
contract term of a competing request, transmission providers could be 
forced to enter into shorter-term arrangements that could be 
detrimental from both an operational standpoint (i.e., system planning) 
and a financial standpoint.\763\ We clarify, however, that transmission 
customers must also enter into a transmission contract of at least five 
years in order to obtain a subsequent rollover right in the absence of 
a competing request for a longer term.
---------------------------------------------------------------------------

    \762\ See Order No. 888-A at 30,197.
    \763\ Id.
---------------------------------------------------------------------------

    1256. The Commission will continue to require rollover restrictions 
based on reasonable forecasts of native load growth or preexisting 
contracts that commence in the future to be included in the initial 
transmission service agreement. This will remain the only appropriate 
way to restrict a rollover right. We also will continue to evaluate a 
transmission provider's native load growth forecasts on a case-by-case 
basis, as no commenter has provided us with a sufficiently clear, 
consistent, and transparent method that could be implemented on a 
generic basis that ensures that the demonstration of native load growth 
is accurate and is tied to a need for the specific capacity reserved by 
a rollover customer.\764\ Because we will continue to require rollover 
restrictions to be included in the initial transmission service 
agreement, we necessarily reject the suggestion that transmission 
providers be permitted to restudy for rollover restrictions at the time 
of each rollover. Accordingly, it is unnecessary for us to address 
whether it would be appropriate for a transmission provider's native or 
network load to compete with a rollover customer if a new study at the 
time of the rollover indicated a native or network need for the 
capacity.
---------------------------------------------------------------------------

    \764\ While the Commission has not to date accepted any native 
load growth showing made by a transmission provider, it has recently 
set for hearing several such showings. See, e.g., Southern Co. 
Servs., Inc., 116 FERC ] 61,050 (2006); Nevada Power Co., 116 FERC ] 
61,093 (2006).
---------------------------------------------------------------------------

    1257. In response to the suggestions of some commenters, we believe 
that consideration should be given in our case-by-case evaluations of 
native load growth forecasts to state-approved integrated resource 
plans that show a native load need for the capacity.\765\ Moreover, we 
believe that the ATC and planning reforms that we are adopting in this 
Final Rule will provide greater transparency and assurance that 
transmission providers' forecasts of native load growth are accurate. 
We emphasize that we expect the forecasts utilized in transmission 
planning to be consistent with the forecasts utilized to support a 
rollover restriction. Lastly, the coordinated and regional planning 
process required by this Final Rule is designed to improve the 
availability of transmission service by, among other things, increasing 
transparency and providing customers a meaningful opportunity to 
participate in the planning process. Accordingly, we believe that 
improved planning should help to reduce the need to restrict rollovers 
in the future.
---------------------------------------------------------------------------

    \765\ We note that this is consistent with the Commission's 
evaluation of rollover restrictions proposed by transmission 
providers in the past. See, e.g., Nevada Power Co., 97 FERC ] 61,324 
at 62,493 n.17 (2001).
---------------------------------------------------------------------------

d. Other Issues
Comments
    1258. A number of comments relate to the applicability of the 
rollover-related reforms to RTOs and ISOs. CAISO asks the Commission to 
confirm that the rollover reforms do not apply to CAISO as its current 
tariff does not have such a provision and rollover is, in fact, 
incompatible with CAISO's transmission service model. Sacramento, 
however, asks the Commission to clarify that rollover rights apply to 
long-term firm service provided by RTOs and ISOs under Order No. 681 
under what it terms the ``as good as or superior to'' standard.\766\ 
Organization of MISO and PJM States assert that any changes for RTOs 
should be made through the stakeholder process. In its reply, Williams 
opposes permitting RTO stakeholders to determine changes in rollover 
rights policy in RTO regions, as it would result in disparate rules and 
practices and increased opportunities for discrimination, and 
therefore, the Commission should adopt a single policy applicable to 
all rollover rights.
---------------------------------------------------------------------------

    \766\ In its reply, CAISO argues that this request to expand the 
requirements of Order No. 681 is inappropriate both because the 
Commission and courts have already recognized that rollover rights 
under the pro forma OATT do not apply to entities like CAISO that do 
not offer traditional Order No. 888 network and point-to-point 
transmission services and because the Commission has already 
rejected such a requirement in Order No. 681 itself.
---------------------------------------------------------------------------

    1259. Other commenters raise different discrete issues. Morgan 
Stanley asks the Commission to amend pro forma OATT section 2.2 to 
include existing policy determinations with respect to the manner in 
which a transmission provider can curtail or, alternatively, must honor 
and accommodate rollover requests. Duke asks the Commission to abandon 
its existing policy prohibiting the restriction of rollover rights 
based on the potential exercise of other customers' rollover rights. 
Salt River asks the Commission to clarify that the proposal to extend 
the minimum term to five years does not change the definition in 
section 1.20 of the pro forma OATT that one year constitutes a long-
term contract. AWEA, Constellation, and EPSA ask the Commission to 
allow transmission customers to waive their rollover rights.
Commission Determination
    1260. As we explain in section IV.C above, RTOs and ISOs must 
submit a filing showing that their practices are consistent with or 
superior to the modifications made in the Final Rule. This does not 
necessarily mean that entities such as CAISO must create rollover 
rights if they do not have them already. Arguments regarding the 
applicability of rollover reform may be raised pursuant to the process 
described in section IV.C. We also clarify that our decision to extend 
the minimum term to five years does not change the definition in 
section 1.20 of the pro forma OATT that one year constitutes a long-
term contract. Commenters have not offered sufficient justification for 
further clarifications to our rollover policies or amendments to 
section 2.2 at this time.
e. Effectiveness Upon Acceptance of Coordinated and Regional Planning 
Process and Transition
Comments
    1261. Several transmission customers and other commenters support a 
linkage

[[Page 12429]]

between rollover reform and planning, but do not support making 
rollover reforms effective upon acceptance of a transmission provider's 
coordinated and regional planning process, but rather on successful 
implementation of that process.\767\ While both TAPS and TDU Systems 
support the link to planning generally, TAPS goes further and advocates 
holding transmission providers accountable for failing to plan and 
construct facilities needed to meet transmission customer needs. TDU 
Systems point out that the linkage to planning does not remedy concerns 
that the current market does not generally provide for five-year supply 
contracts.
---------------------------------------------------------------------------

    \767\ E.g., AWEA, Constellation, EPSA, Exelon, PGP, and PPM.
---------------------------------------------------------------------------

    1262. Some commenters, however, oppose linking the effectiveness of 
rollover reform to planning, arguing that rollover reform is needed as 
quickly as possible.\768\ For example, Duke, Progress Energy, and 
Southern argue that FPA section 217 provides no indication that the 
native and network load protections inherent in rollover reform should 
be subject to conditions such as waiting for the Commission to accept a 
planning process. Moreover, Duke argues that developing a planning 
process will be time-consuming and that holding rollover reform hostage 
to it could motivate stakeholders with contracts shorter than five 
years to endlessly try to convince the Commission to delay acceptance 
of a transmission provider's planning process.
---------------------------------------------------------------------------

    \768\ E.g., Bonneville, Duke, EEI Reply, North Carolina 
Commission Reply, Northwest IOUs, PNM-TNMP Reply, Progress Energy, 
Public Power Council, South Carolina E&G Reply, and Southern.
---------------------------------------------------------------------------

    1263. Some commenters contend that linking planning and rollover 
reform will create differences in tariffs, with each transmission 
provider having a different effective date for rollover reforms.\769\ 
MISO argues in its reply that the Commission should clarify in the 
Final Rule that its requirement that the new policy becomes effective 
upon acceptance of the transmission provider's coordinated and regional 
planning process is already met in regions where RTOs or ISOs provide 
service, as they already have Commission-approved regional transmission 
planning mechanisms in place. Bonneville argues in its reply for a 
consistent implementation date across all transmission providers so as 
to avoid another degree of complexity for customers requiring rollover 
capacity across multiple transmission providers' systems.
---------------------------------------------------------------------------

    \769\ E.g., Northwest IOUs, Duke Reply and EEI Reply.
---------------------------------------------------------------------------

    1264. As for the transition period proposed in the NOPR, a variety 
of commenters point out that, depending on the status of any given 
contract, making the one-year notice provision effective on acceptance 
of a transmission provider's planning process could leave some 
transmission customers unable to provide one-year notice if there is 
less than one year remaining on their contracts.\770\ FirstEnergy, 
Exelon, Great Northern, and TAPS emphasize that existing transmission 
customers should be permitted one more rollover under the current 
rules, because the parties to such agreements have relied on the 
current rules in meeting their transmission needs. APPA and TAPS point 
out that transmission customers will need a sufficient amount of time 
to secure five-year power agreements to meet the new requirements. AWEA 
argues generally for a transition period during which existing 
customers can maintain or relinquish their existing rollover rights 
under current rules and become subject to new requirements only at the 
end of the transition period.
---------------------------------------------------------------------------

    \770\ E.g., APPA, FirstEnergy, Northwest IOUs, PGP, and Public 
Power Council.
---------------------------------------------------------------------------

Commission Determination
    1265. The Commission adopts the NOPR proposal to make rollover 
reform effective at the time of acceptance by the Commission of a 
transmission provider's coordinated and regional planning process also 
required by this Final Rule. We believe that rollover reform and 
transmission planning are closely related, because according to our 
longstanding policy, transmission service eligible for a rollover right 
must be set aside for rollover customers and included in transmission 
planning. We believe that it is necessary that reforms in both areas 
proceed together, and therefore, we reject the suggestion of some 
commenters that rollover reform proceed independent of transmission 
planning reform. We understand that our approach may result in 
differences in transmission providers' OATTs, with some having a 
different effective date for rollover reforms. However, because the 
effectiveness of rollover reform will be tied to acceptance of a 
transmission provider's coordinated and regional transmission planning 
process, rollover reforms in any given region generally should be 
effective within the same time period.
    1266. We reject the arguments by some commenters that rollover 
reform be made effective upon the ``successful'' implementation, as 
opposed to acceptance by the Commission, of a transmission provider's 
coordinated and regional planning process. We believe that utilizing a 
subjective deadline, such as the successful implementation of the 
planning process, could result in significant confusion in the industry 
as to when rollover reforms should be effective. Furthermore, an 
existing filed and accepted transmission planning process, such as 
those that may be on file for RTOs and ISOs, does not trigger the 
effectiveness of rollover reform for transmission providers using the 
process. Such RTOs and ISOs and their transmission-owning members must, 
as discussed elsewhere in this Final Rule, comply with the planning 
reforms required by the Final Rule through the compliance filing 
procedures identified in section IV.C. It is Commission acceptance of 
these compliance filings that will trigger effectiveness of rollover 
reform for these transmission providers, assuming rollover reform is 
applicable to their tariff services in the first instance.
    1267. In response to commenters' concerns that, depending on the 
effective date of rollover reform, certain customers may not have a 
year or more left on their contracts such that they can comply with the 
one-year notice provision, we emphasize that existing contracts with a 
rollover right at the time of effectiveness of rollover reform may 
exercise their next rollover based on the existing notice rules. It is 
only a rollover contract entered into or renewed after the 
effectiveness of rollover reform that must comply with the new rollover 
provisions, including the one-year notice requirement.
4. Modification of Receipt or Delivery Points
    1268. Section 22 of the pro forma OATT provides that a transmission 
customer taking firm point-to-point service may modify its receipt and 
delivery points, i.e., redirect its service, on either a non-firm or a 
firm basis. Section 22.1 (Modifications on a Non-Firm Basis) provides 
that, subject to certain conditions, a firm point-to-point customer may 
request transmission service on a non-firm basis over receipt and 
delivery points other than those specified in its service agreement 
(known as secondary receipt and delivery points) in amounts not to 
exceed its firm capacity reservation, without incurring an additional 
non-firm point-to-point service charge or executing a new service 
agreement. Section 22.2 (Modifications on a Firm Basis) provides that 
any request to modify receipt and delivery points on a firm basis shall 
be treated as a new request for service in accordance with

[[Page 12430]]

section 17 of the pro forma OATT (Procedures for Arranging Firm Point-
to-Point Transmission Service), except that the transmission customer 
shall not be obligated to pay any additional deposit if the capacity 
reservation does not exceed the amount reserved in the existing service 
agreement. While such new request is pending, the transmission customer 
retains its priority for service at the existing firm receipt and 
delivery points specified in its service agreement.
    1269. In Order No. 676, the Commission adopted the ``Standards for 
Business Practices and Communication Protocols for Public Utilities'' 
developed by the NAESB's Wholesale Electric Quadrant (WEQ).\771\ Order 
No. 676 incorporated the aforementioned standards by reference into the 
Commission's regulations, required public utilities to implement the 
standards by July 1, 2006, and required public utilities to file 
revisions to their OATTs to include these standards.\772\ The WEQ 
Standards include a number of standards addressing requirements for 
dealing with redirects on both a firm and non-firm basis.\773\ All of 
the WEQ Standards dealing with redirects were adopted by the Commission 
in Order No. 676, except for WEQ Standard 001-9.7, which addresses the 
impact of a firm redirect on a long-term firm transmission customer's 
rollover rights under section 2.2 of the pro forma OATT. The Commission 
directed the WEQ to reconsider WEQ Standard 001-9.7 and to adopt a 
revised standard consistent with the Commission's policies.\774\ The 
Commission also offered guidance to assist the WEQ in developing a 
standard that is consistent with Commission policy.\775\
---------------------------------------------------------------------------

    \771\ The WEQ was established by NAESB in response to a 
Commission order requesting the wholesale electric power industry to 
develop business practice standards and communication protocols by 
establishing a single consensus, industry-wide standards 
organization for the wholesale electric industry. See Order No. 676 
at P 3-4.
    \772\ The standards will hereinafter be referred to as the WEQ 
Standards. The Commission adds a reference to the WEQ Standards in 
section 4 of the pro forma OATT, which identifies the Commission's 
regulations containing the terms and conditions relevant to the 
OASIS and standards of conduct.
    \773\ The requirements for dealing with redirects on a firm 
basis are found at WEQ Standard 001-9, et seq., and the requirements 
for dealing with redirects on a non-firm basis are found at 001-10, 
et seq.
    \774\ Order No. 676 at P 52.
    \775\ Id. at P 53-61.
---------------------------------------------------------------------------

NOPR Proposal
    1270. In response to the NOI, commenters raised various concerns 
regarding redirects. Among other things, customers complained of 
difficulties obtaining redirected service, while transmission providers 
complained of a lack of clarity in the rules governing redirects. In 
the NOPR, the Commission stated its belief that a number of these 
concerns appeared to have been resolved by the adoption of the WEQ 
Standards in Order No. 676, which was issued after the NOI. The 
Commission sought comment on whether parties believed the WEQ Standards 
in fact addressed those concerns adequately.
    1271. The Commission also stated its expectation that a number of 
other concerns raised in response to the NOI, while perhaps not yet 
addressed (or addressed fully) by a WEQ Standard, are nevertheless the 
types of issues that are appropriate for the WEQ process. The 
Commission therefore proposed that each commenter that continued to 
believe additional reform is necessary with regard to redirects 
evaluate whether its concerns would more appropriately be addressed by 
the WEQ as it considers its next version of its standards.\776\ The 
Commission noted that WEQ was in the process of reevaluating WEQ 
Standard 001-9.7, dealing with redirects and rollovers, so that it is 
consistent with the Commission's guidance given in Order No. 676. The 
Commission requested comment on whether the WEQ process, along with the 
guidance provided by the Commission in Order No. 676, is sufficient to 
address the concerns of commenters that seek clarification on the 
interplay between redirects and rollovers.
---------------------------------------------------------------------------

    \776\ The Commission noted in this regard that the WEQ's 
procedures ensure that all industry members can have input into the 
development of a business practice standard, whether or not they are 
members of NAESB, and each standard it adopts is supported by a 
consensus of the five industry segments: transmission, generation, 
marketers/brokers, distribution/load-serving entities, and end-
users. See Order No. 676 at P 5 & n.5.
---------------------------------------------------------------------------

    1272. In the NOPR, the Commission acknowledged that there were 
additional, more fundamental concerns with regard to section 22 raised 
in response to the NOI. Customers generally argued that their ability 
to redirect to new points is stymied by a lack of ATC at the new points 
or the need for major upgrades, or that transmission providers take too 
long to process the redirect request. Transmission providers, on the 
other hand, complained of the administrative burdens and complexity 
(particularly with regard to reliability) of processing transmission 
customers' short-term changes in service and that there is often not 
enough time for the market to respond to capacity made available on a 
customer's original path. The Commission stated its belief that other 
proposed reforms in the areas of process, transmission planning, and 
ATC calculation should address transmission customer concerns regarding 
redirects. The Commission encouraged interested parties to submit a 
specific proposal, along with proposed revised pro forma OATT language, 
to the extent they believe the proposed reforms will not adequately 
address their concerns.
    1273. The Commission also noted in the NOPR that several 
transmission providers had posted business practices that allow network 
customers either to substitute an off-system non-designated resource 
for a designated resource or to redirect the point of receipt 
associated with an existing network resource. The Commission proposed 
that network customers not be permitted to redirect network 
transmission service because network service involves no identified 
contract path and therefore should not be treated as a directable 
service.
a. Proposed Reliance on WEQ Process and Other OATT Reforms
Comments
    1274. Commenters generally agree with the Commission that issues 
with respect to redirects of firm and non-firm transmission service are 
best addressed through the WEQ as established by NAESB, in accordance 
with Order No. 676 and the WEQ process for creating new standards.\777\ 
Seattle argues that the NAESB standard setting process has worked well 
thus far and, as a result, other redirect issues should be first 
referred to NAESB as a standard-setting request. MISO states that it 
has serious concerns with the WEQ process and the Commission's 
unwarranted deference to NAESB to develop what will become binding 
business standards and practices.
---------------------------------------------------------------------------

    \777\  E.g., EEI, Imperial, NorthWestern, Southern, and Suez 
Energy NA.
---------------------------------------------------------------------------

    1275. Nevada Companies recommend the following improvements for the 
NAESB process: use of a professional facilitator to keep discussions 
focused and moving; and mandatory surveys breaking down the sections on 
proposed NAESB standards after the first round of comments are received 
to determine if consensus exists on the proposed standards, since it 
appears that there are relatively few participants at NAESB meetings 
where standards are being drafted and relatively few commenters on 
those draft standards.
    1276. Several commenters state that they agree with the 
Commission's proposal to rely on other proposed

[[Page 12431]]

reforms in the NOPR to resolve the remaining redirect issues.\778\ 
Seattle generally agrees that the reforms proposed in the NOPR should 
improve the ability to assign and use transmission on a firm basis. EEI 
and NorthWestern state that the NOPR proposal to increase transparency 
in the calculation of ATC should assist transmission customers in both 
selecting transmission paths that may be available for redirect and 
understanding why certain paths cannot accommodate redirect 
transactions.
---------------------------------------------------------------------------

    \778\ E.g., EEI, NorthWestern, and Seattle.
---------------------------------------------------------------------------

Commission Determination
    1277. The Commission concludes that the proposed method for 
addressing remaining concerns with redirects--i.e., relying on other 
reforms adopted in this Final Rule and in the Order No. 676 
proceeding--is adequate to ensure that transmission providers do not 
engage in undue discrimination when a customer seeks to modify its 
receipt and delivery points on a firm basis. As explained throughout 
this Final Rule, the reforms adopted herein address the remaining 
opportunities for undue discrimination. Planning and ATC reforms will 
give transmission customers more accurate and complete ATC information 
when evaluating their redirect options. Increased transparency will 
give transmission customers the information they need to evaluate a 
transmission provider's denial of a request to redirect. Modifications 
to the process for requesting and securing firm point-to-point service 
will improve the ability to redirect transmission service to new points 
pursuant to section 22 and ensure complete and timely responses from 
transmission providers. The Commission therefore concludes that no 
further reforms specific to redirects are necessary at this time.
    1278. The Commission also concludes that the NAESB WEQ is the 
appropriate standard-setting body for developing business practices and 
implementing the Commission's redirect policy. The Commission will 
refrain from commenting here on the NAESB process itself because we 
believe that the industry is best situated to determine how to 
structure the standard-setting process to provide for the widest 
possible participation and consensus. We nevertheless clarify that, 
consistent with precedent, NAESB is charged with implementing 
Commission policy through business practices.\779\ The Commission finds 
that the NAESB WEQ is an acceptable standards development process, 
representing a cooperative effort by industry participants to develop 
business practices that enhance the efficiency of the electric 
grid.\780\ Where necessary, NAESB participants may seek clarification 
of Commission policy so that NAESB may develop the appropriate 
standards.
---------------------------------------------------------------------------

    \779\ See Standards for Business Practices of Interstate Natural 
Gas Pipelines, Order No. 587-N, FERC Stats. & Regs. ] 31,125 at P 23 
(2002).
    \780\ See Order No. 676 at P 12.
---------------------------------------------------------------------------

b. Redirects and Rollovers Rights
Comments
    1279. Regarding the interaction between redirects and rollovers, 
some commenters request that the Commission clarify what they view as 
an inconsistency between Order No. 676, the Commission's existing pro 
forma OATT, and the rollover proposal in the NOPR. Specifically, 
Bonneville, MISO, and Southern argue that, contrary to the pro forma 
OATT and NOPR, Order No. 676 improperly suggested in an example that a 
short-term redirect of a long-term service agreement gives the customer 
rollover rights for the new path. TranServ supports placing the 
following two conditions on the receipt of rollover rights for 
redirects: a redirect on a firm basis must be for one year or longer, 
and the redirect must be for the entire remaining term of the parent 
(original) request.\781\ If these conditions are met, TranServ contends 
that the customer will be granted rollover rights on the redirect path 
and lose the rollover rights held on the original path. If the customer 
wishes to retain rollover rights on the original path, TranServ 
continues, it will have the option to submit multiple redirect requests 
of less than one year in duration for the term desired. With respect to 
WEQ Standard 001.9.7, MISO incorporates by reference its opposition to 
the Commission's adoption of the proposed transfer of rollover rights 
on the redirected path in its request for rehearing of Order No. 676. 
There MISO argued that there should be no rollover rights on a redirect 
path and that the guidance in Order No. 676 requiring the transmission 
provider ``to offer rollover rights to a customer requesting a firm 
redirect if rollover rights are available on the redirect path'' was 
inconsistent with the pro forma OATT.
---------------------------------------------------------------------------

    \781\ TranServ explains that these are two primary features in a 
revised WEQ 001-9.7 standard that was open for public comment.
---------------------------------------------------------------------------

Commission Determination
    1280. Commission policy allows a redirect of firm, long-term 
service to retain rollover rights, even if the redirect is requested 
for a shorter period. In other words, the rollover right follows the 
redirect, regardless of the duration of the redirect. Contrary to the 
comments of Bonneville, MISO, and Southern, the Commission did not 
impose this requirement for the first time in Order No. 676, but merely 
provided guidance to the industry by restating Commission policy on 
this matter. The Commission has explained in prior orders that a 
transmission customer making a firm redirect request does not convert 
its original long-term firm transmission service to short-term service, 
nor does it lose its rollover rights under its long-term firm 
transmission service agreement. The Commission's concern underlying 
this policy is that long-term customers should not need to choose 
between redirecting on a firm basis and maintaining rollover rights, 
rather their rollover rights should be retained consistent with the 
long-term nature of their service.
    1281. In Commonwealth Edison Co., the Commission explained that a 
``request to change a delivery point on a firm basis for one month and 
then to revert to its original delivery point does not convert its 
existing long-term firm transmission service agreement into two 
separate short-term transmission service agreements.'' \782\ The 
Commission stated that section 22.2 was intended to provide flexibility 
to transmission customers to permit them to react in a competitive 
market and that some amount of this flexibility would be lost if a 
long-term firm transmission customer seeking to modify its delivery 
points would lose its rollover rights.\783\
---------------------------------------------------------------------------

    \782\ 95 FERC ] 61,027 at 61,083 (2001).
    \783\ The Commission, however, recognized that this flexibility 
was not unlimited--any change to a delivery point is treated as a 
new request for service for purposes of the availability of 
capacity.
---------------------------------------------------------------------------

    1282. The Commission affirmed this policy in American Electric 
Power Service Corp.\784\ In that case, a long-term transmission 
customer (Exelon) had been granted a short-term redirect, but denied 
rollover rights on the redirected path. The Commission found the denial 
of rollover rights was improper, since the ``redirect request made by 
Exelon did not convert Exelon's long-term firm transmission service to 
short-term service, and, therefore, did not affect Exelon's rollover 
rights under its long-term firm transmission service agreement.'' \785\ 
Thus, there is no inconsistency between the Commission's redirect 
policy and Order No. 676.
---------------------------------------------------------------------------

    \784\ 97 FERC ] 61,207 at 61,905-06 (2001).
    \785\ Id.

---------------------------------------------------------------------------

[[Page 12432]]

c. Redirects as New Requests for Service
Comments
    1283. With respect to the provision in section 22.2 of the pro 
forma OATT specifying that requests to redirect on a firm basis be 
considered new requests for service, LPPC and NPPD ask that this 
provision be modified to ensure that a customer redirecting its service 
will retain a higher priority for service in the transmission 
provider's queue than new customers. LPPC argues that it is inequitable 
to require customers to compete for capacity as though their loads were 
incremental to the system when they are simply changing their receipt 
points as a matter of necessity (since suppliers may commence serving 
other loads or cease doing business). EEI argues on reply that, if 
LPPC's proposal would give customers priority at new points of receipt 
and delivery regardless of whether the redirected service creates 
system impacts different from the old service, the proposal would 
replace ``first-come, first-served'' priority with a system in which 
customers would never know for sure whether their own requests for 
service would be displaced by subsequent requests for redirected 
service. EEI cautions that the transmission system simply cannot be 
planned and constructed with enough spare capacity to allow any 
customer to redirect service to any point that it chooses at any time.
    1284. Bonneville similarly argues that a redirect request should 
meet the same term and notice requirements as a new request given that 
the transmission provider's planning horizon and the amount of time 
needed to remarket unused capacity is no different for a redirect and a 
new transmission service request. APPA argues on reply that it is 
unclear how Bonneville's request would affect load-serving transmission 
customers that cannot obtain power supply agreements of a term 
sufficient to dovetail with the term requirements for a new request. 
Imperial recommends that redirects be evaluated using ATC at the time 
of the redirect request, like any other new request for service, but 
that the transmission provider be given additional time to determine 
whether native load growth will prevent rollover rights for the 
redirects.
Commission Determination
    1285. Section 22.2 of the pro forma OATT provides that redirects 
``shall be treated as a new request for service in accordance with 
section 17,'' except that the transmission customer may not be required 
to pay an additional deposit in certain circumstances. Therefore, a 
redirect right does not grant the customer access to system capacity or 
queue position different from other customers submitting new requests 
for service. A redirect request must be evaluated in accordance with 
section 17 using the same system assumptions and analysis applicable to 
any other new request for service, including whether sufficient ATC 
exists to accommodate the request. The Commission concludes it would be 
inappropriate, and contrary to the pro forma OATT, to grant redirects 
special queue treatment.
    1286. Regarding Imperial's request that transmission providers be 
given additional time to determine whether native load growth will 
prevent rollover rights for the redirects, we find that redirects 
should be studied like any other new request for firm point-to-point 
service. Transmission providers must examine whether any request, a 
firm redirect request or a new service request, would be affected by 
future native load growth resulting in possible rollover rights 
restrictions, so we see no need to provide additional time for 
transmission provider analysis of firm redirect request.
d. Pricing for Redirects
Comments
    1287. TranServ requests that the Commission resolve a disagreement 
among WEQ participants regarding the pricing of redirects as requests 
for new service. TranServ asks whether the failure to charge an 
incremental uplift between the original and redirected rate (e.g., 
respectively, the monthly rate and daily on-peak rate) would constitute 
the offering of a discount for daily service that in turn must be 
posted for all other paths to the same point of delivery. TranServ 
argues that it is reasonable to charge an incremental uplift such that 
the rate paid by the redirect customer would be on par with that paid 
by any other transmission customer reserving (daily) short-term firm 
service of like duration (i.e., a ``new request for service''), and the 
customer would pay the difference between the daily on-peak rate and 1/
30th of the monthly rate.
    1288. Southern argues that, with respect to the price for 
redirects, if redirected hourly firm service is more valuable than firm 
service, economic theory would dictate that customers should be 
required to pay for that added value.
Commission Determination
    1289. The Commission has not established a single, industry-wide 
pricing policy for redirects and did not propose a pricing policy in 
the NOPR. As a result, a uniform pricing method for redirects is beyond 
the scope of this proceeding. Nevertheless, we note that the Commission 
explained in a recent order that its policy does not allow transmission 
providers to collect additional charges when a firm point-to-point 
customer redirects on a non-firm basis.\786\ The Commission concluded 
that it would not subject non-firm redirects to the Appalachian Method 
of pricing,\787\ which is premised on the assumption that a customer 
using the transmission system for the 16 peak hours of the day should 
pay the same contribution to fixed costs as a customer who has reserved 
capacity on a daily basis. This is because the redirecting customer 
already would have paid for firm service over all on-peak and off-peak 
hours during the reservation period of its service, therefore, there is 
no need to ensure that the customer pays a premium for the opportunity 
to cherry pick the best hours each day. Furthermore, because the 
Commission is not requiring the provision of hourly firm service, 
Southern's argument regarding redirected hourly firm service is now 
moot.
---------------------------------------------------------------------------

    \786\ Midwest Independent Transmission System Operator, Inc., 
118 FERC ] 61,095 at P 79-85(2007).
    \787\ See Appalachian Power Co., 39 FERC ] 61,296 (1987).
---------------------------------------------------------------------------

e. Other Issues
Comments
    1290. EEI agrees with the Commission's proposal to clarify that 
network customers may not redirect network transmission service. 
Alberta Intervenors contend that undue discrimination remains because 
the flexibility to modify points of receipt and delivery that the 
network customer enjoys through ``parking'' and ``hubbing'' is not 
likewise granted to a point-to-point customer. Alberta Intervenors 
recommends that the pro forma OATT either make a common service 
available to all participants (not just network customers) or prohibit 
network customers from using point-to-point services for parking and 
hubbing.
    1291. Imperial asks the Commission to clarify that a transmission 
customer should not be able to make multiple redirects. Imperial 
explains that this clarification would address two concerns: multiple 
short-term changes raise reliability concerns and often there is 
insufficient time for the released capacity to be used by another 
customer; and the burden on properly scheduling for reliability 
increases exponentially when there are redirects of redirects.

[[Page 12433]]

    1292. MISO/PJM States argue that because RTOs are not likely to 
engage in discrimination with respect to redirects, the Commission 
should not modify RTO redirect policies in the instant rulemaking 
proceeding.
Commission Determination
    1293. The Commission adopts the NOPR proposal and finds that 
network customers may not redirect network service in a manner 
comparable to the way customers redirect point-to-point service. Unlike 
point-to-point service, network service involves no identified contract 
path and thus is not a directable service. A network customer seeking 
to substitute one resource for another already has the ability under 
the pro forma OATT to terminate its existing designation and designate 
a new resource on an as-available basis. If necessary, the network 
customer may then request to redesignate its original network resource 
by making a request to designate a new network resource. Alternatively, 
the network customer could use secondary network service if it wants to 
substitute a non-designated network resource for a designated network 
resource on an as-available basis.
    1294. For similar reasons, the Commission denies Alberta 
Intervenors' request. The Commission has explained that customers must 
choose between point-to-point and network services, each of which has 
its own advantages and risks.\788\ The Commission declined to implement 
a single form of transmission service in Order No. 888, concluding that 
point-to-point and network services are the appropriate base-line 
services under the pro forma OATT, and Alberta Intervenors offer no 
justification for departing from that approach now. Alberta Intervenors 
parking and hubbing related arguments alleging that network service is 
commonly used to purchase power intended for sales to third parties is 
addressed in section V.D.7 of this Final Rule. Although we deny Alberta 
Intervenors' request, we expect that the reforms adopted in this Final 
Rule will provide point-to-point customers with increased service 
options and flexibility.
---------------------------------------------------------------------------

    \788\ Order No. 888-A at 30,260.
---------------------------------------------------------------------------

    1295. Implementing Imperial's proposal would prevent customers from 
redirecting for a short period or periods of time and then redirecting 
back to their original points, making redirects a less valuable option 
for customers. Multiple redirects are allowed only if the customer can 
meet the scheduling and other requirements for new requests for service 
under the pro forma OATT. As long as the customer meets these 
requirements, the Commission believes that the ability to redirect 
service does not present an unreasonable burden to transmission 
providers. As for applicability to RTOs and ISOs, we explain our 
compliance requirements in section IV.C of this Final Rule. To the 
extent an RTO's or ISO's redirect policy does not conform to the pro 
forma OATT, as amended by this Final Rule, the RTO or ISO must 
demonstrate that its policy is consistent with or superior to the pro 
forma provisions in accordance with the compliance procedures set forth 
in that section.
5. Acquisition of Transmission Service
a. Processing of Service Requests
    1296. The pro forma OATT includes requirements that transmission 
providers process requests for transmission service in a timely 
fashion. Section 17.5 (Response to a Completed Application) and section 
18.4 (Determination of Available Transmission Capability) of the pro 
forma OATT provide that following the receipt of a completed 
application for service, the transmission provider must respond to 
transmission customer requests for determinations of the availability 
of firm and non-firm transmission capacity on a timely basis. The 
transmission provider must make the determination as soon as reasonably 
practicable after receipt but no later than certain specified time 
periods (or such time periods generally accepted in the region).
    1297. Section 19 (Additional Study Procedures for Firm Point-to-
Point Transmission Service Requests) of the pro forma OATT provides 
deadlines that transmission providers must adhere to in issuing system 
impact study agreements and facilities studies agreements and that 
transmission customers must abide by in responding to these study 
agreements. Section 19 requires transmission providers to use due 
diligence to complete system impact studies and facilities studies 
within 60 days. Section 32 of the pro forma OATT (Additional Study 
Procedures for Network Integration Transmission Service Requests) 
contains similar due diligence deadlines for completing system impact 
studies and facilities studies associated with requests for network 
service.
(1) Posting Performance Metrics
NOPR Proposal
    1298. In the NOPR, the Commission proposed to require transmission 
providers to post on their OASIS sites metrics that track their 
performance in processing system impact studies and facilities studies 
associated with requests for transmission service. The Commission 
proposed that transmission providers calculate the proposed performance 
metrics separately for affiliates and non-affiliates and for requests 
for short-term and long-term transmission service.
    1299. In addition, the Commission proposed to require a 
notification filing and the posting of additional metrics if a 
transmission provider completes more than 20 percent of non-affiliates' 
studies outside of the 60-day due diligence deadline in the pro forma 
OATT for two consecutive quarters. Starting the quarter after a 
notification filing, the transmission provider would be required to 
post the following information on OASIS: (1) The average, across 
completed system impact studies, of the employee-hours expended per 
completed system impact study, (2) the average, across completed 
facilities studies, of employee-hours expended per completed facilities 
study, (3) the number of employees devoted to processing system impact 
studies, and (4) the number of employees devoted to processing 
facilities studies. The Commission proposed that transmission providers 
post these additional performance metrics until they process at least 
90 percent of all system impact and facilities studies within 60 days 
after the study agreement has been executed. The additional performance 
metrics also would be calculated separately for affiliates' and non-
affiliates' requests for transmission service and for short-term and 
long-term transmission service.
Comments
Standard Performance Metrics
    1300. Transmission customers and a number of other commenters 
generally support or do not oppose the Commission's proposal to require 
transmission providers to post performance metrics.\789\
---------------------------------------------------------------------------

    \789\ E.g., ELCON, Suez Energy NA, Powerex, Seattle, TAPS, 
Constellation, Entegra, NRECA, TDU Systems, Regional Electricity 
Committee, MISO, MidAmerican, FirstEnergy, Tacoma, EEI, Nevada 
Companies, and TranServ.
---------------------------------------------------------------------------

    1301. Southern and Salt River oppose the proposal, arguing that 
most of the data needed to compute the metrics is already available on 
OASIS. Southern asserts that the NOPR does not explain why the 
currently available information is inadequate or how the proposed 
metrics would not be duplicative and, thus, does not fully justify the 
need for reform. Southern also argues that the Commission's proposal 
will impose

[[Page 12434]]

costs and burdens on transmission providers, and ultimately those who 
use their services, that do not correspond with the limited benefits 
that might be gained. Salt River believes that performance tracking 
requirements should be established on a case-by-case basis in response 
to complaints. NorthWestern believes the 60 days should be a target, 
but not a deadline, and, as such, transmission providers should not be 
required to report performance metrics that summarize the time they 
take to perform the studies.
    1302. Several commenters requested clarification on certain 
features of the Commission's proposal. Nevada Companies asks the 
Commission to be very specific as to what statistical data items are to 
be reported on the OASIS so that transmission providers do not 
inadvertently violate the confidentiality of their transmission 
customers. PNM-TNMP requests clarification that the standards set out 
in the NOPR are solely applicable to processing of transmission 
delivery service requests, and not to interconnection service requests. 
Insofar as the Commission determines that performance metrics should be 
posted, Southern asks the Commission to clarify that the proposed 
posting of performance metrics also would be required of RTOs and ISOs.
    1303. A number of commenters suggest that the Commission modify the 
performance metrics that transmission providers are required to post. 
EEI suggests that NAESB develop the metrics that transmission providers 
are required to post, using the metrics contained in the NOPR as 
guidance. EEI and MidAmerican suggest that the performance metrics 
include information about the degree to which transmission customers 
delay the study process. MISO suggests that transmission providers post 
metrics related to the time transmission customers take to respond to 
the results of completed system impact studies and facilities studies. 
Southern asserts that fewer metrics should be required and that they 
should relate directly to the study-timing concerns raised in the NOPR. 
Bonneville and MISO argue that transmission providers should not have 
to post information about the cost of transmission system upgrades 
recommended in the request studies. Bonneville believes that the 
average cost of recommended upgrades is misleading because it will mask 
the wide variation in such costs. MISO suggests that transmission 
providers also report the standard deviation for study completion 
times. Southern asserts further that the OATT does not specifically 
provide for a system impact study or facilities study to be performed 
on a short-term basis, so any metrics required as part of OATT reform 
should not include short-term requests. CREPC suggests that performance 
metrics be calculated separately for renewable resources.
    1304. Several commenters suggest that transmission providers post 
additional information to further enhance transparency. A number of 
commenters suggest that the Commission require the posting of the 
disposition of all transmission service requests, including those not 
requiring studies.\790\ TDU Systems suggest that the Commission require 
transmission providers to post the parameters of each denied request. 
MISO suggests that transmission providers provide a narrative to 
explain any anomalous study costs that may affect the posted average 
cost. If a transmission provider anticipates that it will miss the 
study deadline date, NRECA suggests that it should post that 
information, the expected finish date, and a reason for not being able 
to meet the deadline.
---------------------------------------------------------------------------

    \790\ E.g., CREPC, MISO, Constellation, and TDU Systems.
---------------------------------------------------------------------------

    1305. EEI recommends that the Commission delegate to NAESB the 
responsibility for developing the Standard and Communications 
Protocols, business practices and OASIS modifications that will be 
necessary to provide the metrics.
Additional Performance Metrics (After Two Quarters of Late Studies)
    1306. EEI and Southern oppose the Commission's proposal to require 
transmission providers that fail to complete studies in a timely manner 
to post additional performance metrics that measure the labor input 
used to complete studies. EEI asserts that there is little value to be 
gained from posting the additional information that the Commission 
proposes. EEI believes the information concerning the number of 
employees who perform studies will not be determinative of 
responsibility for the delay because the significant issue is whether 
the number of studies that the transmission provider is required to 
perform or the total amount of time needed to perform studies has 
increased significantly or whether customers caused the delays. 
Southern questions the Commission's legal authority to require 
transmission providers that do not complete studies in a timely manner 
to post additional performance metrics, citing Cal. Ind. Sys. Operator 
Corp. v. FERC.\791\ Southern characterizes the Commission's proposal as 
a punishment for delays in processing request studies.
---------------------------------------------------------------------------

    \791\ 372 F.3d 395, 404 (D.C. Cir. 2004).
---------------------------------------------------------------------------

    1307. Several other commenters suggest changes to the Commission's 
proposal. Southern believes the submission of a notification of 
extenuating circumstances should suspend the obligation to post the 
additional metrics proposed in the NOPR. EEI and Southern argue that 
the Commission should be certain that it is collecting such information 
only from those transmission providers that, for no other reason except 
themselves, fail to consistently evaluate studies within the 60-day due 
diligence period. Therefore, if a transmission provider demonstrates 
that delays in completing studies are due to extenuating circumstances, 
then EEI and Southern believe the Commission should not require the 
transmission provider to post the additional metrics. MISO believes the 
Commission should exempt RTOs from the additional employee performance 
metrics proposed in the NOPR for the same reason that the Commission 
proposed to exempt RTOs from operational penalties for untimely 
completion of studies, as MISO claims the additional posting 
requirements are in the nature of penalty. Bonneville believes the 
proposed metrics will be misleading whenever a transmission provider 
employs outside consultants to perform or assist with studies. 
Therefore, Bonneville suggests that the Commission add two other 
metrics, the number of studies performed entirely by consultants and, 
in the case of studies performed by a combination of employees and 
consultants, the average percentage of the study performed by 
consultants.
Commission Determination
Standard Performance Metrics
    1308. The Commission will require transmission providers to post 
the performance metrics proposed in the NOPR, as modified by this Final 
Rule. The proposed metrics will enhance the transparency of the study 
process and shed light on whether transmission providers are processing 
request studies in a non-discriminatory manner. We also agree with 
comments by MidAmerican and EEI that transmission providers should be 
able to track delays in the study process caused by transmission 
customers. Doing so will allow the Commission and market participants 
to determine the extent to which delays by transmission customers are 
causing transmission providers to process request studies on an 
untimely basis, which will add needed transparency to the study 
process.

[[Page 12435]]

Therefore, we will revise the performance metrics transmission 
providers are required to post to include metrics that track delays by 
transmission customers.
    1309. Transmission providers will be required to post the 
performance metrics, outlined below, for each calendar quarter. 
Transmission providers will be required to begin tracking their 
performance upon the effective date of this Final Rule and keep the 
quarterly performance metrics posted on their OASIS sites for three 
calendar years. The transmission provider will be required to post the 
quarterly performance metrics within 15 days of the end of the quarter. 
The performance metrics outlined below must be calculated separately 
for affiliates' and non-affiliates' requests, in order to identify 
potential instances when the transmission provider is processing 
requests on a discriminatory basis. The transmission provider is 
required to aggregate studies associated with requests for short-term 
and long-term transmission service when calculating the metrics defined 
below. While a transmission provider could offer to study a request for 
short-term firm point-to-point transmission service, we acknowledge 
that the transmission customer often is unwilling to pay for such a 
study. Therefore, to ease the reporting burden, the transmission 
provider is not required to report the performance metrics defined 
below separately for requests for short-term and long-term firm point-
to-point transmission service. A transmission provider is also required 
to post performance metrics for studies that it conducts for RTOs.
    1310. A transmission provider is required to post the following set 
of performance metrics on a quarterly basis:
     Process time from initial service request to offer of 
system impact study agreement pursuant to sections 17.5, 19.1 and 32.1 
of the pro forma OATT

    [cir] Number of new system impact study agreements delivered to 
transmission customers
    [cir] Number of new system impact study agreements delivered to the 
transmission customer more than 30 days after the transmission customer 
submitted its request
    [cir] Average time (days) from request submittal to change in 
request status
    [cir] Average time (days) from request submittal to delivery of 
system impact study agreement
    [cir] Number of new system impact study agreements executed

     System impact study processing time pursuant to sections 
19.3 and 32.3 of the pro forma OATT

    [cir] Number of system impact studies completed
    [cir] Number of system impact studies completed more than 60 days 
after receipt of executed system impact study agreement
    [cir] Average time (days) from receipt of executed system impact 
study agreement to date when completed system impact study made 
available to the transmission customer
    [cir] Average cost of system impact studies completed during the 
period

     Service requests withdrawn from system impact study queue
    [cir] Number of requests withdrawn from the system impact study 
queue
    [cir] Number of system impact studies withdrawn more than 60 days 
after receipt of executed system impact study agreement
    [cir] Average time (days) from receipt of executed system impact 
study agreement to date when request was withdrawn from the system 
impact study queue

     For all system impact studies completed more than 60 days 
after receipt of executed system impact study agreement, average number 
of days study was delayed due to transmission customer's actions (e.g., 
delays in providing needed data)
     Process time from completed system impact study to offer 
of facilities study pursuant to sections 19.4 and 32.4 of the pro forma 
OATT

    [cir] Number of new facilities study agreements delivered to 
transmission customers
    [cir] Number of new facilities study agreements delivered to 
transmission customers more than 30 days after the completion of the 
system impact study
    [cir] Average time (days) from completion of system impact study to 
delivery of facilities study agreement
    [cir] Number of new facilities study agreements executed

     Facilities study processing time pursuant to sections 19.4 
and 32.4

    [cir] Number of facilities studies completed
    [cir] Number of facilities studies completed more than 60 days 
after receipt of executed facilities study agreement
    [cir] Average time (days) from receipt of executed facilities study 
agreement to date when completed facilities study made available to the 
transmission customer
    [cir] Average cost of facilities studies completed during the 
period
    [cir] Average cost of recommended upgrades for facilities studies 
completed during the period

     Service requests withdrawn from facilities study queue

    [cir] Number of requests withdrawn from the facilities study queue
    [cir] Number of facilities studies withdrawn more than 60 days 
after receipt of executed facilities study agreement
    [cir] Average time (days) from receipt of executed facilities study 
agreement to date when request was withdrawn from the facilities study 
queue

     For all facilities studies completed more than 60 days 
after receipt of executed facilities study agreement, average number of 
days study was delayed due to transmission customer's actions (e.g., 
delays in providing needed data).
    1311. In response to Nevada Companies request that we clarify the 
statistical data items that are to be reported on OASIS pursuant to the 
Commission's proposal, we reiterate that transmission providers are 
required to provide summary data as defined above. We do not believe 
these data will violate the confidentiality of any transmission 
customer, even in the event the transmission provider has worked on a 
limited number of studies. We clarify that the performance metrics 
posting requirement discussed above is solely applicable to processing 
of transmission delivery service requests, and not to interconnection 
service requests. Finally, we clarify that RTOs and ISOs also are 
required to post the performance metrics described above. As we discuss 
below, we believe all transmission providers should be subject to the 
same reporting requirements.
    1312. We disagree with Southern and Salt River which argue that the 
data already on OASIS is sufficient to accomplish our goal to enhance 
transparency of the transmission provider's request study processing. 
First, the data available on the OASIS template transstatusaudit does 
not contain the information necessary to calculate all of the 
performance metrics proposed in the NOPR.\792\ For instance,

[[Page 12436]]

transstatusaudit allows one to determine when a request was moved from 
``received'' to ``study'' and then to ``accepted'' or ``counteroffer''. 
Depending on when the transmission provider moves the request into 
``study,'' this information does not allow one to determine either 
whether the transmission provider provided a system impact study 
agreement within 30 days or whether the transmission provider completed 
the system impact study within 60 days. In addition, the transmission 
provider is required to make the data in transstatusaudit available on 
OASIS for only 90 days and available by request for three years.\793\ 
As a result, market participants would be required to calculate the 
performance metrics they desire on a quarterly basis if they want to 
use just the data posted on OASIS. Finally, downloading 
transstatusaudit data for specific OASIS requests that required a 
system impact study or feasibility study can be cumbersome due to the 
manual nature of the download process. The transmission provider has 
the data necessary to calculate the proposed performance metrics 
readily available. We believe it is more efficient for a single 
transmission provider to calculate the performance metrics for its 
system rather than have multiple interested parties calculate the 
performance statistics for each transmission provider of interest.
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    \792\ The OASIS template transstatusaudit is defined in the 
Standards and Communications Protocols section of NAESB's WEQ 
Business Practice Standards. The template transstatusaudit is the 
audit component to OASIS template transstatus and, as such, contains 
information regarding the type of transmission service requested, 
affiliate status, date and time the transmission service was 
requested, and the date and time of all changes in request status 
(e.g., place in study mode, confirmed or withdrawn).
    \793\ 18 CFR 37.7(b).
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    1313. We also disagree with Southern's assertion that the costs and 
burdens to transmission providers are not justified by the benefits 
that might be gained. We are concerned that, under the existing pro 
forma OATT, transmission providers do not have adequate incentives to 
conduct studies on a timely and nondiscriminatory basis. First, 
transmission providers have incentives to discriminate against third 
parties and in favor of their affiliates (i.e., to delay the study 
requests of nonaffiliates, but act more quickly on those of its 
affiliates). Second, transmission providers also can lack incentives to 
provide sufficient staff resources to support increasing demands in the 
study process. Given that most of the costs associated with the study 
process are operational, transmission providers, at most, will recover 
those costs without profit (i.e., a return) and, if the demands of the 
study process are increasing, fail to recover such cost increases if 
the transmission provider is between rate cases. We therefore believe 
that there are several reasons that greater transparency is required to 
provide the correct incentives to comply with the pro forma OATT 
provisions respecting studies.
    1314. We also note that virtually all commenters agree with our 
proposal to require transmission providers to calculate the above 
performance metrics. This support stems, in part, from transmission 
customers' perception that transmission providers do not exert 
sufficient effort to complete requests in a timely manner.\794\ Delays 
in processing study requests can cause customers to incur material 
financial damage. Moreover, the data needed to calculate the required 
performance statistics is readily available to the transmission 
provider and, therefore, the cost to the transmission provider will be 
small relative to the benefits of enhanced transparency and assurance 
that the transmission provider is processing request studies in a 
timely and non-discriminatory fashion.
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    \794\ E.g., Constellation, EPSA NOI Comments, Arkansas Cities 
NOI Comments, APPA NOI Reply Comments, and Powerex NOI Reply 
Comments 795 As noted in P 1318, we direct public utilities working 
through NAESB to develop protocols for posting the performance 
metrics required here so they will be posted in a consistent 
fashion.
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    1315. Based on our experience and the comments received in response 
to the NOI and NOPR, the Commission believes the steps we take here are 
necessary to increase transparency for the processing of service 
requests by all transmission providers. It would be inappropriate, as 
some commenters suggest, to wait for specific complaints about specific 
transmission providers before requiring the transmission provider to 
calculate the performance metrics defined above. We conclude that the 
reporting requirements adopted in this Final Rule must be applied to 
all transmission providers in order to enhance the transparency of the 
study process and ensure that transmission provider processes study 
requests in a timely and non-discriminatory fashion for all 
transmission customers. The fact that the 60-day timeframe in the pro 
forma OATT is a target and not a deadline does not change the fact that 
requiring all transmission providers to post the performance metrics 
defined above will enhance the transparency of the study process.
    1316. We will not adopt any of the changes to the proposed 
performance metrics requested by commenters, other than adding metrics 
to track delays by customers as discussed above. The Commission is in a 
better position to determine the specific performance metrics that will 
achieve our policy goals and thus we will not request that NAESB 
develop the metrics to be posted.\795\ We believe the set of 
performance metrics we have chosen strike the appropriate balance 
between requiring information that will enhance transparency and help 
ensure that the transmission provider is processing request studies in 
a timely and non-discriminatory fashion while limiting the burden the 
transmission provider faces. For instance, we believe the performance 
metrics that address the cost of system impact studies and facilities 
studies as well as the cost of any proposed transmission upgrades can 
be calculated with relatively little effort by the transmission 
provider and should provide meaningful benefits to transmission 
customers. The transmission provider readily knows the cost of studies 
it completes and the costs of proposed system upgrades and summaries of 
this information should enhance the transmission customer's ability to 
decide whether to submit a request for service that may result in a 
study offer.
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    \795\ As noted in P 1318, we direct public utilities working 
through NAESB to develop protocols for posting the performance 
metrics required here so they will be posted in a consistent 
fashion.
---------------------------------------------------------------------------

    1317. We do not believe the relative benefits and burdens justify 
requiring the transmission provider to post performance metrics beyond 
those adopted in this Final Rule. For instance, requiring the 
transmission provider to calculate additional summary information or 
post long narratives to explain anomalous upgrade costs do not appear 
necessary at this time to achieve our stated policy goals, particularly 
since transmission customers can request data associated with completed 
system impact studies and facilities studies pursuant to section 
37.6(b)(2)(iii) of the Commission's regulations.\796\ In addition, we 
do not believe transmission customers, beyond the transmission customer 
directly affected, would benefit from the information NRECA suggests 
the transmission provider should be required to post when it 
anticipates that it will not complete a study within the 60-day due 
diligence timeframe. Section 19.3 of the pro forma tariff already 
requires the transmission provider to notify the affected transmission 
customer when it will not be able to complete a study within the 60-day 
due diligence timeframe, provide an expected completion date, and 
explain why additional time is needed. We do

[[Page 12437]]

not believe other transmission customers would benefit enough from this 
information to justify requiring the transmission provider to post it. 
Similarly, we do not believe the benefit to market participants 
justifies the burden of requiring transmission providers to calculate 
performance metrics separately for renewable resources.
---------------------------------------------------------------------------

    \796\ 18 CFR 37.6(b)(2)(iii).
---------------------------------------------------------------------------

    1318. We agree, however, with EEI's recommendation that the 
Commission delegate to NAESB the responsibility for developing the 
Standard and Communications Protocols, business practices and OASIS 
modifications that will be necessary to provide the performance metrics 
adopted above. NAESB is in the best position to develop the standards 
and the processes by which the performance metrics are posted.
Additional Performance Metrics (after two quarters of late studies)
    1319. The Commission also adopts the NOPR proposal to require 
transmission providers to submit a notification filing with the 
Commission in the event the transmission provider processes more than 
20 percent of non-affiliates' studies outside of the 60-day due 
diligence deadlines in the pro forma OATT for two consecutive quarters. 
This filing must be filed within 30 days of the end of the second 
quarter during which the transmission provider processes more than 20 
percent of non-affiliates' studies outside of the 60-day due diligence 
deadlines in the pro forma OATT. For the purposes of calculating this 
notification trigger, the transmission provider is required to 
aggregate all system impact studies and facilities studies that it 
completes during the quarter for non-affiliates.\797\ The transmission 
provider may explain in its notification filing that it believes there 
are extenuating circumstances that prevented it from meeting the 
deadlines in the pro forma OATT.
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    \797\ For instance, if the transmission provider completes 4 
non-affiliates' system impact studies during the quarter with 2 
completed more than 60 days after the system impact study agreement 
was executed and completes 2 non-affiliates' facilities studies 
during the quarter with none completed more than 60 days after the 
facilities study agreement was executed, then the transmission 
provider will be deemed to have completed 2 out of 6 (33 percent) 
studies outside of the deadlines in the pro forma OATT.
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    1320. As the Commission proposed in the NOPR, starting the quarter 
following a notification filing, the transmission provider will be 
required to post: (1) The average, across completed system impact 
studies, of the employee-hours expended per completed system impact 
study; (2) the average, across completed facilities studies, of 
employee-hours expended per completed facilities study; (3) the number 
of employees devoted to processing system impact studies; and (4) the 
number of employees devoted to processing facilities studies. The 
transmission provider is not required to post these additional 
performance metrics separately for affiliates' and non-affiliates' 
requests for transmission service and for short-term and long-term 
transmission service. The transmission provider is instead required to 
aggregate studies associated with requests for short-term and long-term 
transmission service when calculating these additional metrics. The 
transmission provider is not required to post the additional metrics if 
the Commission concludes that delays in completing studies are due to 
extenuating circumstances. However, the transmission provider is 
required to post the additional metrics while the Commission considers 
the transmission provider's notification filing arguing that 
extenuating circumstances prevented it from processing request studies 
on a timely basis. Based on the timing described in this Final Rule, 
the transmission provider will be required to post the additional 
performance metrics approximately two months after the provider makes 
its notification filing. The Commission will have this time to evaluate 
the transmission provider's contention that it was unable to complete 
request studies due to extenuating circumstances. As a result, we 
expect the transmission provider with legitimate extenuating 
circumstances typically will not have to post any additional metrics.
    1321. We disagree with those arguing that information concerning 
the number of employees who perform studies will not be determinative 
of responsibility for the delay. The transmission provider will have 
the right to establish that it is unable to perform studies in a timely 
manner because of factors outside its control. We received a number of 
comments to the NOPR and NOI that suggest that transmission customers 
believe transmission providers fail to complete studies on a timely 
basis because they do not have sufficient staff to perform the 
studies.\798\ As explained above, this is one of the concerns that has 
led us to adopt these reforms. The additional metrics will serve to 
shed light on the transmission provider's resource commitment, enhance 
the transparency of the study process, and increase the transmission 
provider's incentive to staff its study function appropriately.
---------------------------------------------------------------------------

    \798\ E.g., Constellation, EPSA NOI Comments, Arkansas Cities 
NOI Comments, APPA NOI Reply Comments, and Powerex NOI Reply 
Comments.
---------------------------------------------------------------------------

    1322. The additional posting requirement is not a penalty or a 
punishment. We opted not to require the transmission provider to post 
these additional performance metrics on a regular basis out of a desire 
to limit the transmission provider's reporting burden. However, once 
the transmission provider has stopped completing studies on a timely 
basis, we believe the enhanced transparency justifies the additional 
reporting burden. As a result, ISOs and RTOs also will be required to 
post the additional performance metrics described above. We disagree 
with Southern's argument that we lack jurisdiction to require 
additional posting. The posting requirements are directly related to 
pro forma OATT obligations that are necessary to remedy undue 
discrimination and, hence, necessarily derive from our broad discretion 
in fashioning remedies to undue discrimination. We are not attempting 
to dictate a transmission provider's internal staffing decisions; 
rather, we illuminate the transmission provider's compliance with its 
pro forma OATT obligations to perform studies within certain deadlines 
and on a nondiscriminatory basis.
    1323. We will not add the two other metrics suggested by Bonneville 
regarding the number of studies performed entirely by consultants and, 
in the case of studies performed by a combination of employees and 
consultants, the average percentage of the study performed by 
consultants. Rather, transmission providers should include the time 
spent by consultants on studies in the performance metrics defined 
above.
(2) Operational Penalties for Late Studies
NOPR Proposal
    1324. The Commission proposed to impose operational penalties when 
transmission providers routinely fail to meet the 60-day due diligence 
deadlines prescribed in sections 19.3, 19.4, 32.3 and 32.4 of the pro 
forma OATT. Under the proposal, a transmission provider who processes 
more than 20 percent of non-affiliates' studies outside of the 60-day 
due diligence deadlines in the pro forma OATT for two consecutive 
quarters would be required to notify the Commission. In this 
notification filing, the transmission provider may explain that it 
believes there are extenuating circumstances that prevented it from 
meeting the deadlines in the pro forma OATT. The transmission provider

[[Page 12438]]

would be subject to an operational penalty if it continues to be out of 
compliance \799\ with the deadlines prescribed in the pro forma OATT 
for each of the two quarters following its notification filing.
---------------------------------------------------------------------------

    \799\ The transmission provider would be deemed to be out of 
compliance if it completes 10 percent or more of non-affiliates' 
system impact studies and facilities studies outside of the 
deadlines prescribed in the pro forma OATT.
---------------------------------------------------------------------------

    1325. The Commission proposed that the operational penalty be 
assessed on a quarterly basis, starting with the quarter following the 
notification filing and continuing until the transmission provider 
completes at least 90 percent of all studies within 60 days after the 
study agreement has been executed. For any system impact study or 
facilities study completed during that quarter and more than 60 days 
after the study agreement was executed, the Commission proposed a 
penalty equal to $500 for each day the transmission provider takes to 
complete the study beyond 60 days. For any system impact study or 
facilities study that is still pending at the end of the quarter and 
that has been in the study queue for more than 60 days, the Commission 
proposed a penalty equal to $500 for each day the study has been in the 
study queue beyond 60 days.
    1326. In addition to the proposed operational penalties, the 
Commission indicated that it would order other remedial actions, 
consistent with the Policy Statement on Enforcement, to be determined 
on a case-by-case basis. The Commission proposed that RTOs not be 
subject to this penalty regime because of the RTOs' independence.
Comments
    1327. Transmission providers generally oppose the Commission's 
proposal.\800\ Some opponents argue that, to the extent the Commission 
is going to impose penalties, it should do so on a case-by-case 
basis.\801\ Opponents cite a number of reasons the Commission should 
not impose the proposed operational penalty regime. Several opponents 
caution that imposing a penalty may lead transmission providers to 
either prematurely deny a request or accept a request to the detriment 
of system reliability.\802\ Several opponents argue that many 
transmission requests introduce unique complexities into the study 
process, so a firm 60-day deadline is not workable in practice.\803\ 
Several opponents argue that the Commission's proposed penalty regime 
is inconsistent with the new requirements the Commission has proposed 
for regional planning and requirements to consider redispatch in the 
system impact study.\804\ In its reply comments, EEI argues that due 
process requires that the Commission not impose penalties on 
transmission providers for study delays because, in EEI's view, it is 
highly likely that the delays will have been caused by factors or 
events that were beyond the transmission provider's control. Southern 
asserts that any scheme of operational penalties associated with the 
processing of studies cannot be implemented fairly unless and until the 
problem surrounding the submission of multiple requests is addressed. 
Southern argues that the Commission would violate a transmission 
provider's due process rights if it were to impose penalties for delays 
caused by transmission customers. CREPC proposes that transmission 
projects that cross seams not be subject to penalties, arguing that 
such an exception will create a level playing field for those 
transmission providers in the West working with the CAISO and foreign 
transmission owners to resolve transmission service requests.
---------------------------------------------------------------------------

    \800\ E.g., EEI, MidAmerican, Entergy, Southern, Imperial, 
NorthWestern, PNM-TNMP, Salt River, and Bonneville Reply.
    \801\ E.g., EEI, Southern, and PNM-TNMP Reply.
    \802\ E.g., MidAmerican, Southern, Imperial, and EEI Reply.
    \803\ E.g., MidAmerican, Southern, NorthWestern, Northwest IOUs, 
and PNM-TNMP Reply.
    \804\ E.g., MidAmerican, Southern, and EEI Reply.
---------------------------------------------------------------------------

    1328. A number of commenters ask the Commission to clarify specific 
elements of the proposed operational penalty regime. Several commenters 
argue that the proposal does not clearly provide for an exemption from 
operational penalties if the failure to meet the timeliness criteria is 
a result of extenuating circumstances or customer caused delays, 
thereby denying transmission providers due process.\805\ Several 
commenters ask the Commission to clarify that a transmission provider 
is not subject to operational penalties if the transmission provider's 
failure to meet the compliance threshold following its notification 
filing is due to extenuating circumstances.\806\ Southern asks that the 
Commission clarify that the submission of a notification of extenuating 
circumstances would suspend the obligation of a transmission provider 
to process at least 90 percent of the study requests within the 
proposed deadlines, until such time as the Commission issues a final 
determination on the notification of extenuating circumstances. Tacoma 
asks the Commission to ensure that the processing time is measured from 
the point that the customer provides complete information.
---------------------------------------------------------------------------

    \805\ E.g., EEI, Southern, Northwest IOUs, and MidAmerican.
    \806\ E.g., EEI and MidAmerican.
---------------------------------------------------------------------------

    1329. EEI recommends that the Commission hold a technical 
conference to determine the extent to which studies are not being 
completed within 60 days, the principal causes of delays in completing 
studies within 60 days and whether the increased planning and 
coordination requirements proposed by the Commission will result in 
additional time being needed to complete the studies. EEI believes the 
Commission is far more likely to arrive at a reasonable conclusion 
concerning these issues after a technical conference than if it simply 
imposes penalties for failures to complete all studies within 60 days. 
Seattle believes the proposed penalties should not be implemented until 
providers and customers have had at least one year of experience 
working with the performance metrics.
    1330. Transmission customers generally support the Commission's 
proposal to impose operational penalties when a transmission provider 
routinely fails to meet the 60-day due diligence deadlines.\807\ In its 
reply comments, Entegra argues that the question is not whether a 
transmission provider has sufficient margins of flexibility, but 
whether the transmission provider has any stake in meeting the 
deadlines. Occidental argues that transmission providers may have 
little incentive to meaningfully address customers' issues without the 
prospect of a prospective remedy. Responding to EEI's due process 
argument, TDU Systems in reply assert that imposition of penalties in 
this instance raises no more due process concerns than those 
operational penalties that transmission customers are routinely 
subjected to under the OATT. TDU Systems argue that, should the 
Commission determine that transmission providers are entitled to 
challenge any operational penalty for failure to process service 
requests in a timely manner, then those challenges must be on terms and 
conditions that are comparable to those available to transmission 
customers--a complaint pursuant to FPA section 206. TDU Systems believe 
that the proposed ``explanatory statement'' contemporaneous with any 
notification filing is a form of expedited review that is clearly not 
comparable to the treatment of customers under the tariff.
---------------------------------------------------------------------------

    \807\ E.g., Suez Energy NA, TAPS, Constellation, Entegra, TDU 
Systems, CREPC, and Nevada Companies.

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[[Page 12439]]

    1331. Several transmission customers question whether the proposed 
penalty level is sufficient to ensure compliance.\808\ Constellation 
recommends a penalty of up to $10,000 per day per violation. Entegra 
suggests the Commission set the penalty equal to the higher of the lost 
opportunity cost to the customer resulting from the delay, if any, or 
$1,000 for each day. Entegra also suggests that penalties should be 
assessed automatically, without a notification filing to the 
Commission. In its reply comments, EEI argues that the total penalty 
for delayed studies will be far higher than $500 per day if the 
transmission provider is processing more than five requests per 60-day 
period, which EEI asserts is extremely likely.
---------------------------------------------------------------------------

    \808\ E.g., TAPS, Constellation, and Entegra.
---------------------------------------------------------------------------

    1332. Constellation asks the Commission to consider whether to 
require the transmission provider to engage an independent transmission 
administrator to the extent a transmission provider's posted 
performance metrics are not accurate or the transmission provider 
persistently fails to adhere to the relevant timelines.
    1333. Several commenters suggest that the Commission extend the 
study completion deadlines, such as to 120 or 180 days, at least for 
the purposes of assessing penalties.\809\ Bonneville suggests that the 
Commission change the service request study process to match the 
interconnection study process as articulated in the Large Generator 
Interconnection Procedures. Imperial recommends that instead of 
mandating a nationwide study schedule, each of the NERC regions should 
establish a schedule taking into account the various needs of the 
region. Southern suggests restarting the 60-day due diligence period 
for any study that experiences a delay that cannot properly be 
attributed to the transmission provider. In contrast to the suggestions 
to increase the study time, Entegra suggests that the Commission 
consider changing the due diligence deadlines to 30 days to further the 
goal of encouraging timeliness in completing required studies.
---------------------------------------------------------------------------

    \809\ E.g., Bonneville, MidAmerican, Progress Energy, 
NorthWestern, Northwest IOUs, and EEI Reply.
---------------------------------------------------------------------------

    1334. Several commenters suggest methods for distributing the 
operational penalties the transmission provider pays for late studies. 
TAPS believes that penalty revenues should go to victims of study 
delay. Similarly, Entegra believes the penalty should take the form of 
a credit against the transmission customer's obligation to reimburse 
the transmission provider for study costs, with any amount in excess of 
the study costs payable to the transmission customer, in recognition of 
the harm to transmission customers when required studies are not 
completed expeditiously. CREPC asks the Commission to clarify how it 
plans to determine which unaffiliated transmission customers will 
receive operational penalty payments. CREPC also asks the Commission 
whether the $500 per day penalty is a flat rate that would be pro-rated 
among eligible non-offending, unaffiliated transmission customers or if 
the $500 is a rate paid to each eligible transmission customer.
    1335. Commenters affiliated with RTOs and one transmission customer 
support the Commission's proposal to exempt RTOs from penalties for 
late studies.\810\ MISO asserts that RTOs do not have incentives to 
delay the processing of transmission service requests, as they have no 
affiliates to favor and because their Commission-approved design and 
internal procedures ensure their independence. MISO argues further that 
all transmission service requests benefit some RTO member and, as a 
result, RTOs have no disincentive to approve service so long as 
reliability is maintained. MISO/PJM States asserts that the NOPR 
proposal to exempt RTOs from operational penalties for late studies is 
appropriate because a penalty does not serve a useful purpose with 
respect to RTOs. TDU Systems state that an RTO should not be 
financially penalized for late studies because RTO independence should 
minimize incentives for affiliate preference and RTO members indirectly 
pay for all RTO incurred costs in any event.
---------------------------------------------------------------------------

    \810\ E.g., MISO, MISO/PJM States, TDU Systems, and Indianapolis 
Power Reply.
---------------------------------------------------------------------------

    1336. Most of those commenters not affiliated with an RTO oppose 
the proposal to exempt RTOs from penalties for late studies.\811\ 
Southern argues that given that the Commission is seeking to increase 
transparency in the system, the Commission would undercut that goal by 
omitting a significant segment of the industry. TAPS argues that RTOs 
may still fail to complete studies on a timely basis due to competing 
internal priorities or bureaucratic indifference. Progress notes that 
the Commission has found that RTOs and ISOs should be subject to 
penalties for failure to meet reliability standards. Salt River argues 
that RTOs should be subject to operational penalties because the impact 
on the customer is identical if the request processing deadline is not 
met regardless of the type of provider conducting the study. Xcel notes 
that, historically, transmission owners need to complete facility 
studies in concert with RTOs, thereby giving the customer the most up-
to-date and coordinated analysis. Consequently, Xcel believes it is 
imperative that both transmission owners and RTOs operate under the 
same rules, reporting obligations, and performance metrics in the OATT.
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    \811\ E.g., Southern, TAPS, Progress Energy, Salt River, and 
Xcel.
---------------------------------------------------------------------------

    1337. In its reply comments, WPS disagrees with the Commission's 
proposal to exempt RTOs from penalties for their repeated failure to 
meet the 60-day due diligence requirements. WPS asserts that the 
Commission should impose penalties and prohibit the recovery of 
associated revenue where appropriate. WPS argues that RTO independence 
does not guarantee RTO competence or compliance in every instance. WPS 
believes imposing reporting obligations and penalties for failure to 
comply with tariff requirements, particularly tariff deadlines, will 
help to motivate compliance by ensuring that RTOs devote resources to 
tariff compliance. WPS acknowledges that a non-profit RTO has no 
dividends to cancel and likely no property to liquidate to cover these 
shortfalls, yet believes that such organizations can exercise cost-
cutting measures, especially regarding rewards for employee 
performance, and thereby bear some financial responsibility and 
accountability for their operational violations. In the event of a 
penalty, WPS believes the Commission could require an RTO to take steps 
to cover its penalty-related revenue shortfall by cutting its budget, 
eliminating management bonuses and demonstrating that it has taken 
reasonable corrective steps before the Commission permits recovery of 
the remaining penalty revenue from its members and customers. To the 
extent some portion of an RTO's penalties are passed through to its 
market participants, including transmission owners, WPS argues that 
those market participants would be in a position to take actions 
similar to the actions taken by shareholders of a publicly traded 
company to motivate the RTO either by changing the RTO's processes or 
its Board of Directors.
    1338. TAPS states that some adaptation of the penalties may be 
necessary to make them appropriate and effective in the non-profit RTO/
ISO context, for example, by requiring a reduction in management 
compensation. TDU Systems recommend that RTOs be subject to the 
notification filing requirement that is part of the Commission's 
penalty

[[Page 12440]]

proposal, regardless of whether RTOs are subject to pay penalties. TDU 
Systems believe this reporting requirement would provide an objective 
measure of RTO efficiency. APPA believes steps should be taken to 
remedy tardy RTO processing of service requests, suggesting that 
performance incentives for RTO employees, if carefully designed, could 
be useful. In its reply comments, Duke argues that although 
transmission owners in RTOs should not pay the price for RTOs failures 
to abide by the tariff, RTOs lack of performance should be addressed by 
the Commission, perhaps in a separate proceeding.
    1339. Transmission providers that have retained an independent 
tariff administrator suggest that these independent entities should 
also be exempt from operational penalties related to study completion 
times.\812\ In their view, these independent entities also have no 
incentive to discriminate when completing service request studies. 
Similarly, NorthWestern argues that a transmission provider without an 
affiliate that could benefit from a delay in completing service request 
studies also should be exempt from paying the proposed operational 
penalties.
---------------------------------------------------------------------------

    \812\ E.g., Duke, MidAmerican, and TranServ.
---------------------------------------------------------------------------

Commission Determination
    1340. The Commission adopts the NOPR proposal to subject 
transmission providers to operational penalties when they routinely 
fail to meet the 60-day due diligence deadlines prescribed in sections 
19.3, 19.4, 32.3 and 32.4 of the pro forma OATT. Transmission providers 
must have a meaningful stake in meeting study time frames. As discussed 
above, a transmission provider will be required to make a notification 
filing with the Commission indicating that it has not completed request 
studies on a timely basis and may present evidence that extenuating 
circumstances prevented it from completing studies on a timely basis. 
The transmission provider then will be subject to an operational 
penalty if the transmission provider continues to be out of compliance 
with the deadlines prescribed in the pro forma OATT for each of the two 
quarters following its notification filing and the Commission 
determines that no extenuating circumstances exist to excuse the 
transmission provider's non-compliance. The transmission provider will 
be deemed to be out of compliance if it completes 10 percent or more of 
non-affiliates' system impact studies and facilities studies outside of 
the deadlines prescribed in the pro forma OATT. The operational penalty 
will be assessed on a quarterly basis, starting with the quarter 
following the notification filing and continuing until the transmission 
provider completes at least 90 percent of all studies within 60 days 
after the study agreement has been executed. For any system impact 
study or facilities study completed during that quarter and more than 
60 days after the study agreement was executed, the penalty will equal 
$500 for each day the transmission provider takes to complete the study 
beyond 60 days. For any system impact study or facilities study that is 
still pending at the end of the quarter and that has been in the study 
queue for more than 60 days, the penalty will equal $500 for each day 
the study has been in the study queue beyond 60 days.
    1341. The late study penalty regime described in this Final Rule 
will become effective at the same time as the rest of the new pro forma 
OATT. The penalty regime is designed so that the transmission provider 
has to be out of compliance for at least three quarters before it is 
subject to late study penalties. We believe nine months is sufficient 
time for the transmission provider to adjust its operations to the new 
requirements in this Final Rule, including penalties for late studies. 
That is, we believe transmission providers should be able to reallocate 
employees to study requests for service and hire new staff, to the 
extent these steps are necessary, by the time the transmission provider 
will be subject to civil penalties.
    1342. The procedures underlying the operational penalty regime 
adopted in this Final Rule ensure that the due process rights of 
transmission providers are protected. In their notification filing, 
transmission providers will have the right to document and describe any 
unique complexities that particular requests introduce into the study 
process and that prevent the transmission provider from completing the 
study within a the 60-day due diligence time frame. Thus the 60-day 
time frame will continue to be a flexible deadline, especially given 
that the transmission provider is not required to complete all studies 
within 60 days. These due process rights provide a de facto case-by-
case review of the transmission provider's efforts to complete studies 
on a timely basis.
    1343. On review of a notification filing, we will waive operational 
penalties if a transmission provider establishes that its non-
compliance is the result of factors or events that are truly beyond its 
control, including delays caused by the transmission customer. We will 
not, however, exempt all transmission projects that cross seams from 
operational penalties, as CREPC urges. We will consider the specific 
facts surrounding studies of such projects based on a transmission 
provider's notification filing. In response to TDU Systems, we 
acknowledge that the procedures for addressing a transmission 
provider's failure to conform to the 60-day time frame are not the same 
as the procedures applicable to a transmission customer that is 
assessed an operational penalty under the pro forma OATT. We believe 
such different procedures are justified in this instance. The other 
operational penalties in the pro forma OATT are assessed for failure to 
remain in compliance with strict requirements, while the study time 
frame is based on the transmission provider using its due diligence to 
complete studies within 60 days. The Commission recognizes that the 
transmission provider must have flexibility, within reason, to complete 
studies outside of this time frame. At the same time, the notification 
and penalty procedures we adopt in this Final Rule will ensure that 
this flexibility is not abused.
    1344. We do not find the remaining comments in opposition to the 
operational penalty for late studies to be compelling, particularly 
given the flexibility built into our penalty regime. We would not 
expect a transmission provider to prematurely deny a request for 
service simply to avoid an operational penalty. According to section 
17.5 of the pro forma OATT, a transmission provider must either grant 
service or offer the transmission customer a system impact study. The 
transmission provider does not have the option to simply deny the 
request for service. We therefore interpret comments that the 
transmission provider may prematurely deny a request to mean that the 
transmission provider will not explore all possible system upgrades or 
redispatch options as required by section 19.3 of the pro forma OATT or 
any conditional firm options discussed in section V.D.1. Such behavior 
would be a tariff violation that should be brought to our attention. 
The transmission provider is required under the pro forma OATT to 
provide a complete study and corresponding work papers to the 
transmission customer. If a transmission customer feels a system impact 
study is incomplete, it has recourse to call the Commission's 
Enforcement Hotline or file a formal complaint with the Commission.
    1345. We also do not expect a transmission provider to accept a

[[Page 12441]]

transmission service request to the detriment of system reliability 
simply to meet the study time frame. First, the transmission provider 
is not required to complete every request study within 60 days. Second, 
to the extent our new requirements that the transmission provider 
consider conditional firm options and participate in regional planning 
cause study delays, the transmission provider can document and describe 
such delays in its notification filing. Finally, the transmission 
provider has been required to consider redispatch in the system impact 
study since Order No. 888 was issued, so the 60-day due diligence time 
frame should continue to be consistent with the long standing 
requirement to consider redispatch in the system impact study.
    1346. As we discuss below, we believe NAESB's queue hoarding and 
queue flooding business practices, as well as additional reforms 
adopted in this Final Rule, will address the problem surrounding the 
submission of multiple requests. With regard to requests for a 
technical conference or further procedures to consider the effect of 
our operational penalty regime, we believe the commenters' proposals 
would largely provide anecdotal information and speculation on the 
impacts of the new planning and coordination requirements. Our 
experience from the last ten years, and the comments provided in 
response to the NOI and NOPR, provide a sufficient basis to develop a 
penalty regime. In addition, the very requirement that transmission 
customers post performance metrics and submit notification filings 
prior to assessment of operational penalties will provide actual 
experience with the new regime. As explained above, the notification 
procedures adopted today will ensure that we will not assess a penalty 
for late studies unless justified by the circumstances. We can propose 
additional changes to the study process or penalty regime based on the 
actual experience under this Final Rule if our experience warrants it.
    1347. As described above, we adopt the proposal to set the 
operational penalty for late studies equal to $500 per day per late 
study. We believe $500 per day per late study is in line with the cost 
the transmission provider would incur to focus additional resources on 
processing requests studies. In addition, the penalty for being one 
month late, $15,000, is in line with the overall cost of the study. We 
conclude that the $500 per day per late study penalty is high enough to 
provide the incentive to transmission providers to comply with study 
processing deadlines in the pro forma OATT, while not being 
unnecessarily punitive. We believe that a penalty in the range of 
$10,000 per day per late study would be unnecessarily punitive. The 
proposal to set the penalty equal to the higher of the lost opportunity 
cost to the customer resulting from the delay, if any, or $1,000 for 
each day is administratively cumbersome and could result in 
administrative costs that are not justified. Finally, we believe the 
due process afforded the transmission provider is an important element 
of the penalty regime, so we decline to impose penalties automatically, 
without a notification filing to the Commission.
    1348. As indicated in the NOPR, we may order other remedial actions 
in addition to the operational penalties described above, consistent 
with the Policy Statement on Enforcement. We will determine any other 
remedial action on a case-by-case basis. The decision to order other 
remedial actions will be based, among other things, on whether we 
believe the transmission provider is using the same due diligence to 
complete studies for non-affiliated customers as it uses to complete 
studies for itself. We do not believe it would be appropriate, as a 
general matter, to require a transmission provider to engage an 
independent transmission administrator to the extent its posted 
performance metrics are not accurate. As a threshold matter, Commission 
audit staff may audit the accuracy of a transmission provider's posted 
metrics. If we are concerned about the accuracy of a transmission 
provider's metrics, we will evaluate the use of third-party audits at 
that time. We will not prejudge which remedial actions we will consider 
if a transmission provider persistently fails to adhere to the relevant 
timelines. Rather, we will review each such instance on a case-by-case 
basis and determine the appropriate remedial action consistent with the 
Commission's Policy Statement on Enforcement.
    1349. We clarify that a transmission provider is not subject to 
operational penalties if it can make a showing that its failure to meet 
the compliance threshold following its notification filing is due to 
extenuating circumstances, as we agree that the transmission provider 
should not be penalized for factors out of its control. The submission 
of a notification of extenuating circumstances will not, however, 
suspend the obligation of a transmission provider to process at least 
90 percent of the study requests within the proposed deadlines, until 
such time as the Commission issues a final determination on the 
notification of extenuating circumstances. At the same time, we will 
not require the transmission provider to distribute its operational 
penalty while we are still considering the transmission provider's 
notification filing. The transmission provider nonetheless remains 
liable for paying the operational penalty for all request studies 
completed or outstanding after the notification filing and not 
completed within 60 days. This timing will balance the transmission 
provider's due process rights with the need to provide an incentive to 
the transmission provider to complete studies on a timely basis.
    1350. We clarify that the processing time is measured from the 
point that the customer returns its executed study agreement to the 
transmission provider. By the time the transmission provider offers a 
system impact study agreement, it should have all the information it 
needs to complete the study. Pursuant to section 17.4 of the pro forma 
OATT, the transmission provider can deem a transmission service request 
deficient if the transmission customer does not provide all information 
the transmission provider needs to evaluate the request for service. We 
expect the transmission provider to use informal means to communicate 
the information it needs from the transmission customer before it deems 
a transmission service request deficient.
    1351. We adopt the NOPR proposal to have the transmission provider 
distribute the operational penalty for late studies to all non-
affiliated transmission customers, as discussed in section V.C.5.b of 
this Final Rule. We believe that a transmission provider that is not 
processing studies on a timely basis potentially harms all transmission 
customers, not just those with requests in the study queue. For 
instance, a transmission customer may decide against requesting service 
that it believes will require a system impact study if the transmission 
provider is not processing transmission service requests on a timely 
basis. Therefore, we will not adopt suggestions to distribute penalty 
revenue only to transmission customers that have request studies that 
are not completed within 60 days. We clarify that the penalty is $500 
per day per late study, with the resulting total penalty revenue 
distributed to unaffiliated transmission customers as discussed in 
section V.C.5.b of this Final Rule. We clarify that the transmission 
provider will propose a method to determine how unaffiliated 
transmission customers will receive operational penalty payments, as 
discussed in section V.C.5.b of this Final Rule.

[[Page 12442]]

    1352. We will not alter the 60-day study completion timeframe 
currently embodied in sections 19.3, 19.4, 32.3 and 32.4 of the pro 
forma OATT. We continue to believe, absent concrete evidence to the 
contrary, that the existing timeframe adequately balances the need for 
expeditious resolution of request studies and the need to ensure that 
the transmission provider can reliably accommodate the transmission 
service reserved. Moreover, we believe the penalty regime defined in 
this Final Rule protects the transmission provider in the event studies 
take longer to complete due to the new planning requirements defined in 
section V.B of this Final Rule or the new requirement to consider 
conditional firm options as defined in section V.D.1 of this Final 
Rule. We will not adopt the suggestion to restart the 60-day due 
diligence period for any study that experiences a delay that can not 
properly be attributed to the transmission provider. We reiterate that 
the transmission provider is not subject to penalties for late studies 
if it can establish that delays are due to factors the transmission 
provider cannot control.
    1353. The Commission declines to adopt the NOPR proposal to exempt 
RTOs from operational penalties for completing studies on an untimely 
basis. We agree with those commenters that argue that RTO independence 
does not guarantee RTO competence or compliance in every instance and 
that RTOs may fail to complete studies on a timely basis due to 
competing internal priorities or staffing issues. Imposing penalties 
for failure to comply with the due diligence timeframe for completing 
studies will provide RTOs an appropriate incentive to comply with the 
pro forma OATT requirements and ensure that they devote adequate 
resources to tariff compliance. Finally, we note that subjecting RTOs 
to operational penalties for late studies is consistent with the 
Commission's decision to subject RTOs and ISOs to penalties for failure 
to meet reliability standards.\813\ We believe that all transmission 
providers, including RTOs, should operate under the same rules, 
reporting obligations, and performance metrics in the OATT. We will 
nonetheless keep in mind the nature of an RTO's operations and the 
RTO's unique characteristics when we consider whether penalties would 
be appropriate. We agree that RTOs do not have an incentive to 
discriminate (which is one of the bases for this policy) and we agree 
that imposing a penalty raises the issue of cost recovery, as most RTOs 
are not-for-profit entities. We will therefore consider these and all 
other relevant factors in exercising our discretion whether to impose a 
penalty in a given circumstance.
---------------------------------------------------------------------------

    \813\ Rules Concerning Certification of the Electric Reliability 
Organization; and Procedures for the Establishment, Approval, and 
Enforcement of Electric Reliability Standards, Order No. 672-A, 71 
FR 19814 (Apr. 18, 2006), FERC Stats. & Regs. ] 31,212 at P 56 
(2006) (``It is not arbitrary and capricious to treat all operators 
alike, including RTOs and ISOs, in terms of their liability for 
violation of a Reliability Standard.'').
---------------------------------------------------------------------------

    1354. Consistent with the treatment of RTOs, we will not exempt 
independent entities that provide tariff administration from penalties 
for late completion of studies. As with RTOs, independence does not 
guarantee competence or compliance in every instance. Independent 
entities have a similar incentive to limit the personnel committed to 
processing request studies in an effort to reduce overhead costs. We 
believe that all entities administering the tariff should operate under 
the same rules, reporting obligations, and performance metrics in the 
pro forma OATT.
(3) Recovery Through Rates
NOPR Proposal
    1355. The Commission proposed that a transmission provider cannot 
recover for ratemaking purposes any operational penalty it pays for 
failing to process transmission service studies on a timely basis.
Comments
    1356. CREPC noted that, while it may be reasonable for an investor-
owned utility to pay penalties without being allowed to recover the 
penalties in rates, this approach will be problematic for utilities 
that do not have shareholders.
Commission Determination
    1357. We will prohibit all jurisdictional transmission providers 
from recovering penalties for late studies from transmission customers. 
We believe that all entities administering the tariff should operate 
under the same rules, reporting obligations, and performance metrics in 
the pro forma OATT. Non-profit transmission providers have other 
sources of money to pay penalties beyond the revenue they collect for 
sales of transmission service. Therefore, we require non-profit 
transmission providers to pay operational penalties for late studies 
from their other sources of money. This notwithstanding, we may 
consider factors such as an entity's financial ability to absorb a 
penalty in determining whether to impose penalties in the first 
instance.
(4) Fee for Multiple Self-Competing Transactions
NOPR Proposal
    1358. In the NOPR, the Commission sought comment on a fee structure 
that could provide a disincentive for transmission customers to submit 
duplicative requests without penalizing transmission customers that 
have legitimate requests for transmission service. The Commission asked 
for detailed recommendations, including any proposed tariff language, 
regarding the standards it should use to identify requests that would 
be subject to a fee. The Commission also sought recommendations on the 
level of a fee that balances its policy goals to discourage requests 
for transmission service that the transmission customer does not intend 
to confirm while not discouraging legitimate requests for transmission 
service. Finally, the Commission sought comment regarding the 
circumstances, if any, under which the processing fee would be refunded 
to or credited to the transmission customer.
Comments
    1359. A number of commenters express support for a fee for 
duplicative requests.\814\ CREPC believes that queue blocking behavior 
should be discouraged so that legitimate requests lower in the queue 
are not disadvantaged. MISO believes the transmission provider should 
be allowed to charge a fee that is small enough to not create a barrier 
to entry yet high enough to ``add up'' for anyone wishing to flood the 
queue. MISO and Seattle suggest that the fee be based on the 
transmission provider's cost to review a request and handle the initial 
processing. MISO also believes the transmission provider should be able 
to charge a fixed dollar amount for any accepted requests that the 
customer wants to retract. Southern suggests that the Commission 
consider a procedure whereby transmission customers place a deposit 
with transmission providers to cover a certain number of requests that 
is forfeited once the requests reach a certain threshold and are deemed 
self-competing. TranServ suggests that the fee apply to requests for 
long-term firm transmission service and be based on duration of the 
request and not capacity requested as an incentive to the transmission 
customer to submit fewer combined requests where possible. TranServ 
suggests this fee could be

[[Page 12443]]

waived if the service request is submitted pre-confirmed.
---------------------------------------------------------------------------

    \814\ E.g., MidAmerican, MISO, Seattle, Southern, TranServ, 
TAPS, and CREPC.
---------------------------------------------------------------------------

    1360. Most of the transmission customers and some transmission 
providers oppose the creation of a fee structure for duplicative 
requests for transmission service.\815\ Several commenters argue that 
the Commission should determine whether the newly-adopted NAESB 
business practices and other reforms proposed in the NOPR can reduce 
the number of requests that the transmission customer does not intend 
to confirm.\816\ Nevada Companies and Great Northern assert that the 
current deposit requirement serves to discourage multiple self-
competing requests. Constellation asserts that the Commission should 
focus on narrowly-tailored penalties to deter market participants from 
intentionally jamming the queue.
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    \815\ E.g., EEI, Nevada Companies, Powerex, and Suez Energy NA.
    \816\ E.g., EEI, Powerex, Suez Energy NA, and Entegra.
---------------------------------------------------------------------------

    1361. Several commenters suggest that a transmission provider that 
makes a showing that it is experiencing a significant problem with 
respect to customers' submission of multiple competing requests should 
be allowed to propose a fee to combat the problem.\817\ MISO notes that 
the Commission has rejected a fee for unconfirmed requests in the 
past.\818\
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    \817\ E.g., EEI and TAPS.
    \818\ See Midwest Independent Transmission System Operator, 
Inc., 97 FERC ] 61,269 (2001) (rejecting a proposal to include a fee 
for non-confirmed transmission service requests for firm point-to-
point transmission service of one week or longer).
---------------------------------------------------------------------------

    1362. TAPS believes the fee revenue should be shared with network 
customers on a load-ratio share basis. TAPS also suggests that the fee 
apply to the transmission provider's merchant arm in a meaningful way.
    1363. CREPC urges the Commission to adopt a simple, straightforward 
standard for determining duplicative requests, such as the same points 
of receipt and delivery, same source and sink, same time frame, and 
same firmness, as well as the same project at multiple locations. 
Powerex recommends that the Commission be very specific in describing 
the types of multiple transmission requests it believes to be a problem 
and the fee structure that would be applied to such problematic 
requests. For example, Powerex believes the Commission should clarify 
that requests subject to the fee must be multiple, not pre-confirmed, 
and with identical quantity, point of receipt, point of delivery, start 
time, end time, and firmness. In its reply comments, Santa Clara 
disagrees with Powerex. Santa Clara urges the Commission to examine the 
practice of queue hoarding and punish those entities that are acting in 
an anticompetitive and manipulative manner. Further, Santa Clara urges 
the Commission to refrain from being too specific in its ruling, as a 
more general explanation of the behavior to be avoided would go a long 
way in preventing entities from making an end-run around a ruling 
against queue hoarding.
    1364. MidAmerican believes that if a fee is imposed, the fee should 
not be refunded as the administrative costs and difficulty of 
administering the refunds would be an unreasonable burden on the 
transmission provider. CREPC believes refunding or crediting the 
processing fee would defeat the purpose of having one in the first 
place, although the processing fee could be refunded if the duplicative 
service request attached to it actually comes to fruition. Suez Energy 
NA suggests that the processing fee be refunded whenever the 
transmission provider exceeds the 60-day request study due diligence 
deadline. TAPS suggests that the fee be structured to provide for 
exceptions where the failure to confirm reflects a legitimate purpose, 
not jamming. TAPS cites as examples transmission requests associated 
with requests for proposals, alternative sites for planned generation, 
and the inability to secure timely confirmation of all legs of a multi-
system path. TAPS notes that the current pro forma OATT accommodates 
multiple submissions in relation to the same competitive solicitation 
in sections 19.2(ii) and 32.2(ii).
Commission Determination
    1365. The Commission will not require transmission providers to 
charge a fee for duplicative requests for transmission service. We will 
instead first consider whether the newly adopted NAESB queue flooding 
and queue hoarding business practices reduce the number of requests 
that the transmission customer does not intend to confirm. We are 
concerned that benefits to market participants would not justify the 
administrative costs of a new fee if the NAESB business practices can 
effectively discourage transmission service requests the transmission 
customer does not intend to confirm. We also believe that the current 
deposit mechanism in section 17.3 of the pro forma OATT should have the 
same effect as a fee based on the transmission provider's cost to 
process the request for transmission service, like the fee MISO and 
CREPC propose. Pursuant to section 17.3, in the event a transmission 
customer retracts or withdraws a request, the transmission provider is 
allowed to deduct from the transmission customer's deposit the costs 
the transmission provider incurred to process the request. As a result, 
we do not believe any other fee structure is necessary to make the 
transmission provider whole when a transmission customer submits a 
transmission service request it does not expect to confirm.
    1366. A transmission provider that continues to experience problems 
related to submission of multiple duplicative requests for transmission 
service is free to file a tariff modification that includes a fee to 
combat the problem. This filing should explain why the transmission 
provider is unable to handle the submission of multiple duplicative 
requests for transmission service through NAESB's queue hoarding and 
queue flooding business practices.
(5) Clustering Transmission Service Request Studies
NOPR Proposal
    1367. In the NOPR, the Commission sought comment regarding whether 
a transmission provider should be required to study requests for 
transmission service in a group if the transmission provider fails to 
complete studies on a timely basis. If so, the Commission sought 
comment on the circumstances that should trigger such a requirement and 
the appropriate method of implementing the requirement. The Commission 
sought further comment regarding whether transmission providers should 
be required to study requests for transmission service in a group if 
all the transmission customers in the group agree to cluster their 
requests. Finally, the Commission sought comment regarding how to 
select the requests that belong to a cluster so that transmission 
customers cannot ``cherry-pick'' clusters to avoid transmission system 
upgrade costs.
Comments
    1368. A few commenters, primarily transmission customers, believe 
transmission providers should be required to study requests for 
transmission service in a group.\819\ CREPC believes transmission 
providers should have the discretion to develop the criteria for 
clustering so that transmission customers do not have the opportunity 
to ``cherry pick'' study clusters. If transmission providers are 
required to study requests in a group, Powerex believes customers 
should be

[[Page 12444]]

given the option of paying the transmission provider to perform an 
individual study. Suez Energy NA believes studying requests that are 
clustered voluntarily will partially incorporate the value of 
counterflows in the study process. PGP believes transmission customers 
should have the opportunity to join a cluster, but only if the customer 
is bound to accept the study results.
---------------------------------------------------------------------------

    \819\ E.g., CREPC, Powerex, and Suez Energy NA.
---------------------------------------------------------------------------

    1369. A number of commenters, primarily transmission providers, 
state that transmission providers should be allowed, but not required, 
to study requests for transmission service in a group.\820\ Bonneville 
argues that the transmission provider is in the best position to 
determine whether requests should be studied individually or in groups. 
EEI asserts that clustering does not necessarily ensure timely 
completion of transmission studies. FirstEnergy believes each 
transmission service request should stand on its own merits and be 
directly assigned costs associated with its own request so that 
requests in one part of the request queue do not end up subsidizing 
requests in another part of the request queue. MISO believes giving the 
transmission provider discretion to cluster requests will address the 
Commission's concerns with respect to transmission customers cherry-
picking clusters to avoid paying upgrade costs. Arkansas Commission and 
East Texas Cooperatives suggest that the Commission allow clustering 
through an open season procedure similar to the procedure SPP currently 
uses pursuant to Attachment Z of SPP's OATT.
---------------------------------------------------------------------------

    \820\ E.g., Bonneville, EEI, MISO, Nevada Companies, Southern, 
Entegra, and PNM-TNMP.
---------------------------------------------------------------------------

Commission Determination
    1370. The Commission will not require transmission providers to 
study transmission requests in a cluster, although we encourage 
transmission providers to cluster request studies when it is 
reasonable. We do, however, require transmission providers to consider 
clustering studies if the customers involved request the cluster and 
the transmission provider can reasonably accommodate the request. We 
believe clustering request studies offers potential benefits as the 
needed transmission upgrades are frequently large enough that the 
upgrade can accommodate more than one transmission service request. In 
addition, jointly modeling transmission service requests can allow the 
transmission provider to more efficiently design transmission system 
upgrades. Clustering also allows the transmission provider to include, 
to the extent it is consistent with good utility practice, the 
potential counterflows created by the clustered requests. We do not 
agree, as suggested by commenters, that clustering necessarily leads to 
one set of transmission customers subsidizing another set of 
transmission customers.
    1371. We therefore require each transmission provider to include 
tariff language in its compliance filing that describes how it will 
process a request to cluster request studies and how it will structure 
the transmission customers' obligations when they have joined a 
cluster. We will give the transmission provider discretion to determine 
whether a transmission customer can opt out of a cluster and request an 
individual study. We are giving each transmission provider discretion 
to develop the clustering procedures it will use because we believe the 
transmission provider is in the best position to determine the 
clustering procedures that it can accommodate. We also believe that the 
transmission provider is in the best position to develop a clustering 
procedure that prevents a transmission customer from strategically 
selecting the clusters in which it participates in an attempt to avoid 
responsibility for needed transmission system upgrades.
(6) Standardization of Business Practices for Study Queue Processing
NOPR Proposal
    1372. In the NOPR, the Commission sought comment on whether 
additional standardization of request queue processing is necessary. If 
so, the Commission sought comment on the specific issues commenters 
believe are not clearly prescribed in Order No. 676 or the NOPR and 
that require additional mandatory queue processing business practices.
Comments
    1373. Several commenters identified issues where a transmission 
customer needs coordinated responses across several transmission 
systems in order to serve its load.\821\ Seattle and NRECA suggest that 
the Commission amend the pro forma OATT so that a customer's 
applications for service across multiple systems that are intended to 
serve a single sink from an identified resource will be considered a 
single application for purposes of establishing the deadlines for 
rendering an agreement for service, revising queue status, eliciting 
deposits and finally commencing service. Seattle believes the 
Commission should permit coordination and implementation of these 
requirements by a third party such as wesTTrans.net and sub-regional 
planning organizations. At a minimum, these commenters ask the 
Commission to develop business practices to protect a transmission 
customer caught between two systems with uncoordinated deadlines.
---------------------------------------------------------------------------

    \821\ E.g., NRECA, TDU Systems, and Seattle.
---------------------------------------------------------------------------

    1374. Exelon states that the Commission should require all 
transmission providers to allow transmission customers to link 
consecutive requests for service (e.g., monthly firm service requests 
for December, January and February) and to evaluate such request as a 
single request. Exelon argues that this service, which is currently 
provided by some transmission providers, would increase uniformity and 
use of the transmission system, and enhance competitiveness without 
burdening transmission providers or adding administrative complexity.
    1375. TDU Systems indicate that several of its members have 
experienced difficulty related to the lack of standardized business 
practices, particularly in practices related to timing, application 
requirements, and requirements relating to methods of proving that a 
network customer has executed a power purchase agreement prior to 
designating the power purchase agreement as a network resource.
    1376. PNM-TNMP does not believe that additional clarity or business 
practices are necessary beyond those already provided in Order No. 676. 
However, to the extent additional issues arise, PNM-TNMP believes 
NAESB's WEQ forum is the appropriate place to address them. Similarly, 
NorthWestern recommends that transmission providers work together 
within regional groups to develop a common set of business practices 
that will be followed by all transmission providers within each region, 
instead of the Commission using the NOPR comments it receives to 
develop a prescriptive set of business practices by which all 
transmission providers must abide. In its reply comments, Powerex 
argues that either the entire transmission process has to be integrated 
via an RTO, or coordination of requests across multiple control areas 
has to be done transmission provider by transmission provider. Powerex 
suggests that NorthWestern's suggestion for regional development of 
business practices may be a more pragmatic approach to address concerns 
about coordination of requests across multiple systems.

[[Page 12445]]

Commission Determination
    1377. The Commission agrees that transmission requests across 
multiple transmission systems should be coordinated by the relevant 
transmission providers. We will not, however, amend the pro forma OATT 
to require such coordination. Rather, we require transmission providers 
working through NAESB to develop business practice standards related to 
coordination of requests across multiple transmission systems. In order 
to provide guidance to NAESB, we will articulate the principles that 
should govern processing across multiple systems. All the transmission 
providers involved in a request across multiple systems should consider 
a request that requires studies across multiple systems to be a single 
application for purposes of establishing the deadlines for rendering an 
agreement for service, revising queue status, eliciting deposits and 
commencing service. In order to preserve the rights of other 
transmission customers with studies in the queue, the priority for the 
single application should be based on the latest priority across the 
transmission providers involved in the multiple system request. We note 
that regional entities like wesTTrans are already coordinating requests 
across multiple transmission systems and we believe such coordination 
is an acceptable solution to this issue.
    1378. We interpret Exelon's request that we require all 
transmission providers to allow transmission customers to link 
consecutive requests for firm point-to-point transmission service and 
to evaluate such requests as a single request as asking us to (1) allow 
transmission customers to require the transmission provider to either 
grant service for the entire period, deny service for the entire 
period, or offer the same partial quantity for the entire period and 
(2) require the transmission provider to consider the full duration of 
the linked requests when determining reservation priority pursuant to 
sections 13.2 of the pro forma OATT (short-term firm point-to-point 
transmission service). We require transmission providers working 
through NAESB to develop business practice standards to allow a 
transmission customer to rebid a counteroffer of partial service so the 
transmission customer is allowed to take the same quantity of service 
across all linked transmission service requests. Transmission providers 
need not implement these business practice standards until NAESB 
develops appropriate standards. We note that the transmission customer 
should not be required to take the same quantity of service across 
consecutive transmission service requests, it should simply have the 
option to do so. On the second issue, we reiterate that, according to 
existing NAESB business practice standard 001-4.16, the transmission 
provider is required to consider the full duration of the linked 
requests when determining reservation priority pursuant to section 13.2 
of the pro forma OATT.
    1379. We believe most of the standardization issues TDU Systems 
raise (application requirements, requirements relating to methods of 
proving that a network customer has executed a power purchase agreement 
prior to designating the power purchase agreement as a network 
resource, and timing) have been addressed in this Final Rule. In 
particular, we describe the information a network customer is required 
to provide when designating a new network resource in section V.D.6.b 
of this Final Rule. We also indicate in section V.D.6.b that the 
transmission provider is not allowed to require a network customer to 
provide contract terms and conditions when it designates a power 
purchase agreement as a network resource. The network customer is 
required to provide a statement that attests, among other things, that 
it has executed a power purchase agreement prior to confirming its 
request to designate a new network resource. We will continue to give 
transmission providers discretion in determining whether to impose 
restrictions on the earliest time at which it will accept a request for 
transmission service. We believe the transmission provider is in the 
best position to determine whether it needs to restrict the time at 
which it will accept requests for transmission service in order to 
process transmission service requests in an orderly fashion consistent 
with the requirements in the pro forma OATT.
(7) Additional Processing Proposals
Comments
    1380. A number of commenters propose changes to queue processing 
requirements that were not addressed in the NOPR.
    1381. Powerex believes that OASIS practices should be modified to 
ensure that short-term firm and non-firm point-to-point service 
requests are processed based on the ATC posted at the time the requests 
were queued. Powerex argues that a transmission provider should not be 
permitted to grant transmission service requests at a time when its 
OASIS indicates there is no ATC. In its view, any such requests should 
be automatically denied. Powerex also suggests that confirmation time 
periods be shortened for short-term firm point-to-point service 
requests to discourage behaviors that have the effect of delaying queue 
processing. In its reply comments, Powerex asserts that requiring 
transmission provider responses to be based on posted ATC, as well as 
increasing standardization in transmission provider response time for 
short-term transmission requests, would enhance a transmission 
customer's ability to manage multiple transmission provider requests 
within the context of the pro forma tariff.
    1382. Occidental suggests in reply that the Commission should 
introduce meaningful tariff-based sanctions for unauthorized deviations 
from the standards and modeling assumptions it proposes to include in 
Attachment C of the pro forma OATT, the transmission provider's 
description of its ATC calculation methodology.
    1383. Several commenters make suggestions to allow the transmission 
provider to terminate idle transmission service requests. TDU Systems 
recommends that the Commission provide a sunset date by which all 
requests not pursued by the transmission customer would be terminated. 
MidAmerican and Northwest IOUs ask the Commission to clarify in the 
Final Rule that the transmission provider may deem a transmission 
service application withdrawn and terminated if a customer revises its 
application or if such customer fails to timely pay the annual 
reservation fee pursuant to section 17.7 of the pro forma OATT.
    1384. Constellation asks the Commission to require transmission 
providers to release study results as soon as a study is completed, 
rather than holding them until the end of the 60 days.
    1385. NorthWestern believes an appropriate modification to the 
study process would be to allow the transmission provider to have an 
opportunity to verify and correct the system impact study results at 
the beginning of the facilities study and again before construction 
begins.
    1386. With the exception of very short-term transmission service 
(for which a bid-based system is impractical to manage), LDWP suggests 
that the queue process be transformed into a competitive process in 
which awards of transmission service are allocated in a manner similar 
to the provisions in section 4.4 of Order No. 638.
    1387. TranServ notes that OASIS standards allow the customer to 
turn a request into a pre-confirmed request, but not vice versa. If the 
Commission's

[[Page 12446]]

proposal on granting priority to pre-confirmed requests is adopted, 
TranServ believes this capability should be removed from OASIS as it 
would seem to invite gaming and confuse transmission providers 
attempting to process requests in proper queue order.
    1388. PGP states that OASIS platforms should be accessible from 
different computer platforms using a variety of browsers, not just one 
operating system/browser combination (Windows/Explorer), which is 
currently the case.
Commission Determination
    1389. We will not adopt Powerex's proposal to require the 
transmission provider to accept or deny in all cases non-firm and 
short-term firm point-to-point transmission service requests solely 
based on posted ATC. The issue Powerex raises is ultimately a question 
of how the transmission provider is going to exercise its discretion 
under the tariff. Under the pro forma OATT, the transmission provider 
can use its knowledge of the system to exercise its discretion to offer 
transmission service even if posted ATC is not sufficient to 
accommodate the requested service. Alternatively, the transmission 
provider can use its discretion to update posted ATC in response to a 
transmission customer's verbal request to update ATC.\822\ In both 
situations, the transmission provider may provide transmission service 
in instances when posted ATC is not sufficient to accommodate a 
transmission service request at the time the transmission customer 
requests service. We do not wish to discourage transmission providers 
from making transmission service available at times when posted ATC is 
not accurate. Therefore, we will continue to allow the transmission 
provider to accept transmission service requests in instances when 
posted ATC is not sufficient but the transmission provider believes it 
can accommodate the service. The transmission provider must use its 
discretion to grant service when posted ATC is not sufficient on a non-
discriminatory basis. In order to ensure that it does so, we expect the 
transmission provider to log such instances as an act of discretion and 
post the log as required in section 37.6(g)(4) of the Commission's 
regulations.\823\
---------------------------------------------------------------------------

    \822\ See, e.g., Florida Power Corp., 111 FERC ] 61,243 at P 5 
(2005).
    \823\ 18 CFR 37.6(g)(4).
---------------------------------------------------------------------------

    1390. We will not modify the pro forma OATT to address requests to 
allow the transmission provider to terminate idle transmission service 
requests. NAESB's business practice 001-4.11 allows the transmission 
provider to retract a request if the transmission customer does not 
respond to an acceptance within the time established in NAESB business 
practice standard 001-4.13. Therefore, we interpret TDU Systems 
comments to refer to circumstances when a transmission customer fails 
to respond to the transmission provider's request for additional 
information during the course of a request study. As discussed above, 
by the time the transmission provider offers a system impact study 
agreement, it should have all of the information that it needs to 
complete the study. Pursuant to section 17.4 of the pro forma OATT, the 
transmission provider can deem a transmission service request deficient 
if the transmission customer does not provide all of the information 
the transmission provider needs to evaluate the request for service. We 
will revise section 17.7 of the pro forma OATT so that the transmission 
provider is able to terminate a request for transmission service if a 
transmission customer that is extending the commencement of service 
does not pay the required annual reservation fee within 15 days of 
notifying the transmission provider that it would like to extend the 
commencement of service. We will not change the pro forma OATT to allow 
the transmission provider to terminate a transmission service request 
if the transmission customer changes its application for service. We 
believe the existing pro forma OATT is sufficient to allow a 
transmission provider to manage situations where the transmission 
customer modifies its application for service to the point that the 
customer is requesting transmission service that is meaningfully 
different than its initial request.
    1391. We clarify that sections 19.3 and 32.3 of the pro forma OATT 
require the transmission provider to release study results as soon as a 
study is completed, rather than holding them until the end of the 60 
days.
    1392. Commenters also suggest changes to the OASIS protocols, 
including prohibiting transmission customers from changing a request 
into a pre-confirmed request and requiring OASIS platforms to be 
accessible on non-Windows/Explorer computers. We believe these issues 
are best addressed by NAESB.
    1393. Commenters proposed a number of additional modifications to 
the pro forma OATT that we do not believe are necessary. These 
proposals would (1) allow the transmission provider to verify and 
correct studies between each step in the study process, (2) transform 
the queue process into competitive process, (3) shorten the 
confirmation time periods for short-term firm point-to-point service 
requests and (4) introduce penalties when the transmission provider 
deviates from the ATC calculation procedures detailed in Attachment C 
of the pro forma OATT. We believe the pro forma tariff is just and 
reasonable without such modifications and the commenters have not 
demonstrated that reforms in these areas are required at this time to 
prevent the exercise of undue discrimination.
b. Reservation Priority
    1394. Section 13.2 of the pro forma OATT requires transmission 
providers to process requests for long-term firm point-to-point service 
on a first-come, first-served basis and to process requests for short-
term firm point-to-point service on a first-come, first-served basis 
conditional on the duration of the request. Section 14.2 of the pro 
forma OATT requires transmission providers to process requests for non-
firm point-to-point service on a first-come, first-served basis 
conditional on the duration of the request to the extent transmission 
capacity beyond that needed by native load customers, network customers 
and firm point-to-point transmission customers is available. In the 
NOPR, the Commission made a number of proposals and requested comment 
regarding various aspects of the reservation priority rules.
(1) Priority for Pre-confirmed Requests
NOPR Proposal
    1395. In the NOPR, the Commission proposed to change the priority 
rules to give priority to pre-confirmed requests for firm point-to-
point transmission service. Specifically, the Commission proposed that 
a pre-confirmed short-term request for firm transmission service would 
preempt any non-pre-confirmed short-term requests, regardless of 
duration. Similarly, the Commission proposed that a pre-confirmed 
request for long-term firm transmission service would preempt a request 
for long-term transmission service that is not pre-confirmed. Under the 
Commission's proposal, a pre-confirmed request for short-term 
transmission service would not pre-empt a non-pre-confirmed request for 
long-term transmission service.
Comments
    1396. A number of commenters generally support the Commission's 
proposal to give priority to pre-

[[Page 12447]]

confirmed requests.\824\ Commenters who support the proposal note that 
giving reservation priority to pre-confirmed requests for transmission 
service could help alleviate the problems that arise when a 
transmission customer submits multiple identical requests for service 
with no intention of confirming all accepted requests.\825\ Supporters 
of the proposal also note that the proposal would allow the 
transmission provider to focus its attention on those requests that 
appear most likely to result in an actual reservation of transmission 
service.\826\ Although Nevada Companies do not oppose the proposal, 
they note that concerns regarding withdrawal of pre-confirmed requests 
might otherwise be alleviated by requiring a non-refundable deposit on 
requests.
---------------------------------------------------------------------------

    \824\ E.g., Nevada Companies, Seattle, LDWP, PGP, PNM-TNMP, Salt 
River, and Suez Energy NA.
    \825\ E.g., Ameren, Santa Clara, Entegra, Entergy, and TVA.
    \826\ E.g., Ameren and NorthWestern.
---------------------------------------------------------------------------

    1397. Several commenters suggest that establishing reservation 
priority first based on pre-confirmation status and then based on 
duration would ultimately result in transmission customers with 
relatively shorter term requests getting transmission service instead 
of transmission customers with relatively longer term requests.\827\ 
EEI asserts that this result would be inconsistent with the 
Commission's desire to promote longer-term uses of the transmission 
system. Several transmission providers suggest that the Commission 
modify its proposal to ensure that longer duration requests continue to 
have a priority over shorter duration requests.\828\ EEI suggests that 
the Commission should use pre-confirmation as a tie-breaker for short-
term requests for transmission service with the same duration. Southern 
argues further that a pre-confirmed daily or hourly request should not 
preempt a weekly request that has not been pre-confirmed.
---------------------------------------------------------------------------

    \827\ E.g., CREPC and EEI.
    \828\ E.g., Entergy, Southern, and NorthWestern.
---------------------------------------------------------------------------

    1398. Opponents of the proposal identify a number of operational 
difficulties in implementing a system that gives priority to pre-
confirmed requests. Several commenters note that transmission customers 
are not bound to take service because they pre-confirm a request for 
transmission service.\829\ They argue, for instance, a transmission 
customer is not bound to take service in the event the transmission 
provider offers a study or counteroffers the request with a partial 
quantity of service. Similarly, MidAmerican notes that a transmission 
customer may withdraw a pre-confirmed request for transmission service 
at any time prior to acceptance by a transmission provider. Opponents 
also argue that giving priority to pre-confirmed requests would disrupt 
the study process.\830\ This disruption would occur when a transmission 
provider receives a pre-confirmed request for transmission service 
while it is actively studying a request for service that has not been 
pre-confirmed. Under these circumstances, the transmission provider 
would be required to suspend the study of one request in order to study 
a request with a higher reservation priority. In its reply comments, 
Indianapolis Power asks the Commission to clarify if this 
interpretation of the NOPR proposal is accurate. TranServ, suggesting 
that the Commission has not proposed to give a priority to pre-
confirmed requests for non-firm transmission service, asserts that 
having different priority rules for firm and non-firm transmission 
service introduces unnecessary complexity. Finally, Southern believes 
that a pre-confirmed service request submitted within close proximity 
to the actual commencement of service should not preempt an existing 
non-pre-confirmed request, if doing so would be disruptive to the 
operations of the transmission provider or to the reliability of the 
system itself.
---------------------------------------------------------------------------

    \829\ E.g., Bonneville and EEI.
    \830\ E.g., Bonneville, EEI, and MidAmerican.
---------------------------------------------------------------------------

    1399. Opponents also argue that giving a priority to pre-confirmed 
requests would unfairly disadvantage transmission customers who are not 
in a position to pre-confirm their requests, such as those requesting 
service in response to a request for proposals.\831\ EEI notes that the 
Commission addressed this issue when it issued Order No. 638 and 
decided that giving priority to pre-confirmed requests would 
disadvantage customers who are requesting service from multiple 
transmission providers.\832\ In the event the Commission decides to 
proceed with its proposal, TAPS suggests that the Commission limit the 
priority for pre-confirmed requests to non-firm and short-term firm 
requests for transmission service.
---------------------------------------------------------------------------

    \831\ E.g., EEI, MISO, TAPS, Constellation, and TDU Systems.
    \832\ Open Access Same-Time Information System and Standards of 
Conduct, Order No. 638, 65 FR 17370, FERC Stats. & Regs., ] 1996-
2000 ] 31,093 at 31,439 (2000).
---------------------------------------------------------------------------

    1400. Several commenters question whether a request that has been 
accepted but not confirmed would be pre-empted by a new pre-confirmed 
request.\833\ In a similar vein, TDU Systems suggests that the 
Commission include a time window between acceptance of a request and 
confirmation of the request, during which a request can not be 
preempted by a pre-confirmed request for transmission service.
---------------------------------------------------------------------------

    \833\ E.g., MidAmerican and TranServ.
---------------------------------------------------------------------------

Commission Determination
    1401. The Commission generally agrees with those commenters that 
argue that giving a priority to pre-confirmed requests can increase the 
efficient utilization of the system by giving priority to customers who 
are committed to purchase service over those who have not so committed, 
including customers that submit multiple requests without any intent to 
take service if each request is granted. However, we are mindful of 
concerns that doing so could undermine the Commission's desire to 
promote longer-term uses of the transmission system, disrupt the study 
process, or disadvantage transmission customers that are not in the 
position to pre-confirm their requests. As a result, we will modify the 
NOPR proposal and give priority only to pre-confirmed non-firm point-
to-point transmission service requests and short-term firm point-to-
point transmission service requests. In addition, longer duration 
requests for transmission service will continue to have priority over 
shorter duration requests for transmission service, with pre-
confirmation serving as a tie-breaker for requests of equal duration. 
This policy will still give an advantage to pre-confirmed requests 
without imposing substantial implementation difficulties or undermining 
the Commission's goals to encourage longer-term uses of the 
transmission system. Our revised policy on priority for pre-confirmed 
requests thus addresses the comments that we should preserve the 
priority of longer duration requests for transmission service over 
shorter duration requests for transmission service. For instance, a 
pre-confirmed daily or hourly request will not preempt a weekly request 
that has not been pre-confirmed. Pre-confirmed short-term service 
requests therefore will not have a priority superior to that of long-
term service requests that have not been pre-confirmed.
    1402. We acknowledge that our revised policy on priority for pre-
confirmed requests may be less effective than the NOPR proposal in 
alleviating the problems that arise when transmission customers submit 
multiple identical requests for service. However, we have taken other 
steps--notably accepting the NAESB business practices on queue flooding 
and queue

[[Page 12448]]

hoarding \834\--that we believe will substantially reduce the instances 
of multiple identical requests for service.
---------------------------------------------------------------------------

    \834\ See Order No. 676 at P 19.
---------------------------------------------------------------------------

    1403. The Commission also acknowledges the concerns expressed 
regarding operational difficulties caused by giving priority to pre-
confirmed requests and clarify our policy as follows. First, we will 
prohibit transmission customers from withdrawing pre-confirmed non-firm 
and short-term firm point-to-point transmission service requests prior 
to when the transmission customer is offered service or a system impact 
study. This policy will address MidAmerican's concern that a 
transmission customer may withdraw a pre-confirmed request for 
transmission service at any time prior to acceptance by a transmission 
provider. We believe prohibiting withdrawal of a pre-confirmed request 
is less administratively burdensome than the non-refundable deposit on 
requests proposed by Nevada Companies and achieves the same goals. The 
Commission will allow transmission providers to invalidate a pre-
confirmed request at the request of the transmission customer in the 
very near term following submittal of the request, in the event the 
transmission customer makes an inadvertent error in submitting its 
request. We expect the transmission provider to log such occurrences as 
an act of discretion so we can verify that transmission customers are 
not abusing this flexibility.
    1404. Second, while the Commission recognizes that a customer 
submitting a pre-confirmed request is not bound to take service when 
the transmission provider counteroffers the transmission customer's 
initial request, we do not believe this fact alone warrants reversing 
our proposal to give a priority to pre-confirmed requests. We are 
satisfied that a transmission customer that pre-confirms its request is 
obligated to take full service in the event the transmission provider 
offers the service requested.
    1405. The Commission also believes the revised priority policy will 
address Southern's comment that a pre-confirmed service request 
submitted within close proximity to the actual commencement of service 
should not preempt an existing non-pre-confirmed request if doing so 
would be disruptive to the operations of the transmission provider or 
to the reliability of the system itself. A pre-confirmed request for 
transmission service will not pre-empt an equal duration request that 
has already been confirmed. Therefore, the effects of the priority for 
pre-confirmed requests will be resolved prior to the time when the 
transmission provider would require an accepted request to be 
confirmed. Handling priority for pre-confirmed requests should be no 
more disruptive than giving a transmission customer time to confirm an 
accepted request.
    1406. Excluding long-term requests for transmission service will 
mitigate many of the concerns expressed by commenters who argued that 
giving a priority to pre-confirmed requests will unfairly disadvantage 
transmission customers who are requesting service in response to a 
request for proposals and are therefore not in a position to pre-
confirm their requests. Such requests for proposals typically involve 
long-term contracts for energy and/or generating capacity and, 
therefore, would be linked most likely to long-term transmission 
service requests. We disagree, however, with EEI's characterization of 
the Commission's decision in Order No. 638 to give a priority to pre-
confirmed requests for non-firm service only if the request offers a 
higher price. The Commission's decision in that proceeding was driven 
by its interpretation that the proposed business practice addressed in 
the part of Order No. 638 cited by Southern was not consistent with the 
relevant section of the pro forma tariff. In addition, the Commission's 
experience since Order No. 638 and the comments received to the NOPR 
proposal indicate the value of giving a priority to pre-confirmed 
requests, despite concerns that some transmission customers are not in 
a position to pre-confirm their requests for transmission service.
    1407. In response to requests for clarification from MidAmerican 
and TranServ, we clarify that a new pre-confirmed request for 
transmission service would preempt a request of equal duration that has 
been accepted by the transmission provider but not yet confirmed by the 
transmission customer. Thus, we decline to adopt TDU Systems' 
suggestion that the Commission include a time window between acceptance 
of a request and confirmation of the request, during which a request 
can not be preempted by a pre-confirmed request for transmission 
service. This is consistent with our desire to give transmission 
service first to those customers that are committed to taking the 
transmission service if it is granted. In the case of monthly firm 
point-to-point transmission service, the transmission customer has up 
to four days to confirm an accepted request. This is a potentially long 
delay when there is another transmission customer that is willing to 
commit to take the same service. Moreover, this policy is consistent 
with NAESB business standard 001-4.25, which allows a pre-confirmed 
request for non-firm point-to-point transmission service to preempt a 
request of equal duration and lower price that has been accepted but 
not confirmed.\835\
---------------------------------------------------------------------------

    \835\ See Order No. 676.
---------------------------------------------------------------------------

(2) Price as a Tie-Breaker
NOPR Proposal
    1408. The NOPR also proposed to add price as a tie-breaker in 
determining reservation queue priority when the transmission provider 
is willing to discount transmission service. Under the Commission's 
proposal, price would serve as a tie-breaker after pre-confirmation for 
those requests that are not yet confirmed.
Comments
    1409. All of the commenters who address the Commission's proposal 
to add price as a tie-breaker support the proposal, although some 
request that it be modified or clarified. Several commenters ask the 
Commission to clarify that an otherwise higher queued request has a 
right to match the price offer of a request with a higher price.\836\ 
With regard to short-term service, WAPA believes that the Commission's 
proposal to add price as a tie-breaker would overly complicate matters 
after taking into account the many complex timing restrictions on 
short-term service. As a result, WAPA proposes that the Commission 
limit application of its proposal to requests for long-term 
transmission service. MISO/PJM States suggest that the Commission 
consider requiring point-to-point transmission customers to offer a 
reservation price at which they would be willing to sell their 
transmission service.
---------------------------------------------------------------------------

    \836\ E.g., EEI and MidAmerican.
---------------------------------------------------------------------------

Commission Determination
    1410. The Commission adopts the NOPR proposal to add price as a 
tie-breaker in determining reservation queue priority when the 
transmission provider is willing to discount transmission service. As a 
result, price will serve as a tie-breaker after pre-confirmation for 
those requests that have not yet been confirmed by the transmission 
customer or have not yet been evaluated by the transmission provider. 
Consistent with the principles currently embodied in the pro forma OATT 
and articulated in Order No. 638, we clarify that, in the event a later 
queued short-term request for

[[Page 12449]]

transmission service preempts a conditional confirmed short-term 
request for transmission service based on price, then the conditional 
confirmed request has a right to match the price offer of the later 
queued request.\837\
---------------------------------------------------------------------------

    \837\ See Order No. 638 at 31,442.
---------------------------------------------------------------------------

    1411. We disagree with WAPA's proposal to limit application of the 
NOPR proposal to requests for long-term transmission service. We 
believe the addition of price as a tie-breaker for discounted firm 
point-to-point transmission service is an economically efficient policy 
for both short-term and long-term firm point-to-point transmission 
service. We recognize that adding another element to the reservation 
priority criteria adds additional complexity. However, we believe that 
the efficiency gains warrant any additional complexity in the few cases 
in which transmission customers bid for transmission service.
    1412. We do not agree with MISO/PJM States' suggestion that the 
Commission require point-to-point transmission customers to offer a 
reservation price at which they would be willing to sell their 
transmission service. The transmission provider may already make 
unscheduled firm transmission service available to other customers on a 
non-firm basis and we have adopted proposals that we believe will 
encourage transmission customers to voluntarily offer to sell firm 
point-to-point transmission service on the secondary market as 
described in section V.C.4 of this Final Rule. As a result, we see no 
reason to require a firm point-to-point customer to offer its reserved 
capacity for sale.
(3) Five-Minute Window for Requests
NOPR Proposal
    1413. In the NOPR, the Commission responded to comments that 
transmission customers that have the financial resources to purchase 
software and employ staff to continually monitor OASIS sites have an 
unfair advantage under a first-come, first-served approach by seeking 
comment on whether any such advantage would be mitigated if all 
requests submitted within a five-minute window were deemed to have been 
submitted simultaneously. The Commission also sought comment on whether 
transmission customers could game a five minute equivalent priority 
standard to request transmission service only after another 
transmission customer has made a request. The Commission further sought 
comment on how to allocate limited transmission capacity among 
equivalent priority requests of equal duration, in the event a five 
minute equivalent priority standard is adopted.
Comments
    1414. Many of the commenters in the West support the proposal to 
treat transmission requests submitted within some specified period of 
time as submitted simultaneously. Supporters of a time window within 
which all requests would be deemed to have been submitted 
simultaneously argue that the proposal would give transmission 
customers who are less sophisticated and have fewer financial resources 
equal access to transmission service.\838\ Other supporters argue that 
such a time window would be particularly appropriate in circumstances 
when a tariff calls for requests to be submitted ``no earlier than'' a 
specific deadline.\839\ In its reply comments, NRECA argues that a 
customer attempting to plan a request under such circumstances may miss 
being the first in time by a matter of seconds because its computer is 
slower than another customer's computer.
---------------------------------------------------------------------------

    \838\ E.g., Bonneville and Santa Clara.
    \839\ E.g., TDU Systems and NRECA.
---------------------------------------------------------------------------

    1415. Supporters of the proposal suggest a number of modifications 
to the Commission's suggested five-minute window. A number of 
commenters suggest a window longer than five minutes.\840\ For 
instance, Bonneville proposes a system similar to PJM's 30 minute 
window for monthly service. On the other hand, Manitoba Hydro suggests 
a shorter window and a limit on the number and size of requests, 
claiming this would reduce the potential for gaming and/or anti-
competitive behavior. A number of commenters also suggest that such a 
system should be limited to short-term transmission service \841\ and/
or should not apply to requests for transmission service submitted 
close to the hour that service commences.\842\ In its reply comments, 
PNM-TNMP asserts that, if the Commission implements a five-minute 
window policy, then the policy should not be limited to long-term 
transactions. In its reply comments, NRECA argues that requests 
submitted within a five-minute window should not be publicly available 
until the window has closed in order to prevent competitors from 
requesting the same service simply to disrupt the transmission service 
procurement process. Similarly, Bonneville suggests that the 
reservation process should be conducted like a blind auction, so that 
requests are not visible on OASIS until the window closes.
---------------------------------------------------------------------------

    \840\ E.g., Bonneville and CREPC.
    \841\ E.g., Bonneville and Nevada Companies.
    \842\ E.g., Bonneville and NRECA.
---------------------------------------------------------------------------

    1416. Many of the large power marketers and transmission providers 
in the East oppose the notion of a submittal window. Opponents of a 
time window within which all requests would be deemed to have been 
submitted simultaneously suggest that the proposal is an unnecessary 
complication and may actually be counterproductive to the Commission's 
ultimate goal due to issues regarding how transmission service would be 
allocated among simultaneous requests.\843\ EEI notes that there is no 
limit on how far in advance a transmission customer may submit requests 
for firm transmission service, so the likelihood that any two requests 
are submitted within the same five minute period is low. Powerex argues 
that the simplicity of the first-come, first served approach limits the 
number of disputes. In its reply comments, Powerex argues that none of 
the commenters that favor a five-minute window addressed the 
operational problems that such a proposal would generate.
---------------------------------------------------------------------------

    \843\ E.g., EEI, MidAmerican, Ameren, Constellation, Entergy, 
NorthWestern, PNM-TNMP, WAPA, Powerex, and Indianapolis Power Reply.
---------------------------------------------------------------------------

    1417. Some commenters argue that a pro rata allocation of 
simultaneous requests of equal duration will result in all transmission 
customers acquiring less transmission service than they need to 
complete their wholesale transactions.\844\ As a result, these 
commenters suggest that the need to provide transmission customers with 
usable quantities of transmission service will necessarily lead to 
developing an allocation protocol in addition to allocating based on 
time submitted and duration of request.\845\ Powerex argues that any 
system that creates a time window within which all requests would be 
deemed to have been submitted simultaneously will lead transmission 
customers to inflate the quantity of service they request in order to 
get quantity of service they actually desire. Other commenters make 
suggestions regarding the manner by which transmission service should 
be allocated among simultaneously submitted requests. Bonneville 
believes that each transmission provider should develop an allocation 
method appropriate to its system. CREPC suggests that price be used as 
a secondary tie-breaker after duration. TDU Systems argue that using 
duration

[[Page 12450]]

as a tie-breaker for simultaneous requests could discriminate against 
purchased power contracts that are designated as network resources.
---------------------------------------------------------------------------

    \844\ E.g., Powerex and TranServ.
    \845\ Id.
---------------------------------------------------------------------------

Commission Determination
    1418. Based on the comments received, it appears that the desire 
for a time window within which all requests would be deemed to have 
been submitted simultaneously is largely limited to market participants 
in the Western Interconnection. With one exception, we will not mandate 
a change to our current first-come, first-served policy to address an 
issue that appears to be regional in nature. Rather, we will allow 
transmission providers to propose a window within which all 
transmission service requests the transmission provider receives will 
be deemed to have been submitted simultaneously. Transmission providers 
will have discretion to determine which transmission services will be 
subject to a submittal window policy. We believe the transmission 
provider is in the best position to determine whether it can 
accommodate a submittal window for a specific transmission service and 
the need for such a window.
    1419. In order to ensure that transmission service is not awarded 
in an arbitrary fashion and to ensure that transmission customers who 
are less sophisticated and have fewer financial resources have equal 
access to transmission service, we will require transmission provider 
who set a ``no earlier than'' time for request submittal to treat all 
transmission service requests received within a specified period of 
time as having been received simultaneously. We agree with those 
commenters that argue that a time window within which all requests 
would be deemed to have been submitted simultaneously is particularly 
appropriate in circumstances when a tariff or business practice calls 
for requests to be submitted no earlier than a specific deadline. As 
NRECA argues, there is no meaningful difference between requests for 
transmission service that are identical in all respects except that one 
request is received by the transmission provider seconds ahead of 
another request because one customer's computer is slower than another 
customer's computer. EEI is correct that NAESB's uniform business 
practices do not limit how far in advance a transmission customer may 
submit requests for firm transmission service.\846\ However, a number 
of transmission providers have modified their tariffs or adopted 
business practices that mandate that requests can be submitted no 
earlier than a specific deadline.\847\ In these instances, multiple 
requests for transmission service can be submitted at approximately the 
same time. We generally agree with Powerex's assertion that the 
simplicity of the current first-come, first served approach limits the 
number of disputes. However, when a transmission provider establishes a 
``no earlier than'' deadline, submittals that are received by the 
transmission provider within a matter of seconds cannot be meaningfully 
differentiated. A transmission provider with such a business practice 
or tariff provision will be required to modify its tariff to include 
its proposed specified period of time. We will evaluate each proposal 
on a case-by-case basis, as described below.
---------------------------------------------------------------------------

    \846\ See NAESB Business Practice Standard 001-4.13.
    \847\ For instance, Idaho Power Company has adopted a business 
practice that requests for monthly firm transmission service cannot 
be submitted earlier than 11 months prior to operation. Portland 
General Electric has adopted a business practice that Daily Firm ATC 
on the California-Oregon Intertie will be posted at or about 7:11 
a.m. Pacific on the day prior to operation and that requests that 
are submitted prior to ATC being posted will be refused. SPP has 
modified its tariff so that requests for monthly firm transmission 
service cannot be submitted more than 90 days prior to the first day 
of operation.
---------------------------------------------------------------------------

    1420. We will allow transmission providers to propose the period of 
time within which all requests would be deemed to have been submitted 
simultaneously. We believe the transmission provider is in the best 
position to identify the window it can operationally accommodate. We 
expect the submittal window to be open for at least five minutes unless 
the transmission provider can present a compelling rationale to justify 
a shorter submittal window.
    1421. We agree with NRECA and Bonneville's suggestion that requests 
submitted within a specified window should not be publicly available 
until the window has closed in order to prevent competitors from 
requesting the same service simply to disrupt the transmission service 
procurement process.
    1422. We will require each transmission provider that is required 
to, or decides to, deem all requests submitted within a specified 
period as having been submitted simultaneously to propose a method for 
allocating transmission capacity if sufficient capacity is not 
available to meet all requests submitted within the specified time 
period. We agree with Bonneville that the transmission provider is in 
the best position to determine an allocation that is appropriate to its 
system and that cannot be gamed in the manner suggested by Powerex and 
TranServ. We believe that transmission providers will be able to 
develop allocation methods, like the method PJM uses to allocate 
monthly firm point-to-point transmission service, that address the 
operational issues Powerex and TranServ raise.
(4) Right of First Refusal and Preemption
    1423. While not specifically addressed in the NOPR, a few 
commenters use the Commission's proposed introduction of hourly firm 
service, discussed above, to argue that the Commission should take the 
opportunity to clarify or revise the right of first refusal for short-
term transmission service requests.
    1424. To understand commenter concerns, it is useful to note the 
relevant components of the reservation and scheduling process in the 
pro forma OATT. Reservations for short-term firm point-to-point 
transmission service are available on a first-come, first-served basis 
and are conditional based upon the length of the requested transaction 
as explained further below. If the transmission system becomes 
oversubscribed, longer-term service may preempt shorter-term service, 
up to a specified period. The shorter-term reservation holder has a 
right of first refusal to match the longer-term reservation, but such 
right must be exercised within 24 hours of being notified of the 
competing reservation, or earlier to comply with the scheduling 
deadline.
Comments
    1425. Salt River argues that the time required to administer the 
right of first refusal--which includes contacting customers and 
allowing time to exercise the right of first refusal--is overwhelming. 
Salt River argues that the current OASIS business practices do not 
permit adequate time to implement these rules, and the industry lacks 
the software to either streamline the effort or ensure quality control. 
Salt River contends that for hourly, daily, and weekly requests, the 
complexity and potentially unjust results of administering preemption 
and the right of first refusal rules outweighs any potential benefits. 
Accordingly, Salt River recommends revisions to the pro forma OATT that 
make the right of first refusal available only to monthly requests for 
service.
    1426. To address the complications arising from preemption and the 
right of first refusal, Duke proposes several revisions to the pro 
forma OATT: only

[[Page 12451]]

pre-confirmed requests would trigger preemption; confirmed requests 
could not be displaced by longer-term requests; only monthly customers 
subject to preemption would be given a right of first refusal (Salt 
River proposes a similar OATT revision); and, profiled requests (i.e., 
requests for transmission that may have different MW values for each 
hour of the day, and may even include some hours where the MW value is 
zero) would not be granted priority over confirmed reservations. 
TranServ also asks the Commission to provide guidance establishing the 
earliest and latest submission times and maximum successive or 
consecutive terms of service required. TranServ contends it is 
unreasonable that a request for daily firm service could be submitted 
years in advance and then have a right of first refusal to match any 
longer-term request for service.
    1427. To eliminate the potential for more complexity, TranServ 
requests that the Commission eliminate the conditional nature of short-
term point-to-point service under the OATT. Whether the Commission 
adopts this recommendation, TranServ further recommends that the 
Commission revise the timing provisions for requesting short-term 
point-to-point service to reduce overlap for submission of requests 
that would trigger the need for preemption. TranServ and Duke recommend 
a reservation or bidding process in which one increment of service 
(monthly, weekly, daily, and hourly) is available at a time, with each 
successive shorter increment of service becoming available after the 
reservation or bidding window for the preceding longer increment has 
closed.
    1428. NorthWestern requests that the Commission clarify whether the 
terms ``reservation'' and ``request'' used in section 13.2 (Reservation 
Priority) are used interchangeably. If they are not used 
interchangeably, and ``reservation'' is meant to be a confirmed 
request, while ``request'' is a queued request that has not been 
confirmed, NorthWestern suggests that the sentence that includes the 
two uses of ``reservation'' creates confusion because, if both requests 
are confirmed, then either sufficient capacity exists to accept both 
requests, or the transmission provider accepted requests that exceed 
the ATC. To avoid confusion, then NorthWestern recommends that the 
second use of ``reservation'' should be changed to ``request.'' If so, 
to avoid the suggestion that the section is attempting to distinguish 
between requests that have been confirmed from those simply queued, 
NorthWestern recommends that the Commission consider changing all of 
the ``reservation'' references to ``request.''
Commission Determination
    1429. Based on the issues raised in comments, we find that changing 
the ``first come, first served'' nature of the reservation process and 
right of first refusal process is not warranted at this time. The 
``first-come, first-served'' principle facilitates the administration 
of the reservation process and benefits customers because there can be 
little confusion about how to comply with it.
    1430. The remaining concerns regarding administering the right of 
first refusal are addressed below. First, when a longer-term request 
seeks capacity allocated to multiple shorter-term requests, the 
shorter-term customers should have simultaneous opportunities to 
exercise the right of first refusal. Duration, pre-confirmation status, 
price, and time of response would then be used to determine which of 
the shorter-term requests will be able to exercise the right of first 
refusal, consistent with the Commission's tie breaking provision in 
section 13.2(ii). Second, to minimize the potential for gaming, a 
preempting longer request must be for a fixed capacity over the term of 
the request.
    1431. We agree with NorthWestern's assertion that the sentence in 
section 13.2(iii) of the pro forma OATT that includes the two uses of 
``reservation'' creates confusion. Therefore, we clarify that the terms 
``reservation'' and ``request'' are not used interchangeably; 
``reservation'' is meant to be a confirmed request, while ``request'' 
is a queued request that has not been confirmed. To clarify the 
distinction between use of the terms ``request'' and ``reservation'' in 
section 13.2(iii), we will revise that section so that the sentence 
``Before the conditional reservation deadline, if available transfer 
capability is insufficient to satisfy all Applications, an Eligible 
Customer with a reservation for shorter-term service has the right of 
first refusal to match any longer-term reservation before losing its 
reservation priority'' is replaced by the sentence ``Before the 
conditional reservation deadline, if available transfer capability is 
insufficient to satisfy all Applications, an Eligible Customer with a 
reservation for shorter-term service has the right of first refusal to 
match any longer-term request before losing its reservation priority.''
6. Designation of Network Resources
a. Qualification as a Network Resource
    1432. Taken together, the following sections of the pro forma OATT 
describe the resources a network customer can appropriately designate 
as a network resource. Section 30.1 of the pro forma OATT describes 
network resources as all generation owned or purchased by the network 
customer designated to serve network load under the tariff. Section 
30.1 also indicates that network resources may not include resources 
that are committed for sale to non-designated third-party load or 
otherwise cannot be called upon to meet the network customer's network 
load on a noninterruptible basis. Pursuant to section 30.7 of the pro 
forma OATT, the network customer must demonstrate that it owns or has 
committed to purchase generation pursuant to an executed contract in 
order to designate a generating resource as a network resource. 
Alternatively, the network customer may establish that execution of a 
contract is contingent upon the availability of network service. 
Section 29.2 requires the network customer to provide the following 
information about a power purchase agreement that is to serve as a new 
designated network resource: source of supply, control area location, 
transmission arrangements and delivery point(s) to the transmission 
provider's transmission system.
    1433. As the Commission noted in the NOPR, a number of orders 
address what types of resources meet the criteria set out in sections 
30.1 and 30.7 of the pro forma OATT. In MSCG, the Commission stated 
that network resources must be generating resources owned by the 
network customer or purchases of noninterruptible power under executed 
contracts that require the network customer to pay for the 
purchase.\848\ In WPPI, the Commission found that a network customer 
can designate as a network resource a system purchase that is not 
backed by a specific generator.\849\ The Commission found that 
Wisconsin Public Service Corporation (WPS) had appropriately designated 
a power purchase as a network resource, even though the power purchase 
agreement did not require WPS to take energy around the clock and 
allowed WPS to convert its energy purchase to a discounted product that 
could be interrupted.\850\ In addition, the Commission stated that, 
because the pro forma OATT requires a power purchase to be 
noninterruptible, third-party transmission arrangements to deliver the 
resource to the network have to be

[[Page 12452]]

noninterruptible as well.\851\ In Illinois Power, the Commission found 
that a firm purchase need not be backed by a capacity purchase to 
qualify as a network resource.\852\
---------------------------------------------------------------------------

    \848\ Morgan Stanley Capital Group v. Illinois Power Co., 83 
FERC ] 61,204 at 61,911-12 (1998), order on reh'g, 93 FERC ] 61,081 
(2000) (MSCG).
    \849\ Wisconsin Public Power Inc. v. Wisconsin Public Service 
Corp., 84 FERC ] 61,120 at 61,650-51 (1998) (WPPI).
    \850\ Id.
    \851\ Id. at 61,660.
    \852\ Illinois Power Co., 102 FERC ] 61,257 at P 14 (2003), 
reh'g denied, 108 FERC ] 61,175 (2004) (Illinois Power).
---------------------------------------------------------------------------

NOPR Proposal
    1434. In the NOPR, the Commission proposed to maintain its current 
policy regarding the power purchase agreements that network customers 
may designate as network resources. In particular, the Commission 
proposed that a network customer would continue to be able to designate 
resources from system purchases not linked to a specific generating 
unit, provided the power purchase agreement is not interruptible for 
economic reasons, does not allow the seller to fail to perform under 
the contract for economic reasons, and requires the network customer to 
pay for the purchase. In addition, the Commission reiterated that 
third-party transmission arrangements to deliver the purchase to the 
network must be noninterruptible.
    1435. Regarding seller's choice contracts, the Commission explained 
that a power purchase agreement that is structured so that a network 
customer cannot specify all of the information required by section 
29.2(v) of the pro forma OATT cannot be designated as a network 
resource. Specifically, the Commission reiterated that a request to 
designate a new network resource must provide the information including 
the source of supply, control area location, transmission arrangements, 
and delivery point(s) to the transmission provider's transmission 
system. The Commission proposed that, when designating a system 
purchase as a new network resource, a network customer must identify 
the resource as a system purchase as well as the control area from 
which the power will originate.
    1436. In response to suggestions that liquidated damages (LD) 
products should not be designated network resources because they are 
interruptible for economic reasons, the Commission proposed to clarify 
that network customers may not designate as network resources those 
power purchase agreements that give the seller a contractual right to 
compensate the buyer instead of delivering power even if the seller is 
able to deliver power. For instance, the Commission proposed that a 
network customer may not designate as a network resource a purchase 
agreement that allows the seller to interrupt sales under the purchase 
agreement for reasons other than reliability, but allows the buyer to 
force delivery at a higher price. In addition, the Commission proposed 
that a network customer may not designate as a network resource a 
purchase agreement that requires a seller to pay the buyer's cost of 
replacement power when the seller chooses not to deliver energy for 
economic reasons.
Comments Overview
    1437. Most commenters argue that the Commission must provide 
further clarification than given in the NOPR, particularly with regard 
to the eligibility of firm LD power products and the information 
required by section 29.2(v) of the pro forma OATT for seller's choice 
contracts. Various commenters also argue that the Commission's 
precedent on this issue is contradictory and that the Commission's 
policy with respect to designation of network resources may violate 
section 217 of the FPA and conflict with state jurisdiction.
(1) LD Contracts
Comments
    1438. Many commenters express general support for some or all of 
the Commission's clarifications in the NOPR with regard to 
ineligibility of resources which are interruptible for economic reasons 
and/or that allow the seller to compensate the buyer instead of 
delivering power even if the seller is able to deliver power.\853\ 
However, many commenters express concern about the clarity of the 
policy.\854\
---------------------------------------------------------------------------

    \853\ E.g., Ameren, BART, Constellation, Duke, Entegra, Entergy, 
Morgan Stanley, MISO, NorthWestern, Progress Energy, Sempra Global, 
Southern, Suez Energy NA, and TranServ.
    \854\ E.g., AMP-Ohio, APPA, Duke, EEI, Entergy, Fayetteville, 
Morgan Stanley, NCPA, Northwest IOUs, Northwest Parties, MISO/PJM 
States, PGP, Pinnacle, PNM-TNMP, Salt River, Sempra Global, 
Southern, TAPS, Utah Municipals, and WSPP.
---------------------------------------------------------------------------

    1439. In particular, several parties contend that it is in fact the 
firmness of the contract and not the mere existence of an LD provision 
describing the remedies in case of a failure to perform that determines 
the eligibility of a power purchase agreement to be designated as a 
network resource.\855\ TAPS argues that, in order to determine the 
firmness of a purchase, one must look at the criteria for excusing a 
failure to supply. AMP-Ohio, MISO, and NCPA also express support for 
this position, pointing to the Commission's finding in Dynegy \856\ 
that the inclusion of an LD provision in EEI's Master Power Purchase 
and Sale Agreement's Firm LD product (EEI's Firm LD Product) does not 
inherently make that product less firm.
---------------------------------------------------------------------------

    \855\ E.g., AMP-Ohio, Northwest IOUs, NRECA Reply, PGP, 
Pinnacle, Sempra Global, Strategic Energy Reply, and TAPS.
    \856\ Dynegy Midwest Generation, 101 FERC ] 61,295 (2002), reh'g 
dismissed, 108 FERC ] 61,175 (2004) (Dynegy).
---------------------------------------------------------------------------

    1440. Several commenters argue that, when the Commission in Dynegy 
considered the acceptability of EEI's Firm LD Product as a designated 
network resource, it neglected to consider the presence of a provision 
which appears to contradict its decision.\857\ They point to the 
Commission's statement in Dynegy that EEI's Firm LD Product ``does not 
permit the power to be interrupted for economic reasons, or at the 
discretion of either party, but only if a force majeure occurs.'' \858\ 
Some contend that the Commission's conclusion ignored the fact that 
EEI's Firm LD Product actually allows power to be interrupted for any 
reason, including economic reasons, after which the agreement then 
provides LDs as a remedy if the interruption was not due to a force 
majeure event.\859\ Duke and EEI note that contracts under EEI's Firm 
LD Product agreement or similar agreements have become commonplace 
since the Commission's Dynegy decision and that clarification regarding 
their use as network resources is required to address industry 
confusion.
---------------------------------------------------------------------------

    \857\ E.g., Duke, Dynegy Reply, EEI, and Southern.
    \858\ Dynegy at P 21.
    \859\ E.g., Duke, EEI and Southern. EEI notes that its Firm LD 
Product is distinct from its ``System Firm'' and ``Unit Firm'' 
products in its Master Power Purchase and Sale Agreement, each of 
which excuses a failure to perform only for force majeure and 
neither of which permits a party to fail to perform and pay 
liquidated damages.
---------------------------------------------------------------------------

    1441. Several commenters disagree that the EEI Firm LD Product 
gives parties the right to interrupt for any reason, including economic 
reasons, provided that LDs are paid by the non-performing party.\860\ 
Hoosier argues on reply that EEI and Southern have misunderstood the 
Commission's intent in Dynegy. Hoosier contends that the Commission 
correctly found in Dynegy that the EEI Firm LD Product does not permit 
power to be interrupted for economic reasons, or at the discretion of 
either party, but only if a force majeure event occurs. Thus, Hoosier 
argues, the EEI Firm LD Product does not give the seller a right to 
interrupt for any reason other than force majeure, and any seller that 
interrupts for economic reasons is clearly in breach of its obligations 
to perform under the contract and must

[[Page 12453]]

pay damages. Hoosier acknowledges that a seller always has the choice 
of not performing its obligations and paying damages, but that is not 
peculiar to the EEI Firm LD Product. Hoosier maintains that any party 
to any contract has the ability, but not the right, to breach its 
obligations under the contract and pay damages. According to Hoosier, 
the only difference in the case of the EEI Firm LD Product is that the 
parties have stipulated beforehand as to the measure of the damages 
required of a seller in breach, in order to minimize litigation over 
damages. This stipulation, Hoosier argues, conveys no additional 
substantive rights on either party.
---------------------------------------------------------------------------

    \860\ E.g., Hoosier Reply, Strategic Energy Reply, and Utah 
Municipals.
---------------------------------------------------------------------------

    1442. Several parties note that firm LD contracts account for a 
significant number of currently utilized products and that disallowing 
these product to be designated as network resources may create 
significant disruption.\861\ Commenters supporting continued use of 
firm LD contracts as designated network resources argue that allowing 
products structured on EEI's Firm LD Product has not created 
reliability problems.\862\ Southern argues that the Commission should 
not set criteria that would place in jeopardy an array of products that 
have a firm LD dimension. Southern further states that such products 
are among the most reliable in instances where market prices are very 
high (where LDs could be quite substantial) and that just about any 
power purchase/sale contract can be financially settled in real-time or 
for a given period in lieu of physical delivery during that period. The 
fact that some contracts set out in advance the terms of such 
settlement (so to render commerce more efficient and liquid) does not, 
Southern argues, render those contracts any less qualified for 
designation as network resources. Thus, Southern encourages the 
Commission to reconsider its revised guidance regarding the 
ineligibility of contracts structured after EEI's Firm LD Product. Utah 
Municipals agrees, and similarly requests that contracts under EEI's 
Firm LD Product be allowed to qualify as network resources.
---------------------------------------------------------------------------

    \861\ E.g., APPA, Hoosier Reply, NCPA, Southern, Strategic 
Energy Reply, and Utah Municipals.
    \862\ E.g., EEI, Hoosier Reply, Southern and NCPA.
---------------------------------------------------------------------------

    1443. Morgan Stanley argues that the notion that firm LD contracts 
do not contribute as much to resource adequacy as contracts tied to 
individual physical resources is inaccurate. Morgan Stanley contends 
that the incentive to ensure performance is far greater with a firm LD 
obligation than with unit contingent and system firm contracts. Morgan 
Stanley explains that unit contingent and system firm contracts require 
delivery if the unit or group of units performs and excuses delivery if 
they do not, while a Firm LD obligation requires delivery so long as it 
is physically possible to achieve delivery, regardless of the cost of 
doing so. Thus, according to Morgan Stanley, firm LD products can 
enhance supply security because they are not dependent upon the 
performance of an individual unit or units, but rather put the burden 
and opportunity on the supplier to use multiple physical resources to 
meet its obligations.
    1444. APPA also requests reconsideration of this issue, arguing 
that its members are often presented with power purchase agreements 
based on EEI's Firm LD Product and that they are not always successful 
in negotiating amendments to such agreements with suppliers. APPA 
argues that an LSE can use a diverse resource portfolio, including firm 
LD power purchase agreements, to serve its load economically, while 
meeting reliability requirements and advancing other important policy 
objectives (diverse fuel mix, use of renewable energy, etc.). APPA 
urges the Commission to allow such use if it is consistent with the 
commercial practices in a region.\863\
---------------------------------------------------------------------------

    \863\ MISO/PJM States similarly argue that whether a particular 
contract with LD provisions can serve as a designated resource 
should be decided within the RTO stakeholder process.
---------------------------------------------------------------------------

    1445. NCPA also opposes forbidding firm LD products without looking 
more fully into their merits and the potential safeguards that could be 
built into them. NCPA recognizes that firm LD contracts raise certain 
issues under the pro forma OATT and also pose issues for planning where 
a specific resource is not designated, but these problems are not 
significantly different from the problems of a large transmission owner 
designating its entire fleet as network resources for its entire load. 
Rather than ban LD contracts from an important segment of the market, 
several commenters suggest that the Commission convene a separate 
proceeding or conference to further investigate the issue.\864\
---------------------------------------------------------------------------

    \864\ E.g., APPA Reply, Morgan Stanley, and NCPA.
---------------------------------------------------------------------------

    1446. Other commenters argue against allowing the designation as 
network resources of contracts that permit the interruption of power 
sales for reasons other than reliability as long as LDs are paid.\865\ 
Detroit Edison argues in its reply comments that a seller's decision to 
pay the ``costs of `cover' '' under these contracts is of no value to 
an LSE that lacks deliverable alternatives. Detroit Edison further 
claims that, contrary to Southern's assumption that a failure to 
deliver under a firm LD contract would result in substantial non-
delivery penalties, one would expect a supplier afforded the option to 
divert power to a higher priced market that produces a net financial 
gain would elect to interrupt service under the power sales contract 
and pay the LDs. Detroit Edison contends that purchasers would be left 
hanging during periods of supply shortage when firm physical supply is 
most critical.
---------------------------------------------------------------------------

    \865\ E.g., Duke, Dynegy, and Detroit Edison Reply.
---------------------------------------------------------------------------

    1447. In its reply comments, Duke asserts that allowing firm LD 
products to be designated as network resources would result in network 
customers leaning on its system. Although it has doubts about whether 
the EEI Firm LD Product actually contains language that prohibits 
interruptions for economic reasons, Duke would find the inclusion of 
such language in purchased power agreements to provide sufficient 
firmness to allow the contract to be designated as a network resource. 
In its reply comments, Dynegy argues that allowing designation of firm 
LD products is simply inconsistent with the existing OATT requirements 
that a transmission customer either own, purchase or have rights to 
generation.
    1448. Northwest IOUs request that the Commission clarify whether 
the limitations for qualification of a network resource, such as the 
presence or absence of an LD clause, would prevent a transmission 
provider from using such a resource for service to its bundled native 
load customers. Northwest IOUs state that, if the non-rate terms and 
conditions do not apply directly by requirement of the Final Rule, but 
only under a comparability test where there is a comparison to network 
customers, then that position should be made clear. They further note 
that some transmission providers have no comparable network service, or 
no service involving generating units within the transmission 
provider's control area. Accordingly, Northwest IOUs request that the 
Commission clarify whether, in those instances, the limitations for 
qualification of a network resource would apply.
    1449. Many commenters also argue for the eligibility of service 
provided under the WSPP Service Schedule C (Schedule C) agreement.\866\ 
In particular, WSPP argues that its Schedule C product satisfies the 
Commission's requirements for designation as a network resource because 
it requires the seller to deliver power except under very limited

[[Page 12454]]

circumstances, such as force majeure, and that the agreement itself 
clearly provides that it is a firm product. However, WSPP notes that 
its product, like most if not all wholesale power sales contracts, 
contains a damages provision which could be characterized as an LD 
provision. WSPP contends that such provision is used simply to avoid 
the need to litigate damages and not to permit a seller to ignore its 
delivery obligations by financially settling a firm power sale. WSPP 
states that it is not intended that sellers be allowed to refuse to 
deliver for economic reasons. Therefore, WSPP requests clarification 
that its Schedule C product is eligible for designation as a network 
resource, and notes the potential for significant disruptions in the 
market and WSPP member sales of firm products if its Schedule C product 
is not considered eligible for designation as a network resource.
---------------------------------------------------------------------------

    \866\ E.g., APPA, EEI, Entergy, Northwest Parties, Salt River, 
Utah Municipals, and WSPP.
---------------------------------------------------------------------------

    1450. EEI and Northwest Parties note that, in some instances, both 
the sellers and buyers of the Schedule C product designate that product 
as a network resource, since it appears to meet the pro forma OATT 
definition of a network resource for both parties because the agreement 
allows interruptions to serve native loads. If only one party is found 
to be able to designate the Schedule C product as a network resource, 
EEI argues that the other party would run the risk of civil penalties 
for making an incorrect attestation and may also lose the transmission 
rights that it needs to serve its native load or network load. 
Northwest Parties request specific clarification as to whether power 
purchased under Schedule C from a seller with public utility or 
statutory obligations to its customers is to be considered power 
available to meet the purchaser's network load on a non-interruptible 
basis, given that the seller may interrupt service under the power 
sales contract to meet its public utility or statutory obligations. If 
the Commission decides that the Schedule C transactions cannot be 
designated as network resources, Northwest Parties asks the Commission 
to state whether such transactions would be eligible if the WSPP 
service agreement requires the seller to give the purchaser advance 
notice of an interruption. Salt River also asks that, if Schedule C is 
found to be ineligible, the Commission identify the specific changes 
needed to that contract to allow for designation.
    1451. Beyond the eligibility of contracts with LDs to be designated 
as network resources, EEI and Duke also argue that there is a conflict 
between the policy guidance given in Dynegy (that a power purchase 
agreement which is interruptible for reasons other than reliability is 
not eligible for designation as a network resource) and the guidance 
given in WPPI \867\ (that a power purchase agreement which permits 
curtailment to serve the seller's native load is eligible for 
designation as a network resource). Duke argues that, since the type of 
contracts contemplated in WPPI are clearly interruptible for reasons 
other than reliability, WPPI should no longer be deemed valid case law 
in light of the Commission's proposed clarifications in the NOPR. Duke 
argues that allowing such contracts to be designated as network 
resources creates reliability risks and likely permits two entities to 
designate the same generation as network resources. While Duke 
acknowledges that exceptions to this rule may be necessary in the 
Western Interconnection, it does not support an exception for the 
Eastern Interconnection. EEI argues that the conflict between the 
Dynegy and WPPI standards has resulted in different transmission 
providers and customers using different standards for designation of 
network resources. EEI therefore asks the Commission to clarify 
precisely what contracts qualify as a network resource before it 
implements its proposed attestation requirement.
---------------------------------------------------------------------------

    \867\ WPPI, 84 FERC at 61,652.
---------------------------------------------------------------------------

Commission Determination
    1452. Many commenters seek clarification of the eligibility of 
power purchase agreements with LD provision to be designated as network 
resources. In clarifying our policy concerning firm LD products, we 
turn first to the apparent confusion surrounding the Commission's 
findings in Dynegy. Duke, Dynegy, EEI, and Southern argue that the 
Commission incorrectly found in Dynegy that the EEI Firm LD Product 
could not be interrupted for economic reasons. These parties argue that 
the EEI Firm LD product actually allows power to be interrupted for any 
reason, including economic reasons, after which LDs are assessed if the 
interruption was not due to a force majeure event. We disagree. As 
Hoosier points out, the EEI Firm LD Product does not permit power to be 
interrupted for economic reasons. While any party to any contract can 
choose to fail to perform, that does not convey a contractual right to 
fail to perform. The EEI contract clearly obligates the supplier to 
provide power, except in cases of force majeure. Thus, the contract 
does not allow interruption for economic reasons. The presence of an LD 
provision in the EEI Firm LD Product does not permit the seller to 
violate the terms of the contract, but rather merely specifies the 
damages that must be paid if the seller fails to perform under the 
contract. As noted by many commenters, it is the firmness of a power 
purchase contract, and not simply the presence or absence of an LD 
provision, that determines the eligibility of that power purchase to be 
designated as a network resource.
    1453. We conclude, however, that the firmness of an obligation to 
provide under a contract with an LD provision is informed by the 
particular terms of the LD provision. The type of LD provision commonly 
seen in firm LD products, such as the EEI Firm LD Product, obligates 
the supplier, in the case of interruption for reasons other than force 
majeure, to make the aggrieved buyer financially whole by reimbursing 
them for the additional costs, if any, of replacement power. In 
contrast to this ``make whole'' type of LD provision, other types of LD 
provisions establish penalties at a fixed-dollar amount, cap penalties 
at some level, or are otherwise not equivalent to a general ``make 
whole'' type provision. Under these other types of LD provisions, 
suppliers only need to compare their savings from interrupting with the 
specified LD penalty when deciding whether to interrupt power sales. 
Because such a consideration may not take into account the cost of 
replacement power, such LD provisions could lead to inefficient 
supplier interruption and economic harm to the buyer.
    1454. We find that a ``make whole'' LD provision, such as that 
found in the EEI Firm LD Product and in the WSPP Schedule C agreement, 
does not create incentives that are incompatible with the firmness of 
the overall product. ``Make whole'' LDs require the seller to consider 
the price of the replacement power, if it is available, to its original 
buyer if the seller fails to perform under the contract. There could, 
of course, be situations where the supplier is still presented with a 
net financial gain and has an incentive to interrupt, but those 
incentives would seem to be the same incentives faced by a designated 
network resource that is a specific generating plant owned by the 
network customer. In such an instance, the network customer may 
determine, from time to time, that it is more economic to substitute 
power from an alternate source in order to allow the originally 
designated resource to either shut down or to sell its output into the 
wholesale market. We find no reason to create financial incentives that 
make purchased power designated as a

[[Page 12455]]

network resource financially ``more firm'' than owned generation.
    1455. Accordingly, we find that the inclusion of a ``make whole'' 
LD provision in a power purchase agreement does not disqualify that 
agreement from being designated as a network resource. However, other 
types of LD provisions may create incentives that are incompatible with 
the firmness of a power purchase agreement. Thus, as of the effective 
date of this Final Rule, power purchase agreements designated as 
network resources may only contain LD provisions that are of the ``make 
whole'' type. Conversely, power purchase agreements containing LD 
provisions that provide penalties of a fixed amount, that are capped at 
a fixed amount, or that otherwise do not require the seller to pay an 
aggrieved buyer the full cost of replacing interrupted power, are not 
acceptable. Any contract which contains an unacceptable LD provision, 
but otherwise qualifies for designation as a network resource and has 
been properly designated as a network resource prior to the effective 
date of this Final Rule, will be grandfathered only until the earlier 
of (1) the expiration of the current term of the power purchase 
agreement or (2) an indefinite termination \868\ of the power purchase 
agreement as a designated network resource pursuant to section 30.3 of 
the pro forma OATT. In response to the many comments received, we 
confirm that the LD provisions in both the EEI Firm LD Product and the 
WSPP Schedule C agreement are acceptable.\869\
---------------------------------------------------------------------------

    \868\ As discussed below, in section V.D.6.c, termination of 
network resource status may either be temporary or indefinite. A 
firm LD contract that does not have a ``make whole'' LD provision 
and which is grandfathered here may continue to be temporarily 
terminated in order to make third-party sales without jeopardizing 
its eligibility to be redesignated after a third-party sale. 
However, once a network resource is indefinitely terminated, it must 
comport with the requirements for LD provisions, and all other 
requirements for designation of network resources, before it can be 
redesignated.
    \869\ As discussed below, however, we otherwise find that the 
WSPP Schedule C agreement does not comply with the requirements for 
designation as a network resource because it allows for interruption 
for reasons other than reliability. We therefore do not need to 
address requests to clarify that both the buying and selling party 
to a WSPP Schedule C contract can designate network resources 
associated with the contract.
---------------------------------------------------------------------------

    1456. Detroit Edison argues that a seller's obligation to pay the 
cost of replacement power under firm LD contracts is of no value to an 
LSE that lacks deliverable alternatives. Detroit Edison appears to 
assume that, as long as an LSE purchasing power had no deliverable 
alternatives from which to procure power, a designated supplier would 
not be liable for damages if it chose to interrupt power sales to the 
buyer for reasons other than force majeure. We disagree. Detroit Edison 
is addressing the fairly unusual circumstance where a power supply is 
interrupted, there are no available alternatives in the market, and 
firm load therefore must be interrupted. We fail to see why this 
circumstance, and the difficulty of calculating damages for lost load 
when it occurs, provides a reason why a particular network resource (an 
LD contract) should not qualify under the pro forma OATT as a network 
resource.
    1457. We also disagree with Dynegy's argument that allowing the 
designation of firm LD products is inconsistent with the existing OATT 
requirement that a transmission customer own, purchase or have rights 
to generation. As discussed, firm LD contracts that meet the 
Commission's requirements for designation do create for the buyer a 
contractual right to generation and do not contain damage provisions 
which make the actual incentives under such contracts incompatible with 
those present in owned generation.
    1458. In response to Northwest IOUs' request, we also clarify that 
the presence or absence of an LD provision does not prevent a 
transmission provider from using such a resource to serve its bundled 
native load customers. Rather, as we explain above, it is the type of 
LD provision that is controlling. A power purchase contract with a 
``make whole'' remedy could be used to serve native load customers.
    1459. We disagree with Duke and EEI's argument that there is a 
conflict between the policy guidance given in Dynegy (that a power 
purchase agreement which is interruptible for reasons other than 
reliability is not eligible for designation as a network resource) and 
the guidance given in WPPI (that a power purchase agreement which 
permits curtailment to serve the seller's native load is eligible for 
designation as a network resource). We reiterate the Commission's 
finding in WPPI that a power purchase agreement properly designated as 
a network resource may permit curtailment to serve the seller's native 
load. Consistent with the long-standing definition in Order No. 888, 
``curtailment'' contemplates a reduction in service as a result of 
system reliability conditions, not economic reasons.
    1460. Although we find that the LD provision contained in the WSPP 
Schedule C agreement does not impair the firmness of that agreement, we 
note that the agreement otherwise allows interruptions in generation 
service ``to meet [the] Seller's public utility or statutory 
obligations to its customers.'' Thus, the WSPP Schedule C agreement 
appears to allow interruptions for reasons other than reliability and, 
as a result, would not be eligible for designation as a network 
resource under the Dynegy or WPPI precedent. We find that the provision 
in the WSPP Schedule C agreement allowing for interruption of 
generation service in order to serve native load would need to be 
revised to explicitly prohibit interruptions for reasons other than 
reliability of service to native load in order for that provision to 
meet the requirements established under Dynegy and WPPI.
    1461. Maintaining the standard for eligibility established in 
Dynegy and WPPI will further the Commission's goals of preventing undue 
discrimination, promoting comparable treatment of customers, and 
increasing the accuracy of ATC calculations. However, we acknowledge 
that some may currently be relying on the WSPP Schedule C agreement in 
designating network resources and that there may be disruption if we 
were to invalidate the designations of the existing WSPP Schedule C 
resources. Thus, we exercise our discretion not to invalidate existing 
designations of the WSPP Schedule C agreements as a result of 
noncompliance with this particular requirement until the earlier of the 
following: (1) The expiration of the current term of a power purchase 
agreement or (2) redesignation of a previously designated WSPP Schedule 
C resource following a period of temporary or indefinite termination 
pursuant to sections 30.2 and 30.3 of the pro forma OATT. 
Alternatively, parties may voluntarily reform the offending contract 
terms in order to preserve their eligibility for network service.
(2) Off-System Resources
Comments
    1462. Many commenters request clarification or reconsideration of 
the information that is required to be specified in section 29.2(v) of 
the pro forma OATT in order to designate a seller's choice contract or 
system sale as a network resource. Northwest Parties agree with the 
proposal in the NOPR that system sales may be designated by providing 
the control area from which the sale is made, transmission 
arrangements, and delivery points to the transmission provider's 
transmission system.\870\ For system sales, Northwest

[[Page 12456]]

Parties argue that unit-specific information is not needed because such 
sales are, by definition, from a variety of resources and, in any 
event, the resource-specific information is typically not available to 
the purchaser. This is particularly true, they argue, for sales from 
large hydroelectric systems, which are operated as one interconnected 
unit. For purchase contracts, they argue that unit-specific information 
is not needed because it is provided in the generation interconnection 
agreement to the control area where the resource is located. Northwest 
Parties contend that not requiring unit-specific information for 
purchase of power, including purchases of system power, is consistent 
with the Commission's description in the NOPR of the requirements to 
designate a network resource.
---------------------------------------------------------------------------

    \870\ Northwest Parties request similar clarification for 
designation of purchase contracts from one or more specified, 
individual resources.
---------------------------------------------------------------------------

    1463. Pinnacle argues that the Final Rule should recognize that the 
level of detail required by section 29.2(v) may vary depending on 
circumstances and permit the transmission provider to determine the 
level of information necessary for the evaluation of the network 
resource. In some cases, a power purchase agreement may, they argue, 
appropriately refer to more general information than a specific single 
control area or single source of supply.
    1464. In cases where a power purchase agreement is being sourced by 
generating units from an external control area, Entergy contends on 
reply that simply identifying the control area is sufficient for 
purposes of studying the deliverability of that resource. However, in 
cases where the power is sourced by generating units internal to the 
transmission provider's control area, Entergy argues that identifying 
only the control area does not provide sufficient information to study 
deliverability. In that case, Entergy argues that the customer must 
provide the specific information required by section 29.2(v) of the pro 
forma OATT, including the location of the specific generating units. If 
such information is not available at the time of the network resource 
designation, Entergy argues that the customer should still be able to 
designate the agreement as a network resource, but that the customer 
would have to confirm resource deliverability prior to actually 
scheduling the service.
    1465. TDU Systems argue in their reply comments that specifying the 
control area and the interface over which power will enter the 
transmission provider's transmission system from a designated network 
resource in an external control area is sufficient for purposes of 
studying the deliverability of that resource. TDU Systems also argue 
that, for competitive reasons, an LSE should never be required to 
identify the generator or the transmission zone where the generator is 
located.
    1466. In contrast, EEI requests that the Commission modify section 
29.2(v) to clearly state that the transmission provider has the 
discretion to require the network customer to identify the location of 
the generator with more specificity than simply specifying the control 
area in which the network resource is located, since the location will 
affect the flowgate over which the energy will be transmitted. EEI 
argues that it is necessary to narrow the location of the source of a 
power purchase to the system of a particular transmission owner, rather 
than a control area. PNM-TNMP and Duke also support requirements that 
network customers provide more information concerning the location of 
off-system network resources and purchase agreements so that the 
transmission provider can properly evaluate the impact on its system. 
Duke states that Duke Carolinas are now receiving requests to designate 
as network resources power purchase agreements that list the point of 
delivery as ``the PJM control area'' or ``into Southern.''
    1467. Dynegy argues in its reply comments that the Commission has 
never explained how a transmission customer designating a firm LD 
contract as a network resource could ever comply with section 29.2 of 
the pro forma OATT, which requires specific information about the 
generation resource being designated. Dynegy contends that, just like a 
seller's choice contract, a customer is not entitled to any information 
about particular generating assets when entering a firm LD purchase 
contract such as the EEI Firm LD Product. As a result, Dynegy states 
that it is unclear how a network customer would ever be able to 
legitimately designate such contracts as a network resource.
    1468. In order to help ensure that all network resources are in 
fact backed by capacity, Dynegy argues that the Commission should 
require identification of more than just the control area when 
designating a network resource. Dynegy argues that the Commission 
should require the generation owner or trading agent for the generation 
to positively verify that capacity was sold to the entity designating 
that particular generator as a network resource, and that the 
designation is appropriate pursuant to the parties' agreement, as is 
currently required in PJM.
    1469. Because some regions of the country determine ATC using a 
flow-based methodology and other regions use a rated path methodology, 
EEI argues that section 29.2(v) should be modified to permit 
transmission providers to require a network customer to designate the 
point to which the energy is delivered and from which the transmission 
provider will provide network service if it is not delivered at the 
generator bus.
    1470. Duke requests that the Commission resolve an inconsistency 
between the NOPR's statement at P 408 that ``when a network customer is 
designating a system purchase as a new network resource, the source 
information required in section 29.2(v) should identify that the 
resource is a system purchase and should identify the control area from 
which the power will originate,'' and the statement in the very next 
sentence that a ``power purchase agreement that is structured so that a 
network customer cannot specify all of the information required by 
section 29.2(v) cannot be designated as a network resource.'' Duke 
notes that significantly more information is required by section 
29.2(v) (unit size, VAR capability, operating restrictions, variable 
generating cost for redispatch computations, etc.) than the ``control 
area from which the power will originate.''
    1471. Morgan Stanley contends that the information required in 
section 29.2(v) must not disallow designation of seller's choice 
contracts as network resources. They assert that transmission providers 
use security constrained economic dispatch under which the source of 
supply in a contract is generally irrelevant from a planning or 
operational perspective and is therefore not needed. Morgan Stanley 
also argues that, if the underlying network customer's contract permits 
the seller to curtail its dispatch and substitute a source from the 
market, the transmission provider would never actually know the 
location where a network customer's power is coming from and, thus, it 
is unclear why the specification of that source should be a 
requirement. Therefore, Morgan Stanley requests that the Commission 
consider revising 29.2(v) to eliminate the inclusion of information 
that is not necessary or make the provision of such information 
required ``to the extent practicable.''
    1472. Duke replies that Morgan Stanley accurately portrays what 
typically happens under seller's choice contracts, but reaches the 
wrong conclusion about a remedy. Duke argues that, if network customers 
are permitted

[[Page 12457]]

to designate as network resources contracts that may be relatively 
long-term, but under which the seller has no obligation to identify the 
source of the power any sooner than on a day-ahead basis, then ATC may 
be reserved even though there is no intent to use it. Duke also argues 
that allowing seller's choice contracts would hamper the transmission 
provider's ability to plan its system. In Duke's view, it would be 
appropriate to permit a seller's choice contract to be a designated 
network resource at the time transmission service is granted for the 
period such transmission service lasts, as at that point the customer 
will have designated a source and sink.
    1473. Fayetteville recognizes that there are problems related to 
modeling and reliability in contracts for energy which do not specify 
particular units as sources, but argues that these problems are exactly 
the same as those that exist within any vertically integrated utility 
which names its generation fleet as network resources for its native 
load.
Commission Determination
    1474. Many comments were received with respect to seller's choice 
and system purchases. Some comments refer not only to seller's choice 
and system purchases, but also to other possible off-system 
transactions, including sourcing from owned generation located off-
system. We therefore use the term ``off-system resources'' here to 
refer to all such resources.
    1475. The existing requirements in section 29.2(v) are intended to 
ensure that the network customer designating resources on other 
transmission systems provides sufficient information to allow the local 
transmission provider to determine the effect on ATC. Conversely, 
network customers should not be permitted to designate off-system 
resources which are so vaguely defined that the effects on ATC cannot 
be determined. In light of the requests that the Commission clarify 
exactly what information must be provided in order to designate network 
resources located off-system, and what information required by section 
29.2(v) must be posted on OASIS, we will revise section 29.2(v) of the 
pro forma OATT to specify exactly what information is required.
    1476. As revised by the Final Rule, section 29.2(v) of the pro 
forma OATT will require the following information to be provided with 
the request and posted on OASIS when designating an off-system 
resource: (1) Identification of the resource as an off-system resource; 
(2) amount of power to which the customer has rights; (3) 
identification of the control area(s) from which the power will 
originate; (4) delivery point(s) to the transmission provider's 
transmission system; and (5) transmission arrangements on the external 
transmission system(s). Additionally, section 29.2(v) is revised to 
require that the following information be provided with such 
designation, but such information must be masked on OASIS to prevent 
the release of commercially sensitive information including (1) any 
operating restrictions (periods of restricted operation, maintenance 
schedules, minimum loading level of resource, normal operating level of 
resource); and, (2) approximate variable generating cost ($/MWH) for 
redispatch computations. Requests to designate off-system network 
resources submitted on or after the effective date of this Final Rule 
must include all of the information listed above.
    1477. We direct transmission providers to develop OASIS 
functionality to (1) allow all of the information required for a 
request to designate network resources to be provided electronically, 
(2) mask information about operating restrictions and generating cost 
on OASIS, and (3) allow for queries of all information provided with 
designation requests in accordance with section 37.6 of the 
Commission's regulations.\871\ As provided in paragraph 385, we also 
direct transmission providers to work in conjunction with NAESB to 
develop business practice standards describing procedural requirements 
for submitting designations over any new OASIS functionality. 
Transmission providers need not implement this new OASIS functionality 
and any related business practices until NAESB develops appropriate 
standards. Prior to implementation of this new OASIS functionality, any 
information that cannot be provided electronically may be submitted by 
transmitting the information to the transmission provider by telefax or 
providing the information by telephone over the transmission provider's 
time recorded telephone line.
---------------------------------------------------------------------------

    \871\ 18 CFR 37.6.
---------------------------------------------------------------------------

    1478. Duke argues that there is an inconsistency between the 
following statements in P 408 of the NOPR: (1) ``when a network 
customer is designating a system purchase as a new network resource, 
the source information required in section 29.2(v) should identify that 
the resource is a system purchase and should identify the control area 
from which the power will originate''; and (2) the statement in the 
very next sentence that a ``power purchase agreement that is structured 
so that a network customer cannot specify all of the information 
required by section 29.2(v) cannot be designated as a network 
resource.'' We disagree. The first statement only provided guidance on 
what could be provided in lieu of the source of supply information (as 
required in the last bullet of section 29.2(v) of the existing pro 
forma OATT) and was not intended to excuse customers from providing all 
of the relevant information for an off-system purchase other than the 
specific source of supply. However, the revisions to section 29.2(v) we 
adopt in this Final Rule remove any confusion.
    1479. We disagree with Dynegy's argument that no firm LD contracts 
would be able to meet the requirements for designation. We note that 
all of the information required for off-system resources should be 
available for a seller's choice contract. Even firm LD contracts have 
variable generating costs (energy cost) and may have maintenance and 
other operating constraints. If no such constraints are contractually 
specified, or if no such constraints are relevant to an owned 
generation resource being designated, then that should be reflected in 
the information posted on OASIS.
    1480. We reject Dynegy's request that the Commission require 
additional verification by sellers that capacity was in fact sold to an 
entity designating that particular generator as a network resource and 
that the network resource designation is appropriate pursuant to the 
parties' agreement. As the Commission explained in Illinois Power,\872\ 
a firm energy purchase need not be backed by capacity to qualify as a 
designated network resource.
---------------------------------------------------------------------------

    \872\ 102 FERC ] 61,257 at P 14.
---------------------------------------------------------------------------

    1481. We disagree with commenters who argue that more specific 
information than the control area must be provided with each request to 
designate system purchases or seller's choice contracts as network 
resources. In particular, we disagree with EEI's and Duke's argument 
that customers designating seller's choice contracts as network 
resources must be required, on a generic basis, to identify the 
specific transmission system, rather than the more general control 
area, in which the physical resources are located. EEI argues that such 
specificity is required for transmission providers to identify the 
individual flowgates over which the power will flow into their system. 
The existing section 29.2(v) of the pro forma OATT requires that 
customers designating network resources identify

[[Page 12458]]

the ``delivery point(s) to the transmission provider's transmission 
system.'' We agree with Entergy and TDU Systems that providing both the 
control area in which off-system resources are located as well as the 
delivery point(s) to the transmission provider's transmission system is 
usually sufficiently specific to allow a transaction to be evaluated 
for its effect on the ATC of the local transmission system. However, we 
acknowledge Duke's concern about receiving requests to designate as 
network resources purchase agreements that list the point of delivery 
as only vague statements such as ``the PJM control area'' or ``into 
Southern.'' If any transmission provider believes that it faces unique 
circumstances that require deviations from the pro forma OATT in order 
to allow them to determine the effects of designations of network 
resources on ATC, it can, in a filing pursuant to FPA section 205, 
propose terms and conditions that it demonstrates are consistent with 
or superior to the pro forma OATT.
    1482. Because some regions of the country determine ATC using a 
flow-based methodology and other regions use a rated path methodology, 
EEI argues that section 29.2(v) should be modified to permit 
transmission providers to require a network customer to designate the 
point to which the energy is delivered and from which the transmission 
provider will provide network service if it is not delivered at the 
generator bus. It is unclear what specific changes EEI is requesting. 
We note that, with respect to off-system purchases, section 29.2(v) of 
the pro forma OATT already requires that the delivery point(s) to the 
transmission provider's transmission system be included in the 
description of the network resource.
    1483. In response to Entergy's request, we clarify that a customer 
may not designate as a network resource a seller's choice power 
purchase agreement which is sourced by generating units internal to the 
transmission provider's control area, since evaluating the effect on 
ATC would be problematic. We disagree with Entergy that a customer 
should be able to designate such a resource, even without specifying 
the location of the specific generating units, provided that the 
customer's network service from those units is contingent upon 
confirming resource deliverability prior to actually scheduling the 
service, because such a policy would still significantly obscure the 
evaluation of ATC. If a customer wishes to have a choice of resources 
that are internal to the particular transmission provider's control 
area from which to dispatch power, it must designate each of the 
resources as network resources.
    1484. We disagree with Morgan Stanley's unsupported comments that 
the source of supply in a contract is irrelevant. We find that location 
of resources is a critical factor to the transmission provider's ATC 
calculations and its ability to model and evaluate the proposed network 
resource, regardless of whether the transmission providers use security 
constrained economic dispatch.
(3) Ability To Serve Native Load
Comments
    1485. Many parties contend that the Commission's policy with regard 
to the qualification of network resources affects their ability to 
serve native load. EEI argues that energy purchases are an integral 
part of the resources many utilities use to serve their loads, yet 
often such projected energy purchases are not under contract until 
shortly before the power is needed. According to EEI, the requirement 
that a purchase contract be executed to qualify as a network resource 
jeopardizes the ability of such utilities to serve their native loads 
because they will not be able to reserve transmission capacity and 
other users may receive all of the ATC before their contracts are 
executed.
    1486. APPA, EEI and Nevada Companies argue that restrictions on the 
types of generation and power supply arrangements that qualify for 
network service may violate section 217 of the FPA. EEI notes that 
section 217 provides that LSEs are entitled to use firm transmission 
rights to deliver the output of their generators or purchased energy to 
meet their service obligations to their loads. In EEI's view, section 
217 requires the Commission to exercise its authority in a manner that 
enables LSEs to secure firm transmission rights on a long term basis 
for long term power supply arrangements made, or `planned,' to meet 
such needs and, therefore, a requirement that network customers and 
transmission providers not reserve transmission capacity to serve their 
network loads and native loads unless they either own generation or 
have executed contracts that specify the source of the energy is 
inconsistent with section 217. APPA notes that section 217 does not 
distinguish among the types of power supply arrangements that an LSE 
must enter into to be protected and that section 217(b)(1)(A) refers to 
a broad universe of owned or contracted generation that would suffice, 
so long as the power supplies are for the purpose of meeting a service 
obligation.
    1487. Newmont Mining disagrees that the Commission's requirements 
for designation of network resources are contrary to the new FPA 
section 217(b)(2). Newmont Mining argues the legislative history of 
section 217(b)(2) shows that it was intended essentially to codify 
Order No. 888 \873\ and that the resource designation requirements do 
not deny LSEs any right to use their transmission, but rather prescribe 
how they are to implement that right.
---------------------------------------------------------------------------

    \873\ In its reply comments, Newmont Mining cites (through 
reference to its own NOI reply comments) the statement in H.R. Rep 
No. 108-65 at 171 (2003) that ``[t]his section is intended to be 
consistent with the Commission's Order No. 888,'' as well as the 
statement in S. Rep. No. 109-78 at 50 (2005) that section 217 ``does 
not affect the Commission's authority under sections 205 and 206 [of 
the FPA] to ensure that rates are just and reasonable and not unduly 
discriminatory or preferential.''
---------------------------------------------------------------------------

    1488. EEI, Nevada Companies, PNM-TNMP and South Carolina E&G on 
reply also argue that the Commission's requirements for eligibility for 
designation as a network resource may impermissibly conflict with 
state-mandated procurement plans. EEI and South Carolina E&G contend 
that, by imposing restrictions on the ability of LSEs to serve their 
native load, the Commission is indirectly asserting jurisdiction over 
state-regulated procurement practices, which they further argue is 
prohibited under Northern States Power Co. v. FERC.\874\
---------------------------------------------------------------------------

    \874\ 176 F.3d 1090, 1096 (8th Cir. 1999), cert. denied, 528 
U.S. 1182 (2000).
---------------------------------------------------------------------------

    1489. Nevada Companies argue that the type of contracts that the 
Commission has determined to be eligible for qualification as network 
resources tend to be the most expensive. They point out that state 
regulatory agencies might determine that other types of contracts are 
more cost-effective without unnecessarily jeopardizing reliability. 
Even more troubling, they argue, is the problem created when 
transmission providers have peak loads that can more effectively be 
served by purchasing power on a short-term period (i.e., less than one 
year). To reserve the transmission required to serve a needle peak that 
can occur anytime within a four month period would require the purchase 
of thousands of megawatt hours of power that Nevada Power knows it will 
not need, resulting in a disallowance by the Public Utility Commission 
of Nevada, which approves all open positions, options and hedges for 
Nevada Power.
    1490. Nevada Companies contend that the network designation process 
should not be changed on systems where the process works reasonably 
well,

[[Page 12459]]

particularly on systems where transmission providers are required to 
make significant purchases of power to meet their retail loads. Nevada 
Companies argue that the Commission should therefore give transmission 
providers the option of instituting a reservation-based contract demand 
service similar to that previously approved in Florida Power.\875\
---------------------------------------------------------------------------

    \875\ Florida Power Corp, 81 FERC ] 61,247 (1997) (Florida 
Power).
---------------------------------------------------------------------------

    1491. Newmont Mining replies that Nevada Companies proposal is not 
similar to the Florida Power proposal or other approved contract demand 
network service arrangements, as those services were offered at the 
request of a network customer; designed to deal with a particular 
circumstance of the network customer; and offered as an option to, not 
as a replacement for, standard network integration services. Utah 
Municipals in their reply comments agree that utilities should not be 
permitted to unilaterally impose a contract demand ``reservation 
based'' methodology on its network customers.
    1492. Newmont Mining argues that Nevada Companies' request to 
maintain an open position for a portion of their resource portfolio, in 
accordance with their required resource planning process, does have 
some basis, but that Nevada Companies' proposal is not the right 
solution. If the Commission is inclined to provide some relief to 
Nevada Companies, Newmont Mining argues that such relief should come, 
if at all, only after an investigation of how similar problems are 
handled on other systems and that such relief should be limited. The 
limitations Newmont Mining suggests include, among other things, 
excusing Nevada Companies from the requirement, if at all, only to the 
extent that a specific open portfolio position is contained in a 
resource plan approved in accordance with applicable law; requiring 
that the reservation be posted on OASIS; not granting a reservation to 
Nevada Companies over a competing application for network service by a 
potential network customer that actually has a designated network 
resource; and permitting other network customers to hold similar open 
positions.
Commission Determination
    1493. We generally disagree with arguments that the Commission's 
restrictions on the designation of network resources may violate 
section 217 of the FPA. Congress did not require that LSEs be able to 
take transmission service without limitations of any kind in order to 
serve their native load, and nothing in section 217 suggests that LSEs 
should not be required to comply with reasonable requirements that are 
necessary to prevent undue discrimination and maintain a reliable 
transmission system. The conditions that have been established for 
taking network transmission service are reasonable and support these 
goals, and we therefore disagree that such conditions are inconsistent 
with the requirements of section 217. Furthermore, as Newmont Mining 
points out, the legislative history of section 217(b)(2) supports the 
interpretation that section 217 was intended to be consistent with the 
Commission's authority under sections 205 and 206 of the FPA to ensure 
that rates are just and reasonable and not unduly discriminatory or 
preferential, under which the designation requirements in Order No. 888 
were adopted.
    1494. We also disagree with commenter arguments that the 
Commission's requirements for eligibility for designation as a network 
resource impermissibly conflicts with state-mandated procurement plans. 
We point out that, with the exception of some clarifications on the 
types of LD provisions that are acceptable in designated firm LD 
products and what information a customer designating a system purchase 
or a seller's choice contract must provide, the requirements for 
designation of network resources are not new. Order No. 888 has long 
required that contracts be executed and imposed reasonable restrictions 
on the types of resources that may be designated as network resources.
    1495. To the extent that individual transmission providers have 
unique circumstances or needs that justify a variation from the pro 
forma OATT, those parties can request such a variation and explain why 
their proposed variation is consistent with or superior to the 
requirements of the pro forma OATT in a section 205 filing. In 
particular, Nevada Companies' request for approval of a contract demand 
service in order to address certain issues presented by their unique 
situation would properly be made in the context of a section 205 filing 
requesting a deviation from the pro forma OATT. We agree with Newmont 
Mining and Utah Municipals that approved variations, if any, must be 
applied on a comparable basis to both the transmission provider's 
merchant function and the other network customers.
(4) General
Comments
    1496. A number of commenters raised other general concerns 
regarding the designation of network resources. TAPS requests that the 
Commission clarify that conditional firm transmission service is 
sufficiently firm to meet the requirement that third-party transmission 
arrangements to deliver a designated purchase to the network be 
noninterruptible. TAPS also requests that the Commission provide for 
designation of network resources within the control area on a 
conditional firm basis.
    1497. In its reply comments, South Carolina E&G request 
clarification of the content and process of making information postings 
in accordance with section 29.2 of the pro forma OATT. South Carolina 
E&G argues that, taken literally, section 29.2 requires that everything 
in an application for network service be posted. South Carolina E&G 
contends, however, that the contents of an application do not fit on 
OASIS as currently configured, and that making such information 
available on OASIS is not necessary for the Commission's purposes, 
particularly given the Commission's representations in favor of 
preserving the integrity of customer confidential information. South 
Carolina E&G suggests the Commission require only the following 
information to be posted on OASIS: identification of the service type 
as ``network''; identification of the source by name of the generator 
or system; identification of the sink by name of the network customer's 
load; identification of the point of receipt by specification of the 
interface at which the network customer intends to deliver to the 
resource into the transmission provider's transmission area; and 
identification of the point of delivery and sink.
    1498. South Carolina E&G also requests clarification on how 
designated network resources are to be posted. South Carolina E&G asks, 
for instance, whether the Commission expects transmission providers to 
develop an OASIS template that network customers can update, as 
necessary, for network resources to simply be posted in PDF format, or 
be accomplished via the comment section of an OASIS reservation. South 
Carolina E&G argues that posting via the comment section of OASIS 
allows for operational ease, but provides limited transparency and 
includes administrative challenges due to character limitations and 
formatting constraints. Alternatively, South Carolina E&G argues, new 
functionality on OASIS that allows customers to post,

[[Page 12460]]

modify and update network resources would satisfy the Commission's 
requirements, but would involve added costs and time.
    1499. TranServ seeks clarification as to the minimum term, if any, 
that the transmission provider must honor for designation of new 
network resources. TranServ requests that network resources be allowed 
to be designated for the same minimum time periods used for firm point-
to-point service, i.e., daily or hourly service. Conversely, South 
Carolina E&G argues in its reply comments that requiring transmission 
providers to update their list of designated network resources on an 
hourly basis is too burdensome. South Carolina E&G requests that the 
Commission allow alternative methods of designating network resources 
on a short-term basis, such as adding comments to the appropriate 
comment field on either eTags or OASIS reservations.
    1500. TDU Systems argue that the designation of network resources 
(explicit or implicit) by some transmission providers is automatic, 
while network customers are required to pay for elaborate studies of 
every conceivable path affected by the addition of the resource. TDU 
Systems request that the Commission clarify that the process of network 
resource designation should be the same for all network users.
    1501. APPA, Fayetteville, NCPA, Northwest Parties, TAPS, and 
Wolverine request that clarifications made to the Commission's policy 
for qualification as a network resource apply prospectively and/or that 
sufficient time be allowed after the adoption of the Final Rule such 
that the necessary products, information systems and business practices 
can be developed. Such commenters contend that the designated network 
resources they currently rely upon were acquired and designated 
consistent with prior Commission precedent, so that changes to the 
network resource criteria established in this proceeding should not 
invalidate the continued use of such resources. Because there may be 
many existing designated network resources that do not meet the 
standards that the Commission eventually sets, Duke suggests on reply 
that the Commission may need to permit existing contractual designated 
network resources that do not qualify under the new standard to retain 
their designated status until the earlier of the expiration data of the 
transaction or the expiration date of any necessary transmission 
service supporting that network resource.
    1502. In its reply comments, Dynegy disagrees with request to 
grandfather existing designated network resources, and argues that the 
Commission's holding in Dynegy was erroneous and should be remedied in 
its entirety, without the creation of yet another class of 
grandfathered entities.
Commission Determination
    1503. The Commission agrees with TAPS that firm point-to-point 
transmission service provided on a conditional firm basis is 
sufficiently firm to be used for transmission to import a designated 
network resource. Firm point-to-point transmission service provided on 
a conditional firm basis meets the existing requirement that 
transmission arrangements in other control areas delivering power 
purchases designated as network resources to the network customer's 
transmission provider must not be interruptible for economic reasons, 
as explained further in section III.F of this Final Rule. With respect 
to TAPS' second request for clarification to allow for designation of 
network resources within the control area on a conditional-firm basis, 
we note that such designation of network resources within the control 
area will not be allowed, as discussed further in section III.F.
    1504. In response to South Carolina E&G's request, we reiterate 
that not all of the information required by section 29.2 of the pro 
forma OATT for designation of a network resource will be made publicly 
available on OASIS. As discussed above, information about operating 
restrictions and generating cost will be masked to protect commercially 
sensitive information. South Carolina E&G has also requested 
clarification of the Commission's intent with respect to how designated 
network resource information is posted. Our existing regulations 
specify the view, download, and query requirements for information 
posted regarding network resource designations.\876\ The details of how 
those informational postings are accomplished are best left to be 
determined as part of the NAESB standards development process.
---------------------------------------------------------------------------

    \876\ See 18 CFR 37.6(a).
---------------------------------------------------------------------------

    1505. TranServ requests that the Commission clarify the minimum 
term, if any, that a transmission provider must honor for designations 
of new network resources. We agree with TranServ that the minimum term 
should be the same as the minimum time period used for firm point-to-
point service (i.e., daily), unless otherwise demonstrated by the 
transmission provider and approved by the Commission.\877\
---------------------------------------------------------------------------

    \877\ See, e.g., Entergy Services, Inc., 105 FERC ] 61,318 
(2003), reh'g denied in relevant part, 109 FERC ] 61,216 (2004).
---------------------------------------------------------------------------

    1506. In response to TDU Systems' request for clarification that 
the process of network resource designation should be the same for all 
users, we note that section 28.2 of the pro forma OATT already provides 
that ``[t]he Transmission Provider, on behalf of its Native Load 
Customers, shall be required to designate resources and loads in the 
same manner as any Network Customer under Part III of this Tariff.'' We 
encourage parties to utilize the Commission's Enforcement Hotline to 
report suspected abused of this process.
b. Documentation for Network Resources
NOPR Proposal
    1507. In the NOPR, the Commission noted that transmission providers 
are responsible for verifying that the network customer has provided 
all the information required in section 29.2, but that transmission 
providers are not responsible for verifying that the generating units 
and power purchase agreements network customers designate as network 
resources satisfy the requirements in sections 30.1 and 30.7 of the pro 
forma OATT. However, the Commission also explained that the 
transmission provider continues to have the responsibility to verify 
that third-party transmission arrangements to deliver the purchase to 
the transmission provider's system are firm.
    1508. The Commission proposed to require the transmission 
provider's merchant function as well as network customers to include a 
statement with each application for network service or to designate a 
new network resource that attests that, for each network resource 
identified in the application for service, (1) the transmission 
customer owns or has committed to purchase the designated network 
resource, and (2) the designated network resource comports with the 
requirements for designated network resources.
    1509. If the network customer does not include an attestation when 
it confirms its request, the Commission proposed that the transmission 
provider will notify the network customer within 15 days of 
confirmation that its request is deficient and that, wherever possible, 
the transmission provider will attempt to remedy deficiencies in the 
request through informal communications with the network customer. If 
such efforts are unsuccessful, the Commission further

[[Page 12461]]

proposed that the status of the request on OASIS will be changed to 
``retracted'' and the network customer's request will be terminated 
without prejudice to the network customer submitting a new request that 
includes the required attestation, after which the network customer 
will be assigned a new priority consistent with the date of the new 
request.
    1510. In the event that the transmission provider or any network 
customer designates a network resource that it does not own or has not 
committed to purchase, or that does not otherwise comport with the 
requirements for designated network resources, the Commission proposed 
that it will deem the network customer to be in violation of the pro 
forma OATT and will consider assessing civil penalties on a case-by-
case basis consistent with the Commission's Policy Statement on 
Enforcement. The Commission encouraged the transmission provider and 
other market participants to use the Commission's Enforcement Hotline 
to report instances when they believe a network customer has designated 
as a network resource a resource that does not meet the criteria for 
network resources.
Comments
    1511. Several commenters support the overall proposed changes 
involving attestation requirements, claiming the proposal should help 
to eliminate abuse, including the practice of some utilities denying 
transmission requests in order to accommodate its merchant function's 
plans to engage in future short-term purchases to serve native 
load.\878\ Entegra explicitly supports the Commission's proposal to 
treat failures to comply as violations of the pro forma OATT subject to 
enforcement. Pinnacle notes that customers should make such 
attestations in good faith, such that an inadvertent error or omission 
would not automatically result in recourse to a legal remedy if it can 
be corrected without adverse impacts.
---------------------------------------------------------------------------

    \878\ E.g., Ameren, Entegra, Pinnacle, Public Power Council, and 
Southern.
---------------------------------------------------------------------------

    1512. Dynegy argues in its reply comments that transmission 
customers who knowingly provide false or inaccurate information in 
their network resource designations not only jeopardize reliability, 
but are essentially engaging in theft. Dynegy argues that such parties 
should be subject to the sanctions and penalties under the Market 
Behavior Rule,\879\ including revocation of the violator's market-based 
rate authority. APPA and TAPS argue that the new attestation 
requirements should be consistently applied to all network customers, 
including the transmission provider's merchant function and affiliates.
---------------------------------------------------------------------------

    \879\ See Investigation of Terms and Conditions of Public 
Utility Market-Based Rate Authorizations, 105 FERC ] 61,218 (2003).
---------------------------------------------------------------------------

    1513. Several commenters support the Commission's determination 
that transmission providers are not required to independently verify 
the accuracy of an application for network service.\880\ Some 
commenters request that the Commission clarify that transmission 
providers or transmission owners can voluntarily seek information which 
verifies that contractual terms meet the requirements in section 30.1 
and 30.7 of the pro forma OATT.\881\ In its reply comments, Duke argues 
that, without the ability to request the contracts supporting the 
compliance with the requirement that the designated network resources 
are firm enough, the Commission may not have authority to require that 
the network customer support its designation in situations where the 
network customer is nonjurisdictional.
---------------------------------------------------------------------------

    \880\ E.g., Ameren, EEI, Suez Energy NA, Nevada Companies, and 
Utah Municipals.
    \881\ E.g., Ameren, Duke Reply, Entergy, and Pinnacle.
---------------------------------------------------------------------------

    1514. Pinnacle disagrees with the NOPR proposal that transmission 
providers should continue to be responsible for verifying the firmness 
of the network customers' transmission arrangements on other systems. 
Instead, Pinnacle contends that the transmission customer should have 
the obligation to ensure that their transmission arrangements meet the 
requirements needed to ensure that their resources qualify as 
designated network resources. In its reply comments, Detroit Edison 
also requests that the Commission require proof that network customers 
have obtained the requisite transmission service on external systems.
    1515. Dynegy, in its reply comments, requests that network resource 
information and validity of designation be verified not only by the 
designating customer, but also by the seller or owner of the 
generation, in order to help ensure that all network resources are in 
fact backed by capacity. Entegra similarly suggests that the Commission 
require that entities designating network resources make periodic OASIS 
postings that will permit verification that the entity designating a 
generating facility as a network resource actually has rights to power 
from that facility.
    1516. EEI and Entergy allege that the Commission's NOPR attestation 
proposal may have unintended consequences. Some commenters contend that 
the gap between the Commission's interpretation of the qualifications 
of network resources and current procurement practices creates a 
significant possibility that, if the Commission enforces its policies, 
it could cause substantial disruptions of service to network and native 
loads, reduce supply options, or expose network customers and 
transmission providers to increased liability.\882\ EEI asserts that 
this is because a significant number of network customers and 
transmission providers are serving their network loads and native loads 
using resources, particularly power purchase contracts, that may not 
meet the Commission's requirement for designation as network resources. 
Some commenters request that the Commission engage in a comprehensive 
review of power purchase practices before implementing its proposed 
attestation requirement, and apply any change in policies only to power 
purchases entered into after the effective date of the Final Rule and 
after the industry has had time to develop new products that meet the 
Commission's requirements.\883\
---------------------------------------------------------------------------

    \882\ E.g., EEI, TDU Systems, Indianapolis Power Reply, and 
South Carolina E&G Reply.
    \883\ E.g., EEI and Indianapolis Power Reply.
---------------------------------------------------------------------------

    1517. Entegra replies that the expressed concern about the 
attestation requirement by EEI is puzzling and troubling, because the 
NOPR did not propose to change the current requirements of the pro 
forma OATT regarding the qualification of network resources. Entegra 
argues that the widespread non-compliance alleged by EEI makes adoption 
of an attestation requirement more important and that EEI's allegations 
may, at most, suggest that the Commission consider some sort of amnesty 
for network customers and transmission providers willing to self-report 
and commit to full compliance with the network resource rules going 
forward.
    1518. To ensure that network customers can submit requests for new 
network service without a final, executed contract, Entergy requests 
that an attestation to designate a new network resource should not be 
required until the service request is confirmed. If the request is pre-
confirmed, Entergy suggests that the attestation should be provided at 
the time the request is submitted.
    1519. SPP requests that the Commission not require it to police the 
additional restrictions on the designation of network resources 
proposed in the NOPR. SPP states that it has neither the data nor the 
personnel

[[Page 12462]]

necessary to perform this function and that the Commission should rely 
on network customer verification, subject to Commission audits. 
TranServ suggests that the exact nature of how the customer would make 
the newly required attestation, as well as the treatment of OASIS 
requests failing to provide the required attestation, should be 
determined in the NAESB forum at the time when the technical 
requirements for processing network service requests on OASIS are 
established.
    1520. Several commenters request that the Commission amend section 
30.2 of the pro forma OATT to require network customers that designate 
network resources in an external control area also provide a 
certification from that control area's administrator that the resource 
being designated is not counted as a designated resource for another 
load on or off of the system.\884\ TDU Systems disagree, arguing on 
reply that the Commission should not require these types of 
certifications. TDU Systems recommend, in the alternative, that LSEs on 
multiple systems should not have to undesignate network resources to 
serve off-system load, which would eliminate the need for such control 
area certification for such transactions. TDU Systems also argues that, 
in the absence of any evidence of abuse, the Commission should not 
further complicate a process that most market participants would agree 
is already overly complicated and burdensome.
---------------------------------------------------------------------------

    \884\ E.g., MISO, Indianapolis Power Reply, and Detroit Edison 
Reply.
---------------------------------------------------------------------------

Commission Determination
    1521. The Commission adopts the NOPR proposal that transmission 
providers continue to be responsible for verifying that third-party 
transmission arrangements to deliver the purchase to the transmission 
provider's system are firm, but that transmission providers are not 
responsible for verifying that the generating units and power purchase 
agreements network customers designate as network resources satisfy the 
requirements in sections 30.1 and 30.7 of the pro forma OATT. We also 
adopt the proposal to require both the transmission provider's merchant 
function and network customers to include a statement with each 
application for network service or to designate a new network resource 
that attests, for each network resource identified, that (1) the 
transmission customer owns or has committed to purchase the designated 
network resource and (2) the designated network resource comports with 
the requirements for designated network resources. The network customer 
should include this attestation in the customer's comment section of 
the request when it confirms the request on OASIS.
    1522. If the network customer does not include the attestation when 
it confirms the request, the transmission provider must notify the 
network customer within 15 days of confirmation that its request is 
deficient, in accordance with the procedures in section 29.2 of the pro 
forma OATT. Whenever possible, the transmission provider shall attempt 
to remedy deficiencies in the request through informal communications 
with the network customer. If such efforts are unsuccessful, the 
transmission provider shall terminate the network customer's request 
and change the status of the request on OASIS to ``retracted.'' This 
termination shall be without prejudice to the network customer 
submitting a new request that includes the required attestation. The 
network customer shall be assigned a new priority consistent with the 
date of the new request.
    1523. In the event that the transmission provider or any other 
network customer designates a network resource that it does not own or 
has not committed to purchase or that does not comport with the 
requirements for designated network resources, we will deem the network 
customer to be in violation of the pro forma OATT and will consider 
assessing civil penalties on a case-by-case basis, consistent with the 
Commission's Policy Statement on Enforcement.\885\ We encourage the 
transmission provider and other market participants to use the 
Commission's Enforcement Hotline to report instances where they believe 
a network resource has been designated that does not meet the 
Commission's requirements.
---------------------------------------------------------------------------

    \885\ See supra note 75.
---------------------------------------------------------------------------

    1524. In response to Pinnacle's request that an inadvertent error 
or omission should not automatically result in a penalty if it can be 
corrected without adverse impacts, we reiterate the policy established 
in the Commission's Policy Statement on Enforcement that enforcement 
actions will not be imposed ``automatically.'' Enforcement actions are 
instead considered on a case-by-case basis after consideration of a 
number of factors which may result in penalties being reduced or 
eliminated.\886\ Among the many factors to be considered pursuant to 
the Policy Statement on Enforcement is whether the violation is 
willful.\887\ At the same time, consideration is provided for other 
factors that may weigh for assessing civil penalties, even in 
circumstances of inadvertent violations. For instance, the Commission 
considers whether the violator has a history of violations and whether 
the actions were recklessly or deliberately indifferent to the 
results.\888\ While enforcement actions will not be automatic, and the 
inadvertence of a violation would be a consideration when determining 
what, if any, penalty to impose, there may be some instances where 
inadvertent violations would be found, after consideration as 
established in the Policy Statement on Enforcement, to warrant a 
penalty.
---------------------------------------------------------------------------

    \886\ Policy Statement on Enforcement at P 13.
    \887\ Id. at P 20.
    \888\ Id.
---------------------------------------------------------------------------

    1525. Dynegy also requests that transmission customers who 
knowingly provide false or inaccurate information in their network 
resource designations be subject to the sanctions and penalties under 
the Market Behavior Rules,\889\ including revocation of the violator's 
market-based rate authority. We reiterate that violations will be dealt 
with on a case-by-case basis in accordance with the Policy Statement on 
Enforcement.
---------------------------------------------------------------------------

    \889\ Investigation of Terms and Conditions of Public Utility 
Market-Based Rate Authorizations, 105 FERC ] 61,218 (2003).
---------------------------------------------------------------------------

    1526. We reject requests to allow the transmission provider to 
voluntarily seek information which verifies that contractual terms meet 
the requirements in sections 30.1 and 30.7 of the pro forma OATT. 
Allowing transmission providers to verify terms and conditions of power 
purchase agreements would put transmission providers in the position of 
interpreting contracts and accepting or rejecting designations based on 
their interpretations. We believe such authority is unnecessary in 
light of the new attestation requirements and that instances of non-
compliance are better handled by the Commission's enforcement staff in 
the context of audits and Enforcement Hotline reports. This applies 
equally to jurisdictional and nonjurisdictional customers. Every 
transmission customer must satisfy the requirements of the transmission 
provider's OATT in order to take service. The Commission thus has 
authority to require that all network customers support their 
designations.
    1527. We disagree with Pinnacle's argument that transmission 
providers should not be responsible for verifying the firmness of the 
network customer's transmission arrangements on other systems. We find 
that having

[[Page 12463]]

transmission providers verify firmness of such transmission 
arrangements provides a significant benefit to the system and is not 
unduly burdensome. The confirmation or lack thereof of service on the 
third-party's system should be readily available on OASIS. If firm 
third-party service is not confirmed in OASIS, the transmission 
provider should attempt to remedy any information deficiency in the 
request through informal communications with the network customer. If 
such efforts are unsuccessful, the transmission provider should find 
the request to designate the network resource deficient. Because this 
information is available on OASIS, we disagree with Detroit Edison's 
request that the Commission require proof that customers have obtained 
requisite transmission service on external systems.
    1528. We also disagree with SPP's argument that it should not be 
required to police the additional restrictions on the designation of 
network resources, since it has neither the data nor the personnel 
necessary to perform this function. The only ``additional'' 
restrictions that the transmission provider is called upon to police is 
that network customers submit the appropriate attestations when 
requesting designation of a network resource, which places a 
particularly small burden on the transmission provider. We also do not 
expect the requirement that transmission providers verify the firmness 
of the network customer's transmission arrangements on other 
transmission systems to require any additional data or personnel.
    1529. We reject Dynegy's request that the validity of network 
resource designations be verified not only by the designating customer, 
but also by the seller or owner of the generation, in order to help 
ensure that all network resources are in fact backed by capacity. 
Similarly, we deny Entegra's request that the customer be required to 
make additional, periodic OASIS postings to demonstrate that it has 
rights to the power from a designated resource. We find that such 
additional verifications are unnecessary in light of the new 
attestation requirements.
    1530. With regard to arguments that requiring an attestation may 
disrupt service, the alleged confusion over the Commission's 
requirements for designation of network resources seems primarily 
concerned with whether the EEI Firm LD Product and similar products 
were eligible to be designated as network resources and whether certain 
resources can be designated both to serve native load and other network 
customers. As we have addressed both of these questions above, we 
believe that many of the concerns about the attestation requirement are 
resolved. Commenters have not supported claims that the attestation 
requirement will be either burdensome or that the requirement will 
require substantial time to comply. As noted above, the minimal 
additional network resource designation requirements impose in this 
Final Rule beyond the existing requirements are not expected to be 
unduly burdensome. While exceptions may be appropriate in cases of 
legitimate emergencies, we disagree with the implication that a 
customer should be granted general flexibility to designate a network 
resource that otherwise may not be eligible.
    1531. In response to Entergy's request, we agree that attestations 
will not be required to be submitted until the service request is 
confirmed. However, if the request is pre-confirmed, we agree that the 
attestation must be provided at the time the request is submitted.
    1532. In response to TranServ's request that the exact nature of 
how the customer would make an attestation should be determined in the 
NAESB forum, we note that the contents and the specific information 
that is required to be provided with the attestation are specified in 
the pro forma OATT, and we are requiring that the attestation be 
submitted through OASIS with each request to designate a new network 
resource. The appropriate subject for transmission providers to 
coordinate with NAESB to resolve is limited to the appropriate 
formatting of such information to be provided in OASIS. In response to 
TranServ's request that NAESB should also determine the treatment of 
OASIS requests where the customer fails to provide the necessary 
attestation, we point out that we have already directed that such 
requests are to be found deficient by the transmission provider and 
treated in accordance with the procedures in section 29.2 of the pro 
forma OATT.
    1533. We reject requests to require network customers designating 
network resources in an external control area to provide certification 
from that control area's administrator that the resource being 
designated is not counted as a designated resource for another load on 
or off the system. We find that, in absence of any evidence that the 
Commission's new attestation requirements will be insufficient, this 
requested verification appears unnecessary.
c. Undesignation of Network Resources
    1534. Section 28.2 of the pro forma OATT requires the transmission 
provider, on behalf of its native load customers, to designate 
resources and loads in the same manner as any network customer under 
Part III of the pro forma OATT (Network Integration Transmission 
Service). The information provided by the transmission provider must be 
consistent with the information it uses to calculate ATC. Section 30.3 
of the pro forma OATT previously allowed the network customer to 
terminate the designation of all or part of a generating resource as a 
network resource at any time, but stated that the network customer 
should provide notification to the transmission provider as soon as 
reasonably practicable.
    1535. In Order No. 888-B, the Commission clarified that the pro 
forma OATT allows network customers to designate network resources over 
shorter time periods. The Commission indicated that a network customer 
that seeks to engage in firm sales from its currently designated 
network resources may terminate the generating resource (or a portion 
of it) as a network resource pursuant to section 30.3 of the pro forma 
OATT and request that, as set forth in section 29 of the pro forma 
OATT, the same generation resource be designated as a network resource 
effective with the end of its power sale.\890\
---------------------------------------------------------------------------

    \890\ Order No. 888-B at 62,093.
---------------------------------------------------------------------------

NOPR Proposal
    1536. In the NOPR the Commission proposed to continue to allow 
network customers to ``undesignate'' \891\ a portion of their network 
resources on a short-term basis to make off-system sales. The 
Commission reiterated that a network customer may redesignate the 
resource by making a request to designate a new network resource. 
Additionally, the Commission reiterated that the transmission provider 
and all network customers must designate their network resources and 
are prohibited from making firm third-party sales from designated 
network resources. The Commission stated that, to the extent the 
transmission provider or a network customer wants to make a firm sale 
from a network resource, it must undesignate the resource pursuant to 
section 30.3 of the pro forma OATT. The network customer, including the 
transmission provider itself, could request to redesignate the resource 
by making a request to designate a new network resource pursuant to 
section 30.2 of the pro forma OATT.
---------------------------------------------------------------------------

    \891\ The general term ``undesignation'' refers to both 
temporary terminations and indefinite terminations of network 
resource status, as discussed below.

---------------------------------------------------------------------------

[[Page 12464]]

    1537. The Commission also sought comment on the amount of time 
prior to operation that the transmission provider and other network 
customers should be required to terminate a network resource to ensure 
that the appropriate set of network resources are included in the ATC 
calculation.
(1) Overview
Comments
    1538. Most commenters appear to support the Commission's proposal 
to continue to allow network customers to undesignate a portion of 
their network resources on a short-term basis to make off-system sales. 
However, many commenters request clarification that a temporary 
undesignation will not cause them to forfeit their rights to 
transmission priority or ATC for any other time period. Several 
commenters also request that formal undesignations not be required or 
that the process not be burdensome. A wide range of comments were 
received in response to the Commission's request for comments on the 
amount of time prior to operation that the transmission provider and 
other network customers should be required to terminate a network 
resource to ensure that the appropriate set of network resources are 
included in the ATC calculation.
Commission Determination
    1539. The Commission generally adopts the NOPR proposal to continue 
to require network customers and the transmission provider's merchant 
function to undesignate network resources or portions thereof in order 
to make certain firm, third-party sales from those resources. In 
particular, network customers and the transmission provider's merchant 
function may only enter into a third-party power sale from a designated 
network resource if the third-party power purchase agreement allows the 
seller to interrupt power sales to the third party in order to serve 
the designated network load. Such interruption must be permitted 
without penalty, to avoid imposing financial incentives that compete 
with the network resource's obligation to serve its network load.
    1540. We clarify that requests to undesignate network resources 
that are submitted concurrently with a request to redesignate those 
network resources at a specific point in time shall be considered 
temporary terminations. Conversely, requests to undesignate network 
resources submitted without any concurrent request to redesignate those 
network resources shall be considered a request for indefinite 
termination of those network resources.
    1541. We direct transmission providers to develop OASIS 
functionality and, working through NAESB, business practice standards 
describing the procedural requirements for submitting both temporary 
and indefinite terminations of network resources, to allow network 
customers to provide all required information for such terminations. 
Such OASIS functionality should allow for electronic submittal of the 
type of termination (temporary or indefinite), the effective date and 
time of the termination, and identification and capacity of resource(s) 
or portions thereof to be terminated. For temporary terminations, such 
OASIS functionality should also allow for electronic submittal of (1) 
effective date and time of redesignation, following the period of 
temporary termination; (2) information and attestation for 
redesignating the network resource following the temporary termination, 
in accordance with section 30.2 of the pro forma OATT; and (3) 
identification of any related transmission service requests to be 
evaluated concomitantly with the request for temporary termination. In 
response to TranServ's request, we clarify that the request for 
temporary termination of the resource and the requests for the related 
transmission service identified in item (3), if any, should be 
evaluated as a single request, and approved or disapproved as such. We 
specifically direct transmission providers, working through NAESB, to 
develop business standards describing the procedures for submitting and 
processing requests for concomitant evaluations of transmission 
requests and temporary terminations. When processing such requests, the 
evaluation of the transmission service requests identified in item (3) 
should take into account the undesignation of the network resources 
identified in the request for termination. However, the evaluation of 
the transmission service requests in item (3) should be processed 
taking proper account of all competing transmission service requests of 
higher priority.
    1542. Consistent with the requirements for requests for designation 
of new network resources, the new OASIS functionality should also allow 
for queries of requests to undesignate and redesignate network 
resources. In accordance with section 37.6 of the Commission's 
regulations,\892\ such requests must be able to be queried by the 
publicly available information posted on OASIS.
---------------------------------------------------------------------------

    \892\ 18 CFR 37.6.
---------------------------------------------------------------------------

    1543. Transmission providers need not implement this new OASIS 
functionality and any related business practices until NAESB develops 
appropriate standards. Prior to implementation of this new OASIS 
functionality, requests for temporary or indefinite terminations of 
network resources may be submitted by transmitting the required 
information to the transmission provider by telefax or providing the 
information by telephone over the transmission provider's time recorded 
telephone line.
(2) Risk to ATC Rights
Comments
    1544. Most commenters request clarification that a temporary 
undesignation of a network resource does not constitute a forfeiture of 
priority followed by a new request to designate the network resource, 
or otherwise put in jeopardy the ATC associated with the designation of 
that resource for any period other than the period of 
undesignation.\893\ Several commenters argue that virtually no network 
customers will ever make a firm third-party sale if they are forced to 
reapply for transmission service after a period of undesignation of 
their resource, since they would run the risk of losing the ATC 
associated with the resource.\894\ EEI and Entergy contend that the 
result of such a policy would be that the industry would no longer be 
able to take advantage of the diversity of peak loads to make firm 
sales and purchases, and an almost immediate shortage of firm energy 
sources to serve network and native loads. Duke argues that the 
approach of not compelling network customers to risk losing the ATC 
associated with their designated resources beyond the period that the 
resource is designated would be the comparable approach vis-[agrave]-
vis point-to-point customers seeking to temporarily redirect their 
service.
---------------------------------------------------------------------------

    \893\ E.g., Duke, EEI, Entergy, Exelon, MDEA Reply, Northwest 
Parties, Pinnacle, Progress Energy, South Carolina E&G Reply, 
Southern, TDU Systems Reply, TranServ, and WSPP Reply.
    \894\ E.g., Duke, EEI, Entergy, Progress Energy, South Carolina 
E&G Reply, and TranServ.
---------------------------------------------------------------------------

    1545. Southern argues that to treat a redesignation as an entirely 
new application for network resource designation would appear to depart 
from existing tariff requirements and unnecessarily limit the 
reliability of network customers' service. It also argues that such an 
approach would be in contravention with section 217(b)(4) of the FPA, 
which directs the


[[Continued on page 12465]]


From the Federal Register Online via GPO Access [wais.access.gpo.gov]
]                         
 
[[pp. 12465-12514]] Preventing Undue Discrimination and Preference in Transmission 
Service

[[Continued from page 12464]]

[[Page 12465]]

Commission to act in a manner that facilitates the planning and 
expansion of facilities to meet the reasonable needs of LSEs to satisfy 
the service obligations of the LSEs. Southern contends that the NOPR 
proposal would create administrative burdens on transmission providers, 
potentially treat network service as an inferior product to long term 
point-to-point transmission service, and introduce a substantial 
deterrent against optimization of network resources by network 
customers.
    1546. On the other hand, Great Northern initially requests that ATC 
not be set aside for a former network resource in anticipation that it 
might be designated as a network resource at some time in the future. 
In order to ensure comparable treatment for all transmission service 
customers, Great Northern argues, the Commission should place new 
requests to designate network resources at the end of the transmission 
queue, regardless of the prior designation of those resources. Great 
Northern clarifies on reply that, while ATC should not be set aside for 
former network resources in anticipation that it might be designated as 
a network resource at some unspecified time in the future, it has no 
objection to setting aside ATC to be used by a formerly designated 
network resource after a temporary, specified period of undesignation 
such as one month or one season.
    1547. NorthWestern, in its reply comments, disagrees with Great 
Northern's initial comments that new designations be placed at the end 
of transmission service queue regardless of the prior designation of 
those resources. NorthWestern argues that such a policy would unduly 
discriminate against the network customer who is paying for the use of 
the entire transmission system and grant an undue preference to the 
point-to-point customer. NorthWestern also argues that the proposal 
that ATC not be set aside for an undesignated network resource appears 
to conflict with the Commission's standard interconnection procedures 
for large and small generators. Once all upgrades specified through the 
interconnection process have been installed, NorthWestern contends that 
the generator can be specified as a network resource by any customer, 
at the time of commercial operation for the generator or at any time in 
the future.
    1548. TAPS appears to support a requirement that transmission 
customers get back in the queue when re-designating resources, so long 
as the rules apply to transmission providers as well as network 
customers.
Commission Determination
    1549. In response to the many requests and comments, we clarify 
that a request for termination of a network resource that is 
concurrently paired with a request to redesignate that resource at a 
specific point in time will not result in the network customer 
permanently forfeiting rights to use that resource as a designated 
network resource. Any change in ATC that is determined by the 
transmission provider to have resulted from the temporary termination 
shall be posted on OASIS during this temporary period. We agree that 
requiring network customers making temporary terminations to 
permanently forfeit rights to use this ATC would significantly reduce 
or eliminate firm third-party power sales. We emphasize, however, that 
a request to terminate a network resource that is not accompanied with 
a request to redesignate that resource at a specific point in time is 
to be considered an indefinite termination. After an indefinite 
termination of a resource, the network customer has no continuing 
rights to the use of such resource and future requests to designate 
that resource would be processed consistent with section 30.2 as a 
designation of new network resource.
    1550. We disagree with NorthWestern's argument that, once upgrades 
specified through the interconnection process have been installed, the 
generator can be specified as a network resource by any customer, at 
the time of commercial operation of the generator or at any time in the 
future. The Commission has long noted that the generator 
interconnection process is separate and independent of the acquisition 
of transmission service for the same generator.\895\ The fact that 
system upgrades may be required to interconnect a generator does not 
mean any network customer is entitled to the use of that generator at 
all times, even in the event that the network customer indefinitely 
terminates the designation of that resource. The integration of network 
resources with different network customers presents different effects 
and flows on the transmission system that must be evaluated by the 
transmission provider.
---------------------------------------------------------------------------

    \895\ See, e.g., Order No. 2003 at P 118, 744.
---------------------------------------------------------------------------

(3) Minimum Lead-Time
Comments
    1551. EEI and Entergy argue that the Commission should not require 
transmission providers or network customers to undesignate a network 
resource for a specific amount of time prior to the commencement of an 
off-system sale. In many instances, EEI argues, short-term firm power 
sales are made with relatively little lead time, particularly after 
events such as forced outages or unusual weather conditions. EEI and 
PNM-TNMP argue that requiring transmission providers or network 
customers to undesignate a specific amount of time prior to an off-
system sale would foreclose the possibility that firm sales could be 
made with short lead times. That, EEI argues, would adversely affect 
the sales market, without having any impact on ATC on the path used by 
the network resource because the network resource would not be 
undesignated. In EEI's view, imposing lead times on undesignations of 
network resources would also result in treating network and native load 
customers less favorably than point-to-point customers. EEI points out 
that the pro forma OATT does not impose any minimum lead times on firm 
redirects of point-to-point transmission service pursuant to section 22 
of the pro forma OATT or reassignment of transmission service pursuant 
to section 23 of the OATT, despite the fact that advance notice of 
redirects might make the resultant ATC more marketable.
    1552. Most commenters, however, appear to support the establishment 
of a minimum amount of time prior to operation that the transmission 
provider and other network customers should be required to terminate a 
network resource to ensure that the appropriate set of network 
resources are included in the ATC calculation, although they express 
widely varying opinions on what period of time would be appropriate.
    1553. Ameren and Pinnacle contend that the amount of time prior to 
operation that the transmission provider and other network customers 
should be required to terminate a network resource should be linked to 
the frequency of the calculation that gets standardized in the ATC 
process. Pinnacle contends that, if the undesignation and redesignation 
are performed on OASIS as they propose, ATC could be recalculated and 
posted immediately following the undesignation or redesignation. Ameren 
contends that it cannot comment further until the parameters of the ATC 
process are defined. FirstEnergy states that the amount of time should 
be consistent with the time periods required in markets, and that 
outside of markets, times should be established that coincide with such 
markets. Southern argues that the current practice, under which a 
resource is undesignated when

[[Page 12466]]

it schedules point-to-point transmission service for an off-system 
sale, provides adequate time to ensure that the appropriate set of 
network resources is included in the ATC calculation.
    1554. PJM notes that, under its system, a generator resource with 
excess capacity can undesignate the excess resource on a ``day ahead'' 
basis. PJM believes that this is the proper amount of time needed to 
ensure resource adequacy. PJM argues that a generator should not, under 
any circumstance, change the designation of its resource ``same day.''
    1555. TranServ argues that, at a minimum, a request for 
undesignation should be supplied no later than the firm scheduling 
deadline so that released capacity may be acquired on a non-firm basis. 
If that data were required to be submitted earlier than the scheduled 
deadline, TranServ suggests the transmission provider may be able to 
offer incremental capacity for firm sales. TranServ requests that the 
Commission establish in the pro forma OATT some nominal timeframe for 
network customers to provide to the transmission provider their planned 
use of designated resources to serve loads.
    1556. Nevada Companies requests that, due to some system 
emergencies, force majeure events, and hourly scheduling of tie-line 
changes, they be allowed to change undesignation of network resources 
at any time to handle these types of events.
Commission Determination
    1557. Commenters presented many alternative views in response to 
the Commission's request in the NOPR for comments on the appropriate 
minimum lead-time prior to operation that the transmission provider and 
other network customers should be required to terminate a network 
resource to ensure that the appropriate set of network resources are 
included in the ATC calculation. In consideration of these comments, 
the Commission finds that the appropriate requirement is that network 
customers not be permitted to make firm third-party sales from any 
designated network resource without (1) undesignating that resource for 
the period of the third-party sale pursuant to pro forma OATT section 
30.3 and (2) providing notice of such undesignation before the firm 
scheduling deadline (10 a.m. the day before service commences). We find 
that this requirement strikes the appropriate balance, allowing 
undesignated capacity to be acquired on a non-firm basis but not 
creating an undue adverse effect on third-party sales.
    1558. We find it unnecessary to incorporate into the pro forma OATT 
provisions relaxed rules for changing the undesignation of network 
resources at any time to handle system emergencies, force majeure 
events, forced outages or unusual weather conditions, as suggested by 
some commenters. Other procedures such as those in NERC's standard for 
Capacity & Energy Emergencies, EOP-002-2, or the possible use of 
capacity benefit margin, are more appropriate to deal with legitimate 
system emergencies. Outside the context of legitimate system 
emergencies, network customers should rely on appropriate planning and 
operation, rather than relaxed rules for designation of network 
resources.
    1559. We disagree with EEI's argument that requiring a minimum 
lead-time will result in treating network and native load customers 
less favorably than point-to-point customers. In particular, EEI is 
incorrect in its statement that the OATT does not impose any minimum 
lead times on firm redirects of point-to-point transmission service or 
reassignments of transmission service. Firm point-to-point customers 
are also subject to deadlines for scheduling redirects pursuant to 
section 22.2 of the pro forma OATT. Furthermore, we find that EEI has 
provided no compelling evidence to support its argument that the 
adverse impacts on the market for firm energy with short lead times 
justifies having no minimum lead time.
(4) General
Comments
    1560. Several commenters argue that the Commission should not 
require network customers or the transmission provider to make formal 
modifications to their designations of network resources when they make 
firm sales to third parties from those resources.\896\ EEI and Southern 
argue that the practice of most network customers and transmission 
providers in the ten years since the Commission issued Order No. 888 
has been that a network resource is undesignated for any period for 
which the customer requests firm point-to-point transmission service 
from the generator or a third party. This practice, EEI argues, has not 
resulted in any adverse impacts on reliability or on the availability 
of transmission service and that, to the contrary, selling energy from 
network resources on a firm basis instead of a non-firm basis frees up 
firm transmission capacity that otherwise would have to be reserved for 
the network customer. EEI and NRECA contend that requiring formal 
undesignations is substantially more cumbersome for network customers 
and transmission providers making off-system sales.
---------------------------------------------------------------------------

    \896\ E.g., EEI, NRECA Reply, PNM-TNMP, and Southern.
---------------------------------------------------------------------------

    1561. Progress Energy and TranServ argue that network customers 
should not have to go through the process of redesignating a network 
resource as new when the network customer once again needs to use this 
resource to serve network load. TranServ argues that such a transaction 
is exactly analogous to a redirect of firm point-to-point service on a 
firm basis and requests clarification of whether the provider should 
evaluate a request to undesignate a network resource concomitantly with 
the assessment of that same customer's point-to-point request, as is 
done with redirects on a firm basis.
    1562. NRECA states that the undesignation requirement is too 
burdensome and, therefore, the Commission should adopt a comparability 
requirement that would allow network customers to utilize the practice 
that many public utility transmission providers use today: i.e., use 
designated resources for firm off-system transactions or third party 
uses without having to go through the designation, undesignation and 
redesignation process. NRECA argues that existing scheduling procedures 
have allowed transmission providers to deliver power from their 
designated network resources for off-system merchant purposes reliably 
and should perform equally well for network customers, provided they 
still pay a point-to-point charge for the ``outbound'' leg of a 
delivery to a neighboring network to serve the customer's network load 
on the neighboring network. NRECA argues in its reply comments that, 
whatever the Commission decides to do, comparability is the most 
important principle when considering the undesignation policy and that 
``grandfathering'' agreements which would allow transmission providers 
to essentially get around this requirement would allow undue 
discrimination to continue. EEI disagrees in its reply comments with 
NRECA's assertion that transmission providers currently have an 
advantage over network customers, arguing that the same standards apply 
to the transmission provider's merchant function and network customers 
when they seek to make off-system sales from network resources.
    1563. PNM-TNMP contends that the Commission has held that formal 
undesignation and redesignation are not required, so long as the 
transmission

[[Page 12467]]

provider treats its own resources and the network resources of network 
customers comparably. PNM-TNMP and Pinnacle further argue that to 
require formal undesignation and redesignation would appear to do 
nothing more than impose an extra layer of administration to the 
management of network resources, making power sales more difficult and 
potentially reducing financial benefits to end use customers. 
Bonneville argues that the Commission's proposals regarding the use of 
network resources for surplus sales are likely to raise the cost to 
consumers.
    1564. Duke requests that the Commission clarify that any product 
that is not ``designatable'' as a network resource by a buyer may be 
sold by a seller that happens to be a network customer, without having 
to undesignate any network resources.
    1565. Suez Energy NA requests that the Commission ensure that a 
utility cannot use redesignation to hoard transmission capacity in 
order to deprive independent power producers of access to the grid. It 
contends that a utility could consistently hold transmission to serve 
generation that never runs for economic reasons and, the day before 
power flows, redesignate that transmission to accommodate a third-party 
purchase, effectively using its ability to redesignate network 
transmission capacity to hoard scarce ATC. In order to prevent 
potential abuse, Suez Energy NA agrees with the NOPR proposal to 
require transmission providers to use the same OASIS procedures to 
designate and terminate network status for themselves that they apply 
to network customers.
    1566. If the Commission requires formal designations and 
undesignations, EEI asks the Commission to clarify whether it is 
changing its policy that it is not necessary to modify service 
agreements in such circumstances in order to avoid requiring 
transmission providers to make numerous filings amending service 
agreements.\897\ If formal undesignations are required, EEI argues on 
reply that each transmission provider would be required to submit a 
revised application for network service under section 29.2 of the pro 
forma OATT both at the time the resource was undesignated and at the 
time that resource was redesignated. EEI also argues that formal 
undesignation would require the execution and filing of revised network 
service agreements reflecting the changes.
---------------------------------------------------------------------------

    \897\ See Virginia Electric and Power Co., 81 FERC ] 61,125 at 
61,111-12 (1997), reh'g denied, 82 FERC ] 61,034 (1998).
---------------------------------------------------------------------------

    1567. South Carolina E&G argues in its reply comments that off-
system sales of firm power are typically in the form of a slice-of-
system sale. South Carolina E&G requests that the Commission provide 
guidance for how to treat such a sale of power, suggesting that the 
transmission provider be permitted to undesignate a slice of a system 
sufficient to support the firm power sale and then, at the conclusion 
of the sale, redesignate that slice of the system as a network 
resource.
    1568. While generally supporting the Commission's proposal to 
continue to allow network customers and the transmission provider, with 
respect to its native load, to undesignate network resources to allow 
them to make sales to third parties, some commenters seek certain 
changes, consideration, or clarification by the Commission.\898\ EEI, 
joined by TDU Systems on reply, argue that the Commission should modify 
its statement that network customers should be permitted to undesignate 
network resources ``on a short-term basis to make off system sales.'' 
They argue that nothing in Order No. 888, the Commission's decisions, 
or the public interest requires that network resources be undesignated 
only for short-term sales. They further argue that such sales need not 
be ``off-system.'' Progress Energy argues that the Commission should 
only allow transmission customers to undesignate network resources to 
make firm off-system sales for a term which the transmission customer 
has adequate generation reserves to serve its network load. In its 
view, the transmission provider also must have the authority to deny 
the designation or undesignation of the network resources if the 
transmission provider determines that it needs the network resources to 
preserve the reliability of its transmission system or to ensure that 
there is sufficient transmission capability to support the requested 
changes. NRECA disagrees on reply, arguing that granting transmission 
providers the authority to deny undesignation requests would give them 
too much discretion and the perfect opportunity to discriminate.
---------------------------------------------------------------------------

    \898\ E.g., EEI, Pinnacle, and Progress Energy.
---------------------------------------------------------------------------

    1569. Progress Energy agrees with the Commission that network 
service involves the entire transmission provider's system and does not 
involve a contract path like point-to-point service. It also agrees 
that the delivery of a network resource once inside the system does not 
need to be redirected. Progress Energy notes that peaking resources 
have low capacity factors and, therefore, their transmission 
reservations are frequently underutilized. They request that network 
customers be given the ability to optimize their transmission purchases 
by bringing energy into the host transmission provider's system from 
other designated network resources in times when they are not using 
their peaking designated resources.
    1570. MDEA, Progress Energy, and Entergy request that, for 
reliability and economic reasons, network customers be given the 
flexibility to substitute new designated network resources without 
abandoning the original transmission queue position of an existing 
designated network resource.\899\ If the Commission does not change its 
proposal in order to provide network customers with this flexibility, 
Progress Energy contends that point-to-point service will be a superior 
service to network service.
---------------------------------------------------------------------------

    \899\ In its reply comments, MDEA requests that any such 
flexibility afforded to transmission providers also be available to 
network customers on a non-discriminatory basis.
---------------------------------------------------------------------------

    1571. Entergy states that it is important for the Commission to 
recognize that the undesignation of network resources can be used by 
network customers as a means of allowing merchant generators the 
opportunity to displace existing resources in serving network and 
native load. It argues that the Commission should be wary of limiting 
the ability of a network customer to undesignate network resources, as 
any such restriction will have broader implications than just the 
ability of network customers, including the transmission provider's 
wholesale merchant function, to sell that resource off-system with 
point-to-point service.
    1572. Entergy also requests that the Commission clarify that, while 
network customers cannot redirect network service, nothing in this 
prohibition prevents transmission providers from studying requests to 
designate new network resources as displacements of existing network 
resources. It argues that preventing network customers from using 
automated study functions would significantly hinder the ability of 
these customers to substitute their existing long-term resources with 
short-term purchases of energy and capacity from merchant generators 
when it is economical to do so.
    1573. TDU Systems argue that network customers (and transmission 
providers to the extent they serve native load on other systems) should 
be able to schedule output on a firm basis from

[[Page 12468]]

network resources on one system to serve their network loads on 
neighboring systems without having to designate and redesignate network 
resources among the various transmission providers' control areas. TDU 
Systems state this would permit LSEs that serve across multiple systems 
to come closer to replicating the economic dispatch of control area 
operators, significantly reducing the cost of discharging their service 
obligations to the customers they serve.
    1574. Xcel opposes requiring a transmission customer to undesignate 
a network resource even in a situation where the resource is used only 
transiently to provide off-system sales, arguing that such policy would 
have significant adverse consequences for customers across the country. 
It points out that it is native load customers that frequently benefit 
from purchase of economy energy and that, if an undesignation was 
required to deliver economy energy, most such transactions likely would 
not occur. Xcel also argues the NOPR concepts relating to designation 
of network resources and justification of economy energy purchases are 
irrelevant in the context of an RTO where energy is procured and 
dispatched throughout the RTO on a security constrained economic basis.
    1575. EEI, joined by TDU Systems on reply, requests that the 
Commission clarify that any changes to the procedures for designating 
and undesignating network resources apply only to designations made 
after the Final Rule becomes effective, in order to avoid substantial 
adverse impacts on the reliability of service to network and native 
loads. Duke and Pinnacle request that the Commission require NAESB to 
develop standards that address undesignation and redesignation and 
allow sufficient time for the NAESB process and for OASIS tools to be 
developed and approved, prior to the implementation of a new policy. 
TranServ asks that the undesignation of network resources be supported 
on OASIS.
Commission Determination
    1576. We disagree with commenters arguing that formal 
undesignations and/or redesignations of resources used to make firm 
third-party sales should not be required. The undesignation and 
redesignation requirements exists not only to promote reliability, but 
also to prevent undue discrimination, promote comparable treatment of 
customers, and increase the accuracy of ATC calculations. We find that 
the interest in advancing these policy goals overrides the minimal 
burden and cost that submitting undesignations and/or redesignations 
entails. We disagree with Xcel's argument that most economy energy 
purchases that benefit its native load customers likely will not take 
place if undesignation of network resources is required prior to firm, 
third-party sales. First, the requirement to undesignate network 
resources only applies to firm sales, while typical non-firm economy 
energy transactions would not require undesignation. Second, 
undesignating a network resource is not unduly burdensome, consisting 
only of electronically submitting several items of information, as 
described above. Therefore, we do not believe that a transaction 
prevented purely as a result of the requirement to undesignate network 
resources would have provided any significant economic value had it 
taken place.
    1577. We find that requests to allow ``informal undesignations'' 
appear to be simply requests to not require undesignations at all. 
Since the salient feature of requiring an undesignation is that the 
proper account is taken of the effects on ATC, informal undesignations, 
which do not take proper account of the fact that a resource is no 
longer a designated network resource, appear to serve no purpose.
    1578. With regard to PNM-TNMP's argument that the Commission has 
held that formal undesignation and redesignation are not required, so 
long as the transmission provider treats its own resources and the 
network customer's resources comparably, we believe PNM-TNMP 
misunderstands our policies. We note that PNM-TNMP provides no citation 
to Commission precedent to support its statement.
    1579. Duke requests clarification as to whether a network customer 
must undesignate a network resource in order to make a third-party sale 
from that resource if the third-party sale would not itself qualify to 
be designated as a network resource. We reiterate the existing 
requirement that designated network resources must not be committed for 
sale to non-designated third-party load or include resources that 
otherwise cannot be called upon to meet the network customer's network 
load on a noninterruptible basis. We find that a resource is 
``committed for sale to a non-designated third party load'' if a power 
purchase agreement for the sale from that resource provides for 
penalties if service to the third party is interrupted in order to 
serve the designated network load.
    1580. In response to comments by EEI, NRECA, and Suez Energy NA, we 
reiterate that all parties, including transmission providers serving 
their native loads, are subject to these requirements for designation 
and undesignation of network resources. Section 28.2 of the pro forma 
OATT clearly provides that transmission providers are required to 
designate resources and loads in the same manner as any network 
customer. We encourage parties suspecting that transmission providers 
or other network customers are not conforming to the requirements for 
designating or undesignating network resources to report their concerns 
using the Commission's Enforcement Hotline.
    1581. EEI has requested clarification of whether the Commission is 
changing its policy that transmission providers do not need to modify 
network service agreements when network resources are undesignated and 
redesignated. We have not proposed and do not intend to begin requiring 
that network customers file modified service agreements when network 
resources are designated or undesignated. As we explained in Dayton 
Power and Light Co.,\900\ ``changes in network resources may require 
the customer to file a request under OASIS, but a change to the 
information recorded initially in the network service agreement is not 
a requirement.'' EEI also argues that, if formal undesignations are 
required, then each transmission provider would be required to submit a 
revised application for network service under section 29.2 of the pro 
forma OATT, both at the time the resource was undesignated and the time 
that resource was redesignated. We disagree. There is no requirement 
that a transmission provider submit a revised application for network 
service every time a resource is designated or undesignated.
---------------------------------------------------------------------------

    \900\ 93 FERC ] 61,331 at 62,128 (2000).
---------------------------------------------------------------------------

    1582. In response to a request by South Carolina E&G, we clarify 
that firm third-party sales may be made from an undesignated portion of 
a network customer's network resources (i.e., a ``slice-of-system 
sale''), so long as all of the applicable requirements are met. In 
particular, the network customer must submit undesignations for each 
portion of each resource supporting the third-party sale. If the 
undesignation is temporary, then the request must be accompanied by a 
request to redesignate the resource(s) on a specific date. When the 
undesignation takes effect, the network customer must update the 
capacities specified in its list of designated network resources posted 
on OASIS.
    1583. We agree with EEI and TDU Systems' comments that there should 
be

[[Page 12469]]

no minimum term for undesignations. We also agree with EEI and TDU 
Systems' arguments that network customers should not be restricted to 
temporarily undesignating network resources only for use in off-system 
sales, and clarify that network customers are not so restricted.
    1584. We agree with Progress Energy that network customers should 
only make firm third-party sales when they have sufficient generation 
reserves to serve their loads. However, the purpose of the pro forma 
OATT is to provide nondiscriminatory transmission access, not to 
enforce generation adequacy requirements.
    1585. With regard to Progress Energy's request for flexibility to 
evaluate potential impacts to the transmission system related to the 
undesignation and redesignation of network resources, we find that 
situations where undesignations cannot be accommodated due to 
transmission constraints should be extremely rare, such as highly-
extraordinary counterflow situations. In such rare situations, the 
transmission provider should attempt to remedy the situation without 
denying the undesignation. If it is determined that the resource cannot 
be undesignated without jeopardizing reliability, then the transmission 
provider may deny the request for undesignation.
    1586. We share NRECA's concern that allowing transmission providers 
to deny undesignations for reliability reasons could give a direct 
market competitor a significant opportunity to discriminate, but must 
weigh this concern against our significant interest in preserving 
reliability. We point out that transmission providers denying requests 
for service or changes to service because of reliability concerns must 
post a description of such denials in accordance with section 
37.6(e)(2) of the Commission's regulations.\901\ Again, we encourage 
any parties with concerns about denials of service or changes to 
service by a transmission provider for reasons of reliability to report 
their concerns to the Commission's Enforcement Hotline.
---------------------------------------------------------------------------

    \901\ 18 CFR 37.6(e)(2).
---------------------------------------------------------------------------

    1587. We deny requests by MDEA, Progress Energy, and Entergy that 
network customers be given the flexibility to substitute new designated 
network resources without abandoning the original transmission queue 
position of an existing designated network resource. These parties seem 
to be requesting that a network customer be allowed to be ``first in 
line'' to use the ATC freed up by an undesignation of a network 
resource, as long as the network customer uses that ATC to designate an 
alternate resource. We disagree. Granting this request would, without 
any apparent justification, put point-to-point customers seeking ATC 
freed up by an undesignation at a disadvantage. We also disagree that, 
if the Commission does not allow network customers this flexibility, 
point-to-point service will be a superior service to network service. 
Progress Energy seems to be arguing that the point-to-point customer's 
ability to engage in a redirect affords that customer more flexibility 
than the network customer. We point out that redirects of point-to-
point service on a firm basis are only on an ``as-available'' basis. 
Firm point-to-point customers cannot redirect unless ATC is available 
to support such a redirect after all higher-priority requests have been 
accommodated.
    1588. Entergy has requested clarification that, while network 
customers cannot redirect network service, nothing in this prohibition 
prevents transmission providers from studying requests to designate new 
network resources as displacements of existing network resources. 
Although Entergy's request is unclear, we reiterate that redirects are 
not allowed within the context of network service and that network 
customers are not ``first in line'' to use ATC freed up by their 
undesignation of another network resource. Such requests must be 
processed taking proper account of all competing transmission service 
requests of higher priority.
    1589. We disagree with TDU System's argument that network customers 
should be able to schedule output on a firm basis from network 
resources on one system to serve their network loads on neighboring 
systems without having to designate and redesignate network resources 
among the various transmission providers' control areas. Allowing 
network customers to not formally undesignate and redesignate network 
resources, even only when using those resources to serve their network 
loads on neighboring systems, will necessarily result in inaccurate 
evaluations of ATC. We reiterate that the burden associated with 
undesignating and redesignating the resources is particularly light and 
find that requiring network customers to make temporary undesignations 
when making third-party firm sales is thus justified in light of the 
ATC-related benefits.
    1590. Xcel argues that the concepts relating to designation of 
network resources are irrelevant in the context of an RTO where energy 
is procured and dispatched throughout the RTO on a security constrained 
economic basis. We agree that Day 2 RTOs do not use the physical rights 
model contemplated under the pro forma OATT and, hence, not all the 
provisions discussed here are directly applicable to Day 2 markets. 
However, as we explain in section IV.C.2, RTOs and ISOs must make the 
necessary filings to comply with the Final Rule, or demonstrate that 
their existing tariff provisions are consistent with or superior to the 
terms of the revised pro forma OATT.
    1591. We agree with parties arguing that network customers should 
not be required to use the new NAESB processes and OASIS tools to be 
developed in response to this section until such time as the NAESB 
standards and OASIS functionality have been developed and implemented. 
However, once the new standards and functionality are in place, network 
customers must use these new procedures to undesignate (whether 
temporarily or as part of an indefinite termination) any network 
resources, regardless of the date that those resources were originally 
designated.
7. Clarifications Related to Network Service
a. Secondary Network Service
    1592. Section 28.4 of the existing pro forma OATT allows a network 
customer to deliver energy to its network load from non-designated 
network resources on an as-available basis without additional charge, 
referred to as secondary network service. In Order No. 888, the 
Commission described such energy as non-firm economy energy purchases 
used to displace firm network resources.\902\
---------------------------------------------------------------------------

    \902\ Order No. 888 at 31,751.
---------------------------------------------------------------------------

    1593. The use of secondary network service to deliver purchased 
power when a network customer is making off-system sales has been 
raised in several Commission investigations and audits. In Idaho Power, 
the Commission accepted a settlement with Idaho Power related to Idaho 
Power's incorrect use of the native load priority to access its 
transmission system.\903\ In Idaho Power, the utility's wholesale 
merchant function purchased power outside of Idaho Power's control area 
to facilitate an off-system sale and used secondary network service to 
bring the purchases into Idaho Power's control area.\904\ In accepting 
the settlement, the Commission stated that ``[i]t is axiomatic that the 
native load priority

[[Page 12470]]

cannot be used to complete sales that are not necessary to serve native 
load.'' \905\ In MidAmerican, the Commission issued an audit report 
that contained a finding that MidAmerican's wholesale merchant function 
used network service instead of point-to-point service to deliver 
short-term energy purchases to its control area that were not used to 
serve MidAmerican's native load.\906\
---------------------------------------------------------------------------

    \903\ Idaho Power Co., 103 FERC ] 61,182 at P 2 (2003) (Idaho 
Power).
    \904\ Id. at P 4.
    \905\ Id.
    \906\ MidAmerican Energy Co., 112 FERC ] 61,346 at P 6 (2005).
---------------------------------------------------------------------------

NOPR Proposal
    1594. In the NOPR, the Commission proposed to clarify that a 
network customer may not use secondary network service to import energy 
onto its system to support an off-system sale if the purchased power 
does not displace the customer's own higher cost generation. The 
Commission therefore proposed to modify section 28.4 of the pro forma 
OATT to state that a network customer may use secondary network service 
only to deliver economy energy and to define ``economy energy'' as 
energy purchased by a network customer that displaces the customer's 
own higher cost generation for the purpose of serving the customer's 
designated network loads. The Commission further explained that all 
participants engaging in purchases for resale must compete on a 
comparable basis and use point-to-point service to complete all 
segments of a purchase for resale off-system.
(1) Overview
Comments
    1595. Several commenters agree with the Commission and support the 
proposed clarification regarding the use of secondary network 
service.\907\ Alberta Intervenors state that such a restriction ensures 
fair competition among network customers and preserves the entitlement 
of native load customers.
---------------------------------------------------------------------------

    \907\ E.g., Alberta Intervenors, Southern, Suez Energy NA, and 
TAPS.
---------------------------------------------------------------------------

    1596. Other participants oppose the proposal, arguing that it is 
too broad and would interfere with legitimate activity by network 
customers.\908\ EEI points out that, if a network customer is using all 
available network resources but is still purchasing energy from non-
designated network resources to meet its peak native load, the network 
customer would need to rely on secondary service to transmit this 
purchase. In EEI's view, the Commission's proposal would prevent this 
customer from using secondary service for this non-economy energy, 
thereby interfering with its service obligations. To avoid such cases, 
EEI, Pinnacle, and PGP recommend that secondary service not be limited 
to economy energy only. NRECA states that the Commission's proposed 
limitation on the use of secondary service would prevent network 
customers from meeting their native load obligations in cases of 
extreme weather and power outages. NRECA asks the Commission to state 
explicitly in section 28.4 of the pro forma OATT that secondary service 
may not be used to facilitate off-system third party sales, but rather 
must be used to import power needed to serve network load economically 
and efficiently. Entergy suggests the Commission abandon the limitation 
and specify simply that secondary service cannot be used to serve loads 
other than the network or native load.
---------------------------------------------------------------------------

    \908\ E.g., EEI, Entergy, Northwest Parties, NRECA, Pinnacle, 
PGP, Southern, and Xcel.
---------------------------------------------------------------------------

    1597. Others argue that the restriction of secondary service to 
only economy energy would have unintended consequences regarding the 
purchase of renewable resources. Emerald, Flathead, and the Northwest 
Parties state that, for reasons of customer demand or contractual 
obligation, network customers may be required to purchase renewable 
power that generally is more expensive than traditional thermal or 
hydro electric generation. These purchases could displace less 
expensive non-renewable resources, resulting in the need for the 
network customer to make off-system sales of the non-renewable 
resources. Emerald, Flathead, and Northwest Parties suggest that the 
Commission revise the definition of ``economy energy'' to include an 
exception for renewable energy. TAPS raises a similar issue, asking the 
Commission to clarify that economy purchases as well as substitute 
resources qualify for use of secondary service.
    1598. EEI argues that the proposed limitation on secondary service 
would require all network customers to engage in a specific form of 
Commission-regulated economic dispatch, while requiring transmission 
providers to evaluate each resource and become ``dispatch police.'' 
Entergy, SPP, and PGP agree. They assert that calculating the ``cost'' 
of power is problematic, inherently subjective and burdensome because 
transmission providers lack the necessary knowledge to perform this 
analysis. EEI, Entergy, SPP, and PGP instead suggest that the 
Commission conduct periodic audits of secondary service to ensure 
compliance with the requirements of OATT section 28.4 rather than 
transmission providers.
    1599. Although Powerex supports the Commission's restriction on the 
proper use of secondary service, it also states that determining 
whether or not an import would qualify as ``economy energy'' would be 
difficult. Powerex requests that the Commission implement specific 
rules in advance of such transactions to resolve uncertainty. It 
suggests a capacity test to prevent preferential acquisition of 
generation capacity, a tariff prohibition on the use by the network 
customer or its energy affiliates of any export transmission capacity 
made available on another intertie, and the modification of business 
practices governing curtailment. In reply, Alberta Intervenors agree 
with Powerex's proposed changes to curtailment practices, but disagree 
with the other two elements. Alberta Intervenors assert that the tariff 
prohibition causes inefficient use of ATC and that the capacity test is 
not a stand-alone test and, as a result, would only be helpful as a 
supplement to the ``economy energy'' test.
    1600. Some participants raise other issues not addressed in the 
NOPR. South Carolina E&G asks that the Commission clarify its policy on 
purchases of economy energy, as well as provide a clear definition of 
the acceptable trading practices--notably parking, hubbing, and 
lending--under the current pro forma OATT. Emerald and Flathead request 
the Commission to revise the definition of ``network load'' in section 
1.24 of the pro forma OATT to allow point-to-point and network service 
to the same discrete point of delivery. Morgan Stanley asks that the 
Commission explain why using secondary service to make an off-system 
purchase while there is any off-system sale during the same interval is 
improper and whether the Commission will prohibit such activity only if 
the off-system purchase and sale are part of a single transaction. 
Finally, Xcel argues that the concepts relating to designation of 
network resources are irrelevant in the context of an RTO where energy 
is procured and dispatched throughout the RTO on a security constrained 
economic basis.
Commission Determination
    1601. In general, the Commission agrees with parties that favor an 
expansion of the proper use of secondary network service. Although we 
affirm our finding in MidAmerican,\909\ the Commission

[[Page 12471]]

recognizes that there are instances outside the proposed definition of 
economy energy that warrant the use of secondary service in order to 
serve network loads reliably. The Commission therefore declines to 
adopt the definition of economy energy proposed in the NOPR and, 
instead, will retain the existing section 28.4 that permits use of 
secondary network service ``to deliver energy to its Network Loads.''
---------------------------------------------------------------------------

    \909\ MidAmerican Energy Co., 112 FERC ] 61,346 at P 6 (2005) 
(MidAmerican). Following an audit, the Commission found that 
MidAmerican's wholesale merchant function used network service 
instead of point-to-point service to deliver short-term energy 
purchases to its control area that were not used to serve 
MidAmerican's native load. The Commission stressed that the use of 
secondary network service is not for the purpose of serving off-
system sales. Id. at P 6. The modifications to section 28.4 adopted 
in this Final Rule do not alter that limitation.
---------------------------------------------------------------------------

    1602. With respect to Powerex's comments, we reject the requested 
clarifications as Powerex has not fully supported the use of its 
proposed capacity test or other measures and has not demonstrated that 
such test would not preclude legitimate uses of this priority as noted 
in the NOPR. If parties suspect inappropriate use of secondary network 
service, they may report the suspected activity to the Commission's 
Enforcement Hotline or file a compliant with the Commission pursuant to 
FPA section 206. Furthermore, the Commission's staff will continue to 
provide oversight of all tariff-related activities through its 
enforcement program.
(2) ``On an as-available basis''
    1603. Section 28.4 of the existing pro forma OATT allows a network 
customer to use secondary network service to deliver energy purchases 
to its network load from non-designated resources ``on an as-available 
basis.'' However, the current pro forma OATT does not specify how a 
network customer must arrange for secondary network service.
NOPR Proposal
    1604. In the NOPR, the Commission proposed to modify section 28.4 
of the pro forma OATT to clarify that a network customer does not need 
to file an application for network service to receive secondary 
service. Instead, the customer must merely request such service on 
OASIS in a manner consistent with pro forma OATT sections 18.1 and 18.2 
(Procedures for Arranging Non-Firm Point-to-Point Transmission 
Service).
Comments
    1605. TDU Systems requests that the Commission clarify that time 
constraints located in OATT section 18.3 are not applicable to 
secondary service. Section 18.3 provides that requests for non-firm 
point-to-point service shall not be made before certain specified 
periods (more than 60 days in advance for monthly service, more than 14 
days in advance for weekly service, etc.). TDU Systems states that some 
of its members currently use secondary service to access economy off-
system purchases where intervening transmission constraints preclude 
the designation of those resources as network resources for long 
periods of time. Application of the non-firm point-to-point service 
request deadlines would impair TDU Systems' ability to rely on 
secondary service in those instances since they would extend beyond the 
timing requirements set forth in section 18.3.
Commission Determination
    1606. The Commission clarifies that secondary service must be 
requested in accordance with section 18, including the timing 
restrictions set forth in section 18.3, of the pro forma OATT. 
Secondary service is on an as-available basis, and network customers 
should not be permitted to lock in such service in advance of other 
non-firm uses of available transmission. Allowing lower-priority 
secondary service to have a scheduling advantage over non-firm 
transmission would be inappropriate and would discourage the use of 
non-firm transmission service, thereby minimizing the revenue credits 
from non-firm transmission service that benefit all firm transmission 
customers.
(3) Redirect of Network Service
    1607. The current pro forma OATT does not include any provision to 
change the point of receipt for an off-system designated network 
resource in a manner similar to redirect of point-to-point service. We 
are aware, however, that several transmission providers have posted 
business practices that allow network customers either to substitute an 
off-system non-designated network resource for a designated network 
resource or to redirect the point of receipt associated with an 
existing network resource.
NOPR Proposal
    1608. The Commission proposed to clarify that network customers may 
not redirect network service in a manner comparable to redirect of 
point-to-point service, as network service involves no identified 
contract path and is, therefore, not a directable service. Should a 
network customer wish to substitute one designated network resource for 
another, the Commission stated that it must terminate the existing 
resource and designate a new one. The Commission explained that the 
network customer could also request to redesignate its original network 
resource by making a request to designate a new network resource. 
Alternatively, a network customer could use secondary network service 
when it wants to substitute a non-designated network resource for a 
designated network resource on an as-available basis.
Comments
    1609. MISO strongly supports the Commission's clarification stating 
that network service is not a directable service and believes that the 
proposal appropriately clarifies the Commission's policy on redirect 
service. TDU Systems and NRECA, however, believe that the Commission 
should allow redirects of network service to deliver an LSE's 
resources. TDU Systems assert that redirect of network service is 
critical to LSEs serving native load across multiple transmission 
systems because it allows the amount of flexibility necessary to manage 
power supply costs. In addition, in TDU Systems' view, redirects have 
no effect on system reliability.
    1610. EEI argues on reply that it is unclear why redirects of 
network service should be allowed. The advantage of redirecting firm 
point-to-point service is that the customer does not have to pay an 
additional charge for transmission service. However, both TDU Systems 
and NRECA agree that network customers should pay an additional charge 
for transmission service from network resources to off-system loads.
    1611. Sacramento alternatively recommends that the Commission 
remove the ban on off-system sales in order to maximize efficiency in 
allocating transmission capacity. Occidental requests that the 
Commission place all transmission, including on behalf of native load, 
under the OATT guidelines to ensure that service is provided in a non-
discriminatory fashion.
Commission Determination
    1612. The Commission clarifies that network customers may not 
redirect network service in a manner comparable to the way customers 
redirect point-to-point service. Point-to-point service consists of a 
contract-path with a designated point of receipt and point of delivery. 
Network service has no identified contract-path and is therefore not a 
directable service. Network service instead provides for the 
integration of new network resources and permits designation of another 
network resource, which has the same practical effect as redirecting 
network service. If the customer wants to permanently

[[Page 12472]]

substitute one designated network resource for another, it should 
terminate the designation of the existing network resource and 
designate a new network resource. The customer could then simply 
request to redesignate its original network resource, if it so desires, 
by making a request to designate a new network resource. The ability of 
a network customer to also temporarily substitute one designated 
network resource for another is addressed in section V.D.6.
    1613. The Commission rejects Sacramento's proposal to remove the 
ban on off-system sales. Network service is not based upon making off-
system sales, but rather on integrating a network customer's resources 
with its load. Transmission providers must take point-to-point 
transmission service for off-system sales and network customers should 
be treated comparably. The Commission also rejects Occidental's request 
to place all transmission, including on behalf of native load, under 
the pro forma OATT. In Order No. 888-A the Commission clarified that a 
``transmission provider is not required to `take service' under its own 
tariff for the transmission of power that is purchased on behalf of 
bundled retail customers.'' \910\ However, the Commission required that 
transmission providers, pursuant to section 28.2 of the pro forma OATT, 
must designate network resources and network loads in the same manner 
as any network customer. Occidental offers no explanation why the 
existing requirement of section 28.2 is not sufficient to address its 
concerns.
---------------------------------------------------------------------------

    \910\ Order No. 888-A at 30,216.
---------------------------------------------------------------------------

b. Behind the Meter Generation
    1614. In Order No. 888, in response to customers with load served 
by ``behind the meter'' generation that sought to eliminate such load 
from their network calculation, the Commission found that a customer 
may exclude a particular load at discrete points of delivery from its 
load ratio share of the allocated cost of the transmission provider's 
integrated system. The Commission determined, however, that customers 
electing to do so must seek alternative transmission service, such as 
point-to-point transmission service, for any load that has not been 
designated as network load for network service.\911\ In Order No. 888-
A, the Commission stated that it would permit a network customer to 
either designate all of a discrete load as network load under the 
network integration transmission service or to exclude the entirety of 
a discrete load from network service and serve such load with the 
customer's behind the meter generation and/or through any point-to-
point transmission service.\912\
---------------------------------------------------------------------------

    \911\ Order No. 888 at 31,736.
    \912\ Order No. 888-A at 30,258-61.
---------------------------------------------------------------------------

    1615. The Commission did not address the subject of behind the 
meter generation in the NOPR. A few commenters nonetheless proposed 
revisions to the pro forma OATT to require netting of a network 
customer's behind the meter generation against their network load as 
described in more detail below.
Comments
    1616. Some commenters argue that, in order to meet the objective of 
eliminating discrimination in the provision of open access transmission 
service, the Commission must require comparable treatment between 
retail native load and network customers by allowing network customers 
to net behind the meter generation against their network load.\913\ 
Specifically, such commenters argue that the Commission should modify 
the current pricing rules for network service to allow an LSE's load 
ratio share to reflect the reduction in load caused by behind the meter 
generation serving retail load.\914\ In support of this position, these 
commenters argue that assigning transmission-related costs to customers 
that do not rely on the transmission provider's system to serve load is 
inconsistent with the Commission's cost-causation principles.\915\ For 
example, CAC/EPUC contends that customer generation does not cause the 
transmission provider to incur costs when power is not being sold to or 
taken off the grid. Similarly, AMP-Ohio argues that it is inappropriate 
to assign a full load ratio share of transmission-related costs to 
behind the meter generation customers that do not use the network to 
the full extent of their load ratio shares.\916\ Further, CAC/EPUC 
asserts that measuring the customer's use of the transmission system at 
the customer's meter would be appropriate as it would demonstrate that, 
if no power flows to the customer from the grid occur, that customer 
has not used nor caused costs to be incurred by the grid for the 
delivery of its energy requirements.
---------------------------------------------------------------------------

    \913\ E.g., TAPS, TDU Systems, AMP-Ohio, and CAC/EPUC.
    \914\ TDU Systems and TAPS also cite Consumers Energy, 98 FERC ] 
61,333 at 62,410 (2002) (requiring that a transmission provider's 
retail load associated with behind the meter generation be included 
in the transmission provider's load ratio share to ensure 
comparability between transmission providers and network customers 
in the calculation of load ratio share).
    \915\ E.g., AMP-Ohio, CAC/EPUC, and TAPS.
    \916\ Citing Occidental Chemical Corporation v. PJM 
Interconnection, L.L.C., and Delmarva Power & Light Company, 102 
FERC ] 61,275 at P 14 (2003) (``Access charges for use of PJM's 
transmission system should be allocated to network customers based 
on a network customer's actual use of PJM's system, consistent with 
the principle of cost-causation.''); PJM Interconnection, L.L.C., 
107 FERC ] 61,113, at P 28 (2004).
---------------------------------------------------------------------------

    1617. Some commenters note that the Commission has approved PJM 
netting provisions that apply to behind the meter generation used by 
non-retail and wholesale customers to serve load.\917\ These same 
commenters further observe that PJM has filed with the Commission to 
expand participation in its behind the meter generation netting program 
to include municipal, electric cooperatives, and electric distribution 
transmission customers who take network service on the PJM system 
pursuant to a settlement agreement filed by PJM on October 24, 2005 in 
Docket No. EL05-127-000.\918\
---------------------------------------------------------------------------

    \917\ E.g., AMP-Ohio, TAPS, and TDU Systems (citing PJM 
Interconnection, L.L.C., 107 FERC ] 61,113 (2004), reh'g denied, 108 
FERC ] 61,032 (2004) (PJM)).
    \918\ This settlement agreement was accepted in PJM 
Interconnection, L.L.C., 113 FERC ] 61,279 (2005).
---------------------------------------------------------------------------

    1618. Further, both TAPS and AMP-Ohio argue that behind the meter 
generation provides benefits to the transmission provider that should 
be taken into account as part of system planning obligations. For 
instance, AMP-Ohio asserts that utility planning can and should be able 
to take into account the ability of customers to reduce their load on 
the system with behind the meter generation. TDU Systems also notes 
PJM's representation that allowing municipal and electric cooperative 
system participation in behind the meter generation netting programs 
increased reliability and demand response opportunities on PJM's 
system.\919\ Similarly, TAPS observes that PJM's rules reserve the 
right to call upon non-retail behind the meter generation under certain 
conditions.
---------------------------------------------------------------------------

    \919\ PJM Interconnection, L.L.C., 113 FERC ] 63,024 (2005).
---------------------------------------------------------------------------

Commission Determination
    1619. The Commission is not persuaded to require transmission 
providers to allow netting of behind the meter generation against 
transmission service charges to the extent customers do not rely on the 
transmission system to meet their energy needs. Commenters in this 
proceeding have not provided any different arguments that were not 
fully considered and addressed in Order No. 888, et al. The existing 
pro forma OATT already permits transmission

[[Page 12473]]

customers to exclude the entirety of a discrete load from network 
service and serve such load with the customer's behind the meter 
generation and through any needed point-to-point transmission service, 
thereby reducing the network customer's load ratio share. Therefore, 
the Commission's existing policy already provides customers with the 
opportunity to reduce network service costs to the extent a customer is 
not relying on the transmission system to meet its energy needs.\920\ 
As the Commission concluded in Order No. 888-A, transmission customers 
ultimately must evaluate the financial advantages and risks and choose 
to use either network integration or firm point-to-point transmission 
service to serve load.\921\ We believe it is most appropriate to 
continue to review alternative transmission provider proposals for 
behind the meter generation treatment on a case-by-case basis, as the 
Commission did in the PJM proceeding cited by the commenters.
---------------------------------------------------------------------------

    \920\ We note that EEI responds to allegations of undue 
discrimination in the calculation of load ratio share costs in the 
OATT Definitions section of this Final Rule.
    \921\ Order No. 888-A at 30,260-61.
---------------------------------------------------------------------------

8. Transmission Curtailments
    1620. In the NOPR, the Commission proposed no changes to the pro 
forma OATT with respect to curtailment provisions for point-to-point 
service (set forth in sections 13.6 and 14.7) and network service (set 
forth in section 33). These provisions establish the terms and 
conditions under which a transmission provider may curtail service to 
maintain reliable operation of the system. Though several commenters 
claimed in response to the NOI that the reasons for transmission 
curtailments are difficult to discern, they did not provide sufficient 
detail to indicate whether that difficulty is a result of inadequate 
disclosure regulations, inadequate compliance with those regulations, 
or some other reason. Therefore, the Commission sought further comment 
on whether requiring transmission providers to post additional 
information would improve transparency and the ability of customers to 
make use of that information. The Commission also declined in the NOPR 
to propose generic penalties for improper transmission curtailments.
Comments
    1621. APPA suggests that the Commission require transmission 
providers to produce additional information regarding firm transmission 
service curtailments, including all circumstances and events 
contributing to the need for such firm service curtailments, specific 
services and customers curtailed (including the transmission provider's 
own retail loads), and the duration of all such curtailments. TAPS also 
urges the Commission to move toward maximum transparency and require 
that sufficient information be provided for a customer to evaluate 
whether it has been treated fairly as compared to other users of the 
system including the transmission provider. TDU Systems suggests that 
the Commission require investigations into the need for network 
upgrades when Level 5 Transmission Loading Relief (TLR) procedures are 
repeatedly employed. It also suggests that all Level 5 TLRs be posted 
on OASIS and filed with the Commission. EEI agrees that providing 
customers with information on transmission curtailments may help to 
reduce confusion and suspicion concerning curtailments and suggests the 
Commission request WEQ (NAESB) to develop a more detailed template for 
posting information on curtailments that will be more useful to 
customers.
    1622. Southern and other commenters \922\ state that sufficient 
information regarding curtailments of transmission service is already 
available on OASIS and believe that the existing rules requiring 
transmission providers to make curtailment data available on OASIS are 
adequate. Nevada Companies request the Commission be very specific if 
it decides to mandate additional reporting requirements in order to 
remove the burden of potential confidentiality problems from the 
reporting entity.
---------------------------------------------------------------------------

    \922\ PNM-TNMP and TranServ.
---------------------------------------------------------------------------

    1623. Powerex is concerned about inconsistent communication and 
curtailment procedures. It recommends that the Commission require three 
additional measures including: Early notice of curtailment through the 
use of the ``recall'' function on OASIS; a requirement to provide 
credits for curtailed service when non-firm point-to-point transmission 
service is interrupted; and requiring pro rata curtailments made prior 
to the energy scheduling and tagging deadline (e.g., 20 minutes before 
the operating hour) to be based on reservation rather than schedule. In 
its reply comments, Seattle states support of pro rata curtailments 
based on reservations. TDU Systems recommend that the Commission 
require transmission providers to refund transmission charges to 
curtailed customers, to discourage transmission providers from 
overselling their systems. On reply, EEI and PNM-TNMP urge the 
Commission to reject the proposals to require transmission providers to 
refund transmission service charges to curtailed customers. They state 
that transmission providers are following ATC calculation procedures, 
but the planning process is not structured to overbuild the system to 
ensure that no curtailments occur. They also argue that the rate of 
return permitted in existing cost of service regulation does not 
account for the risk of loss of curtailment-related revenues. Northwest 
IOUs request the Commission examine whether pro rata curtailments of 
transactions to relieve transmission constraints unnecessarily impose 
burdens on transmission customers, because different curtailments on 
different paths have different effectiveness in relieving a given 
transmission constraint.
    1624. Manitoba Hydro notes that MISO is the only RTO in the Eastern 
Interconnection that does not redispatch when constraints occur on non-
market to market flows. Manitoba Hydro therefore urges the Commission 
to encourage implementation of redispatch to the fullest extent before 
resorting to curtailment. Seattle also supports modifying the pro forma 
OATT to require reliability redispatch. Seattle proposes that 
redispatch costs should be allocated to all classes of customers, and 
transmission providers' cost recovery should be allowed through 
automatic adjustment clause-type formulas to ensure all such costs are 
recovered. It suggests that routine maintenance outages are resulting 
in curtailments, which is an indication that transmission service is 
oversold. Seattle further suggests that transmission providers prepare 
a quarterly incident report for redispatch events detailing 
circumstances resulting in the redispatch, system status information, 
power transfer distribution factors, generator offers for redispatch 
and other information supporting redispatch determinations, including 
the basis for selecting generators called for redispatch.
    1625. APPA, EEI and others comment that the Commission should not 
impose generic penalties for improper curtailments, but treat 
violations on a case-by-case basis. To ensure compliance with 
curtailment posting information, Southwestern Coop suggests that the 
Commission adopt generic penalties for curtailment violations, claiming 
that penalties for transmission provider curtailment discrimination 
would provide incentives for compliance.

[[Page 12474]]

Commission Determination
    1626. The Commission concludes that the posting of additional 
curtailment information is necessary to provide transparency and allow 
customers to determine whether they have been treated in the same 
manner as other transmission system users, including customers of the 
transmission provider. A primary goal of this rulemaking is to remove 
opportunities for transmission providers to unduly discriminate in 
favor of their own or their affiliates' use of the transmission system. 
Making transparent details concerning transmission curtailments so that 
regulators and customers can verify that the transmission provider 
curtailed services in accordance with its OATT is entirely consistent 
with this goal. Commenters who oppose greater curtailment transparency 
offer no convincing evidence to suggest that any harm or hardship of 
doing so outweigh the benefits.
    1627. We agree with suggestions for the posting of additional 
curtailment information on OASIS and, therefore, require transmission 
providers, working through NAESB, to develop a detailed template for 
the posting of additional information on OASIS regarding firm 
transmission curtailments. Transmission providers need not implement 
this new OASIS functionality and any related business practices until 
NAESB develops appropriate standards. These postings must include all 
circumstances and events contributing to the need for a firm service 
curtailment, specific services and customers curtailed (including the 
transmission provider's own retail loads), and the duration of the 
curtailment. This information is in addition to the Commission's 
existing requirements: (1) When any transmission is curtailed or 
interrupted, the transmission provider must post notice of the 
curtailment or interruption on OASIS, and the transmission provider 
must state on OASIS the reason why the transaction could not be 
continued or completed; (2) information to support any such curtailment 
or interruption, including the operating status of facilities involved 
in the constraint or interruption, must be maintained for three years 
and made available upon request to the curtailed or interrupted 
customer, the Commission's Staff, and any other person who requests it; 
and, (3) any offer to adjust the operation of the transmission 
provider's system to restore a curtailed or interrupted transaction 
must be posted and made available to all curtailed and interrupted 
transmission customers at the same time.
    1628. The Commission rejects TDU Systems' proposal to require 
reports filed with the Commission regarding Level 5 TLRs or to require 
transmission providers to conduct investigations into the need for 
network upgrades when TLR 5 procedures are repeatedly employed. TDU 
Systems' proposal is unnecessary at this time in light of our 
requirement that OASIS templates for curtailment information be 
developed that will report occurrences of all levels of TLRs. This will 
enable the Commission and customers to monitor TLR patterns and 
frequency. Furthermore, the requirements imposed in this Final Rule for 
congestion studies as part of the coordinated, open and transparent 
planning requirement will allow stakeholders in the transmission 
provider's planning process to request studies of those portions of the 
transmission system where they have encountered transmission problems 
due to frequent and recurring constraints.
    1629. The Commission rejects the three proposals suggested by 
Powerex. First, it is not necessary to provide early curtailment 
notification through the OASIS ``recall'' function since the OASIS 
currently provides a curtailment notification function. Transmission 
providers should continue to use the OASIS Schedule Details template to 
post information on the scheduled uses of the transmission system and 
any curtailments and interruption thereof. Second, with respect to 
Powerex's request to credit customers when their non-firm point-to-
point transmission service is interrupted, we find it unnecessary to 
modify the pro forma OATT to adopt such crediting procedures, 
consistent with our finding in Order No. 888-A that proper crediting 
would vary depending on the specific rate design a company uses.\923\ 
Third, we believe that pro-rating curtailments based on reservations 
would have the potential to impair reliability since the amount of 
capacity actually curtailed using this approach would not address 
actual power flows and, therefore, may be less than required to relieve 
the overloaded facility.
---------------------------------------------------------------------------

    \923\ See Order No 888-A at 30,276. In Allegheny Power System, 
Inc., 80 FERC ] 61,143 at 61,549 (1997), the Commission clarified 
that where a transmission provider has not proposed an express 
crediting provision for the interruption of non-firm point-to-point 
customers, the transmission provider must compute its bill to an 
interrupted non-firm customer as if the term of service actually 
rendered were the term of service reserved. In other words, if a 
customer with a weekly reservation was interrupted after one day, 
its bill must be computed as if it had a daily reservation, and if a 
customer with a daily reservation was interrupted after ten hours, 
its bill must be computed using the hourly rate applied to ten hours 
of service.
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    1630. The Commission also rejects TDU Systems' recommendation to 
refund transmission charges to curtailed customers as a means of 
disciplining instances of improper curtailments or transmission 
providers' overselling their systems. We also reject proposals to 
remedy improper curtailments through refunds of transmission charges to 
curtailed customers or imposing generic penalties. Rather, the 
Commission believes that addressing allegations of inappropriate 
curtailment practices or transmission providers overselling their 
transmission system are more effectively administered by the Commission 
on a case-by-case basis.
    1631. With respect to the proposal to require redispatch to be 
performed to the fullest extent prior to curtailments, Manitoba Hydro 
itself notes that the proposal is intended to address curtailment and 
redispatch practices unique to MISO. Therefore we conclude that 
Manitoba Hydro's concerns are best addressed on a case specific basis.
    1632. Regarding Seattle's proposal to require what it characterizes 
as ``reliability redispatch'' to benefit and be paid by all customer 
classes, we note that this proposal would require expansion of the 
network service ``reliability redispatch'' provisions to apply to 
point-to-point service as well. The network service ``reliability 
redispatch'' provisions in pro forma OATT sections 33.2 and 33.3 were 
established in Order No. 888 to ensure comparable reliable service to 
network customers as the service that the transmission provider 
provides to its bundled retail load. These redispatch procedures 
further provide for redispatch of not just the transmission provider's 
own resources, but all network resources, including those of network 
customers, when required to maintain the reliability of the system and 
avoid the need for curtailments. Seattle has not demonstrated that its 
proposal to extend ``reliability redispatch'' for point-to-point 
service is required to ensure comparable, not unduly discriminatory 
transmission service and has not addressed why network customer 
resources should be redispatched for the benefit of point-to-point 
customer. Accordingly, we decline to adopt Seattle's proposal. We 
discuss redispatch issues more broadly in section V.D.1 of this Final 
Rule.

[[Page 12475]]

9. Standardization of Rules and Practices
a. Business Practices
    1633. In Order No. 888, the Commission required each public utility 
that owns, controls, or operates facilities used for transmitting 
electricity in interstate commerce to file, pursuant to section 205 of 
the FPA, a pro forma OATT under which it would provide open access 
transmission services. However, certain rules, standards, and practices 
governing the provision of transmission service (e.g., public utility 
business practices) are not reflected in the pro forma OATT. Only when 
a public utility adopts a rule, standard, or practice that 
significantly affects its rates and services has the Commission 
required it to make a filing pursuant to FPA section 205 to amend its 
OATT.\924\ The Commission has applied this policy using a ``rule of 
reason'' test.\925\
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    \924\ E.g., Cleveland v. FERC, 773 F.2d 1368, 1376 (D.C. Cir. 
1985).
    \925\ See, e.g., Public Serv. Comm'n of N.Y. v. FERC, 813 F.2d 
448, 454 (D.C. Cir. 1987) (holding that the Commission properly 
excused utilities from filing policies or practices that dealt with 
only matters of ``practical insignificance'' to serving customers); 
Midwest Independent Transmission System Operator, Inc., 98 FERC ] 
61,137 at 61,401 (``It appears that the proposed Operating protocols 
could significantly affect certain rates and service and as such are 
required to be filed pursuant to section 205.''), order granting 
clarification, 100 FERC ] 61,262 (2002).
---------------------------------------------------------------------------

NOPR Proposal
    1634. In the NOPR, the Commission proposed not to modify its 
existing policy regarding the inclusion of rules, standards and 
practices in a transmission provider's OATTs. The Commission expressed 
concern that requiring transmission providers to include all of their 
rules, standards, and practices in their OATTs could decrease a 
transmission provider's flexibility to change business practices and 
respond to the requests of its customers. The Commission also expressed 
a belief that requiring transmission providers to file all of their 
rules, standards, and practices in their OATTs would be impractical and 
potentially administratively burdensome.
    1635. The NOPR further noted that there is broad consensus that 
rules, standards, and practices not required to be included in a 
transmission provider's pro forma OATT should be posted on the 
transmission provider's OASIS. The Commission agreed and proposed to 
require transmission providers to post on OASIS all of their rules, 
standards, and practices that relate to transmission services. The 
Commission sought comment on how best to determine what ``relates'' to 
transmission service to facilitate a consistent interpretation and to 
minimize discretion on what rules, practice and standards should be 
posted on OASIS.
    1636. On the particular issue of creditworthiness and security 
requirements, the Commission preliminarily concluded that the mere 
posting of information on OASIS was insufficient. The Commission 
proposed that each transmission provider's OATT contain sufficient 
information about its credit process and requirements to enable 
customers to understand the information required to demonstrate 
creditworthiness and to determine for themselves the general amount and 
type of security they may need to provide in order to receive service. 
The Commission therefore proposed to amend section 11 of the pro forma 
OATT on creditworthiness to require each transmission provider to 
include its creditworthiness and security requirements in a new 
Attachment L to its OATT. Consistent with the Creditworthiness Policy 
Statement,\926\ the Commission proposed to require the new Attachment L 
to include such qualitative and quantitative criteria necessary to 
determine the level of secured and unsecured credit required, with 
supplementation in a credit guide or manual to be posted on OASIS.\927\ 
The Commission sought comment on whether the proposal is unduly 
burdensome.
---------------------------------------------------------------------------

    \926\ Policy Statement on Electric Creditworthiness, 109 FERC ] 
61,186 (2004) (Creditworthiness Policy Statement).
    \927\ The Commission proposed to require the new Attachment L to 
include the following elements: (1) A summary of the procedure for 
determining the level of secured and unsecured credit; (2) a list of 
the acceptable types of collateral/security; (3) a procedure for 
providing customers with reasonable notice of changes in credit 
levels and collateral requirements; (4) a procedure for providing 
customers, upon request, a written explanation for any change in 
credit levels or collateral requirements; (5) a reasonable 
opportunity to contest determinations of credit levels or collateral 
requirements; and (6) a reasonable opportunity to post additional 
collateral, including curing any non-creditworthy determination.
---------------------------------------------------------------------------

Comments
Included in Open Access Transmission Tariffs
    1637. Many commenters express support for the continuation of the 
current Commission policy which requires the inclusion in the 
transmission provider's OATT of only those rules, standards and 
practices that significantly affect transmission rates and 
services.\928\ These commenters generally state that any rule, 
practice, term or condition that could result in limiting access to 
transmission services, including rates and charges for service, should 
be included in the OATT and should be subject to Commission scrutiny. 
Examples given include all rules and practices affecting calculation of 
ATC, creditworthiness criteria, and rules or practices affecting the 
transmission provider's regional planning process. Commenters argue 
that Commission oversight is necessary to ensure that these rates, 
charges, rules, practices, terms or conditions of transmission service 
are reasonable and afford comparable treatment for wholesale customers.
---------------------------------------------------------------------------

    \928\ E.g., ISO/RTO Council, CAISO, LDWP, MISO/PJM States, PGP, 
and PNM-TNMP.
---------------------------------------------------------------------------

    1638. Other commenters advocate further inclusion of rules, 
standards and practices in the transmission provider's OATT. Morgan 
Stanley believes that business practices manuals should be incorporated 
into each OATT and filed with the Commission for approval. Morgan 
Stanley states that if this is not required then, at a minimum, each 
OATT should provide for a process to use when the transmission provider 
wishes to amend its business practices manuals. For example, 
transmission providers should provide notice to all affected parties of 
an intent to make a change, a mechanism to receive stakeholder feedback 
on the proposed change, and a minimum period of time between the final 
implementation decision and the effective date of the proposed change 
(e.g., 30-60 days after final decision). Southwestern Coop, however, 
maintains that transmission providers should not be allowed to change 
their rules, standards and practices that affect the justness and 
reasonableness of OATTs without prior Commission review. Southwestern 
Coop states that the Commission should require all rules, standards and 
practices relating to transmission services to be included in the OATT 
filed with the Commission, because otherwise it cannot ensure that 
jurisdictional rates are just and reasonable.
Posted on OASIS
    1639. Many commenters also express support for the proposed 
requirement that all rules, standards and practices that are not 
required to be included in a transmission provider's OATT and that 
affect a transmission provider's provision of transmission service be 
posted on OASIS.\929\ Commenters generally state that these postings 
will allow for increased transparency, while affording the transmission 
provider flexibility to make revisions rather than

[[Page 12476]]

having to amend the OATT each time a change occurs.
---------------------------------------------------------------------------

    \929\ E.g., CAISO, EEI, MidAmerican, MISO/PJM States, Nevada 
Companies, PJM, Powerex, Santa Clara, Suez Energy NA, TDU Systems, 
and TAPS.
---------------------------------------------------------------------------

    1640. Powerex argues that the transmission provider also should be 
required to post data used to calculate ATC, any metrics the Commission 
adopts regarding the transmission provider's performance of system 
impact and facilities studies, information concerning both planned and 
unplanned transmission outages, and a transmission provider's business 
practices, tariff, organizational charts and job descriptions of its 
employees.
    1641. Southern takes issue with the use in the NOPR of the phrase 
``all of their rules, standards and practices,'' stating that language 
suggests that a transmission provider might be required to reduce each 
detail of its business practices to writing, which could be overly 
burdensome. In addition, Southern believes that any rule relating to 
posting requirements on OASIS should have certain mechanisms to allow 
the transmission provider to deviate from posted practices when 
necessary. In contrast, ELCON states that any rule, standard or 
practice used by the transmission provider and any of its employees to 
approve or disapprove a request for service should be committed to 
writing and posted. Similarly, TranServ argues that transmission 
providers should be required to post on OASIS any criteria applied by 
the transmission provider to any attribute of a transmission or 
ancillary service request for the purpose of determining whether the 
service request should be approved or denied.
    1642. Northwest IOUs suggests that the Commission should adopt a 
``rule of reason'' test for matters required to be posted on the OASIS 
similar to the test applied to matters required to be included in the 
OATT.
Creditworthiness
    1643. Several commenters support the inclusion of a separate 
Attachment L to the pro forma OATT outlining creditworthiness 
requirements, asserting that Attachment L will standardize credit 
procedures and security requirements and increase transparency.\930\ 
Suez Energy NA states that the proposal is not unduly burdensome, that 
the procedures proposed are not different from the Creditworthiness 
Policy Statement or the procedures already imposed in individual cases, 
and that the Commission is merely proposing to apply an existing 
requirement in a non-discriminatory manner.
---------------------------------------------------------------------------

    \930\ E.g., APPA, East Texas Cooperatives, Lassen, MISO/PJM 
States, Nevada Companies, NRECA, PGP, Powerex, Southern, Suez Energy 
NA, TANC, and TAPS.
---------------------------------------------------------------------------

    1644. Other commenters propose modifications to the credit-related 
proposals set forth in the NOPR. TAPS urges the Commission to require 
the transmission provider to adopt a two-part creditworthiness 
assessment in order to facilitate non-burdensome and fair assessment of 
creditworthiness. TAPS recommends that a standard similar to the 
Florida Power Corp. OATT be applied, which provides that customers with 
``satisfactory long-term payment history'' and a minimum credit rating 
of Baa2 (Moody's) or BBB (S&P) would not have to post any credit 
security. If a customer fails to meet the threshold test, TAPS states 
that the transmission provider would perform a transparent credit 
assessment that is consistent with the Commission's Creditworthiness 
Policy Statement and the credit policies developed for use in regional 
transmission organizations such as MISO and SPP. According to TAPS, 
since quantitative measures sometimes understate public power 
creditworthiness, transmission providers will need to weigh qualitative 
factors more heavily than quantitative factors in assessing public 
power creditworthiness. For public entities that fail the threshold 
test, TAPS states that transmission providers should use outstanding 
bond indebtedness as a proxy for tangible net worth for those entities 
whose energy and transmission service payments receive priority over 
bond payments.
    1645. PJM generally agrees with the creditworthiness proposals, 
except for inclusion in the OATT of the actual detailed algorithms used 
to calculate credit scores, stating that those algorithms, as the 
Commission recognized,\931\ may change over time. In PJM's view, 
requiring all such changes to be approved by the Commission would be 
unnecessarily burdensome to both the Commission and the transmission 
provider. PJM recommends that the overall framework of the credit 
determinations be included in the OATT, while the detailed algorithms 
be posted on OASIS to meet transparency goals. PJM also recommends that 
the Commission accept, as an option, a regularly-updated posting on the 
transmission provider's Web site of each customer's available credit 
and collateral requirement as sufficient notification for most changes 
in credit available and credit requirements. PJM further recommends 
that only significant and sudden reductions in credit available (for 
example, those greater than 25 percent within a one-month period) be 
subject to an active notification requirement.
---------------------------------------------------------------------------

    \931\ See NOPR at P 456.
---------------------------------------------------------------------------

    1646. TVA recommends the Commission consider two fundamental 
principles as it standardizes creditworthiness terms and conditions. 
First, as long as qualitative factors are part of the equation (and TVA 
agrees that they should be), TVA states that certain subjective 
judgments by the transmission provider will be required. TVA encourages 
the Commission to provide guidance on appropriate criteria to consider 
in making these judgments, but not to remove entirely from the process 
the flexibility necessary for individual assessments of customer 
creditworthiness. Second, TVA states that transmission providers may 
have to impose different security requirements as a result of 
differences in statutes, regulations, or other legal requirements. For 
example, TVA states that its ability to incur debt is limited by 
section 15d(a) of the Tennessee Valley Authority Act \932\ and, 
therefore, it may need to impose security requirements that are 
stricter than those of a public utility, as the Commission has 
previously recognized.\933\ TVA requests that the final rule respect 
these differing legal obligations and provide corresponding flexibility 
in credit decisions among transmission providers.
---------------------------------------------------------------------------

    \932\ 16 U.S.C. 831n-4.
    \933\ Citing East Ky. Power Coop., Inc., 114 FERC ] 61,035 at P 
56 (2006).
---------------------------------------------------------------------------

    1647. A number of commenters oppose the Commission's proposed 
creditworthiness policy.\934\ In general, these commenters believe that 
each transmission provider should have the flexibility to make and 
change creditworthiness procedures without the delay of obtaining 
Commission approval. They also argue that the Commission's goal of 
transparency could be better achieved by requiring the posting of a 
transmission provider's creditworthiness policy on OASIS.\935\ Xcel and 
MidAmerican assert that the Commission's proposal would decrease a 
transmission provider's ability to timely respond to changing market 
and financial conditions and, therefore, creditworthiness and security 
requirements should simply be posted on OASIS. Southern believes that 
the Commission should permit but not require transmission providers to 
file their creditworthiness and security procedures as part of their 
OATTs.\936\

[[Page 12477]]

Southern also asks that the Commission allow a transmission provider, 
in its compliance filing, to request a determination that its current 
creditworthiness policies and practices are acceptable under the new 
Commission policies. Similarly, ISO-New England states that this 
rulemaking should not modify the ISO-New England Financial Assurance 
and Billing Policies, which are already on file with the Commission.
---------------------------------------------------------------------------

    \934\ E.g., MidAmerican, Southern, PNM-TNMP, NorthWestern, and 
Xcel.
    \935\ E.g., PNM-TNMP, EEI, and MidAmerican.
    \936\ Southern states that it already includes creditworthiness 
and security requirements in its OATT since the Commission issued 
its Creditworthiness Policy Statement.
---------------------------------------------------------------------------

    1648. CAISO states that although the NOPR requirements concerning 
credit and security requirements do not appear unduly burdensome, it is 
concerned that the Commission may apply these requirements in a manner 
that will impose an undue burden on transmission providers and 
effectively eliminate the ability of transmission providers to 
supplement basic elements with a credit guide or manual. CAISO and 
MidAmerican further state that there is no legitimate reason to treat 
credit policies and procedures any differently than the other rules, 
practices and standards that the Commission permits to be included on 
OASIS and does not require to be filed as part of the tariff. Santa 
Clara recommends that if the Commission decides to require 
creditworthiness and security policies to be posted on OASIS rather 
than included in the OATT, then it should require at least a 30-day 
notice period for changes in the credit policies.
Commission Determination
    1649. The Commission adopts the NOPR proposal to continue to 
require only those rules, standards, and practices that significantly 
affect transmission service be incorporated into a transmission 
provider's OATT. The Commission further affirms the use of a ``rule of 
reason'' to determine what rules, standards, and practices 
significantly affect transmission service and, as a result, must be 
included in the transmission provider's OATT.
    1650. The ``rule of reason'' test has arisen primarily with respect 
to protocols or operating procedures used by RTOs and ISOs. For 
example, the Commission has held that, while MISO's business practices 
manuals implicate the Commission's jurisdiction because they generally 
involve ``the installation, operation, or use of facilities for the 
transmission or delivery of power in interstate commerce,'' they do not 
require an FPA section 205 filing because ``they mostly involve general 
operating procedures.'' In other cases, the facts have required the 
filing of the rule, standard or practice. For example, CAISO proposed 
to post certain technical, operational and business standards related 
to dynamic scheduling on its Web site and include only the rates under 
its OATT. In that instance, the Commission found that the details 
contained in the standards were practices that could significantly 
affect the terms and conditions of service and, therefore, under the 
Commission's ``rule of reason'' must be filed under section 205 of the 
FPA.\937\
---------------------------------------------------------------------------

    \937\ California Independent System Operator Corp., 107 FERC ] 
61,329 at P 21-22 (2004); see also Southwest Power Pool, Inc., 112 
FERC ] 61,303 at P 25 (requiring that the SPP OATT provide 
sufficient information for market participants to fully understand 
SPP's implementation of an imbalance market), reh'g denied, 113 FERC 
] 61,115 (2005); PJM Interconnection, L.L.C., 104 FERC ] 61,124 at P 
61 (requiring PJM to place all procedures, standards and 
requirements for proposing that a transmission owner construct a 
specific upgrade, and all procedures for charging customers, in its 
tariff, not in its manuals), order on reh'g, PJM Interconnection, 
L.L.C., 105 FERC ] 61,123 (2003).
---------------------------------------------------------------------------

    1651. Comments received in response to the NOPR confirm that there 
is broad support for the Commission's existing practice, requiring only 
those rules, standards, and practices that significantly affect 
transmission service, and the use of the ``rule of reason'' test to 
identify those rules, standards, and practices. The Commission 
disagrees with parties arguing that all of a transmission provider's 
rules, standards, and practices should be incorporated into its OATT. 
We believe that requiring transmission providers to file all of their 
rules, standards and practices in their OATTs would be impractical and 
potentially administratively burdensome.
    1652. The Commission instead requires transmission providers to 
post on their public Web sites all rules, standards, and practices that 
relate to transmission service and provide a link to those rules, 
standards, and practices on OASIS. We conclude that it would not be 
appropriate to place the rules, standards, and practices only on OASIS 
as some transmission providers use certificates to restrict access to 
their OASIS sites. By providing a link on OASIS to the rules, 
standards, and practices that are otherwise publicly posted, the 
Commission ensures that all potential customers will have access to the 
information necessary for them to understand the terms and conditions 
of service. We amend section 4 of the pro forma OATT to expressly 
establish this posting requirement.
    1653. We note that we already require certain rules and practices 
to be posted on OASIS.\938\ We find that it is now necessary to also 
require that all rules, standards or business practices that relate to 
the terms and conditions of transmission service, and how that 
transmission service is provided to customers, to be detailed, clearly 
stated on the transmission provider's public Web site, with a link to 
this information on OASIS.\939\ We emphasize that this requirement 
applies to all such rules, standards, and practices, currently written 
or otherwise.\940\ While we acknowledge this requirement will result in 
some burden to transmission providers, we find that this approach is 
necessary to provide greater transparency and mitigate the potential 
for undue discrimination against customers taking service under the 
transmission provider's OATT. Further, our holding is not intended to 
eliminate all discretion under the pro forma OATT; rather, we recognize 
that certain tariff provisions require consideration of the specific 
facts and circumstances related to particular service requests.\941\ We 
merely require that, if the transmission provider uses standards, rules 
or business practices to administer its OATT, such standards, rules or 
business practices must be available for public inspection. Moreover, 
we note that our actions here are consistent with actions we have taken 
in recent proceedings. For example, the Commission has required that 
certain business practices manuals be posted

[[Page 12478]]

and made available for public view on a permanent basis.\942\ As in 
those cases, we find that making rules, standards, and practices 
readily accessible will serve as a tool to supplement each transmission 
provider's OATT and facilitate fair and open access to the transmission 
grid.
---------------------------------------------------------------------------

    \938\ See, e.g., Order No. 889 at 31,588-89; Open Access Same-
Time Information Systems, Order No. 605, 64 FR 34117 (Jun. 25, 
1999), FERC Stats. and Regs. ] 31,075 (1999); Order No. 676 at P 79.
    \939\ If a particular rule, standard or practice conflicts with 
an OATT provision, the OATT of course shall govern in all 
circumstances. Moreover, as noted in the NOPR, we emphasize that 
posting rules, practices and standards--in lieu of filing such 
practices with the Commission as part of the transmission provider's 
pro forma OATT--neither insulates a transmission provider from 
complaints nor confers a just and reasonable presumption. We 
encourage customers to call the Commission's Enforcement Hotline 
with complaints about the application of such rules, standards and 
practices should they experience problems with their transmission 
providers. To the extent customers are not satisfied with responses 
from their transmission provider, they should contact the 
Commission's Enforcement Hotline via telephone (202) 502-8390, toll-
free 1-888-889-8030, fax (202) 208-0057, or at http://www.ferc.gov/cust-protect/enforce-hot.asp
.

    \940\ With respect to the business practices developed by NAESB, 
there may be certain copyright restrictions that limit the 
transmission provider's ability to post those practices on its own 
Web site. In such instances, we expect that the transmission 
provider will reference any NAESB practices it uses and provide a 
link on its public Web site to the NAESB Web site in order to 
provide interested parties with a means to access the copyrighted 
material.
    \941\ The circumstances and manner in which a transmission 
provider exercises its discretion under its OATT must be posted in 
accordance with 18 CFR 37.6(4).
    \942\ See, e.g., Midwest Independent Transmission System 
Operator, Inc., 108 FERC ] 61,163 at P 658, order on reh'g, 109 FERC 
] 61,157 (2004), order on reh'g, 111 FERC ] 61,043, order on reh'g, 
112 FERC ] 61,086 (2005); see also PJM Interconnection, L.L.C., 81 
FERC ] 61,257 at 62,267 (1997) (finding no reason to require filing 
of the PJM Manuals but requiring that such manuals be available for 
public inspection on a permanent basis), order on reh'g, 92 FERC ] 
61,282 (2000).
---------------------------------------------------------------------------

    1654. To provide guidance to the transmission providers as to 
whether a particular rule, standard, or practice ``relates to'' 
transmission service, and therefore warrants posting, the Commission 
believes the MAPP Policies and Procedures for Transmission Operations 
manual is a good example of the type of information that relates to the 
terms and conditions of transmission service. For example, the MAPP 
manual sets forth information supplementing its OATT pertaining to (1) 
transmission service requests on the MAPP OASIS site, (2) the 
retraction of an accepted or counteroffer transmission request, (3) 
timing requirements for transmission service requests, (4) methods to 
accommodate a firm transmission request with redispatch, and (5) 
transmission service charge implementation procedures. Other examples 
include detailed information regarding tagging, scheduling, billing and 
other matters provided in other RTO manuals. This is the type of 
information that clearly relates to transmission service and therefore 
must be reduced to writing and publicly posted.
    1655. We also agree with requests to require a transparent process 
for amending rules, standards, and practices previously posted by a 
transmission provider. We therefore require each transmission provider 
also post on its public Web site (with a corresponding link on OASIS) a 
statement of the process by which the transmission provider will amend 
these rules, standards, and practices that are accessible via OASIS. As 
part of this process, the transmission provider must specify a 
mechanism to provide reasonable notice of any proposed changes to a 
posted business practice and the respective effective date of such 
change.\943\ We amend section 4 of the pro forma OATT to formalize this 
posting requirement and obligate transmission providers to follow the 
amendment procedures specified by the transmission provider. As with 
the requirement to post the underlying standards, rules and practices, 
we believe the amendment procedures required here will increase 
transparency and help minimize opportunities for undue discrimination.
---------------------------------------------------------------------------

    \943\ As part of their business practice amendment procedures, 
transmission providers may adopt such additional procedures they 
deem appropriate, such as opportunities for comment to proposed 
changes to rules, standards, and practices.
---------------------------------------------------------------------------

    1656. The Commission also adopts the NOPR proposal and amend the 
pro forma OATT to include a new Attachment L.\944\ We find that the 
transmission provider's basic credit standards significantly affect 
transmission service and, therefore, must be included in the pro forma 
OATT. This will ensure that all customers have clear information as to 
the credit process and standards used by a transmission provider to 
grant or deny transmission service and, in turn, will serve to prevent 
undue discrimination and eliminate a potentially significant barrier to 
entry in the provision of service. Most importantly, by making 
Attachment L a part of the pro forma OATT, customers will have an 
opportunity to comment on any changes to the standards proposed by a 
transmission provider in a rate filing with the Commission.
---------------------------------------------------------------------------

    \944\ As with new Attachment K to the pro forma OATT, regarding 
transmission planning, we acknowledge that some transmission 
providers may already have attachments to their OATTs labeled with 
the letter ``L,'' in which case transmission providers are free to 
label their credit procedures OATT attachment with the next 
available letter.
---------------------------------------------------------------------------

    1657. To that end, each transmission provider's Attachment L must 
specify the qualitative and quantitative criteria that the transmission 
provider uses to determine the level of secured and unsecured credit 
required. Attachment L must also contain the following elements: (1) A 
summary of the procedure for determining the level of secured and 
unsecured credit; (2) a list of the acceptable types of collateral/
security; (3) a procedure for providing customers with reasonable 
notice of changes in credit levels and collateral requirements; (4) a 
procedure for providing customers, upon request, a written explanation 
for any change in credit levels or collateral requirements; (5) a 
reasonable opportunity to contest determinations of credit levels or 
collateral requirements; and (6) a reasonable opportunity to post 
additional collateral, including curing any non-creditworthy 
determination. We will allow the transmission provider to supplement 
Attachment L with a credit guide or manual to be posted on OASIS.
    1658. We disagree with commenters that claim requiring this 
information in an attachment to each transmission provider's OATT will 
hinder the transmission provider's ability to timely respond to 
changing market and financial conditions. Because Attachment L requires 
only a summary of credit requirements and other information, we expect 
the need to revise Attachment L will occur infrequently. As suggested 
by PJM, detailed information, such as the algorithms used by the 
transmission provider to determine credit scores, can be posted on 
OASIS along with other information that relates to the provision of 
transmission service. Thus, the requirement we are imposing should not 
be overly burdensome.
    1659. At the same time, we agree that transmission providers need 
flexibility in determining credit requirements in light of qualitative 
and quantitative factors, as we recognized in the NOPR and the 
Creditworthiness Policy Statement. We believe the requirements adopted 
in this Final Rule allow for such flexibility. By requiring 
transmission providers to consider both quantitative and qualitative 
factors, the particular circumstances surrounding public power entities 
can be recognized. We agree, moreover, with TVA that the transmission 
provider's credit policies must be consistent with its legal 
obligations and expect that interested parties will bring any legal 
conflicts to our attention on review of the transmission provider's 
compliance filing.
    1660. With regard to requests to find existing credit policies 
consistent with the requirements of the Final Rule, all transmission 
providers will be required to demonstrate compliance with all aspects 
of the Final Rule either by implementing the reforms adopted today or 
showing that departures are consistent with or superior to the terms 
and conditions of the pro forma OATT, as modified by this Final Rule. 
The procedural mechanisms for making such a showing provided for in 
section IV.C above give transmission providers the opportunity to 
demonstrate that retention of their existing credit practices is 
appropriate.
    1661. Finally, with regard to Santa Clara's request to require the 
transmission provider to provide at least a 30-day notice period for 
changes in creditworthiness and security policies that are posted on 
OASIS, we explain above that each transmission provider must identify 
and incorporate a specific process in its OATT for amending business 
practices that are posted on OASIS. Such practices include those

[[Page 12479]]

that describe and implement its creditworthiness and security policies.
b. Liability and Indemnification
    1662. In Order No. 888, the only liability provisions included in 
the pro forma OATT related to force majeure and indemnification.\945\ 
Section 10.1 of the pro forma OATT provides that neither the 
transmission provider nor the transmission customer will be considered 
in default as to any obligation under the tariff if prevented from 
fulfilling the obligation due to an event of force majeure. A party 
whose performance under the tariff is hindered by an event of force 
majeure, however, is required to make all reasonable efforts to perform 
its obligations under the tariff. With respect to indemnification, 
under section 10.2 of the pro forma OATT, the transmission customer 
indemnifies the transmission provider against third party claims 
arising from the transmission provider's performance of its obligations 
under tariff on behalf of the transmission customer, except in cases of 
negligence or intentional wrongdoing by the transmission provider.
---------------------------------------------------------------------------

    \945\ Order No. 888-B at 62,081
---------------------------------------------------------------------------

(1) Force Majeure
Comments
    1663. Santa Clara queries whether the Commission intended to make 
the transmission provider's performance of its obligations less 
burdensome by using the phrase ``all reasonable efforts'' instead of 
``due diligence'' in the force majeure provision in section 10.1 of the 
pro forma OATT is. In either case, Santa Clara requests the Commission 
to consider the use of the most stringent term when addressing a 
transmission provider's obligation to perform under its tariff.
Commission Determination
    1664. The Final Rule retains the current ``all reasonable efforts'' 
standard in the force majeure provision. Santa Clara does not explain 
how the ``all reasonable efforts'' standard may be more or less 
stringent than the ``due diligence'' standard. Further, as the 
Commission explained in Order No. 888, this protection against 
unexpected and unpredictable events is appropriately made available to 
both the transmission provider and transmission customer. We therefore 
find that the clarification requested by Santa Clara is unnecessary.
(2) Indemnification/Limitation of Liability
Comments
    1665. Several commenters \946\ urge the Commission to change the 
indemnification provision to protect transmission providers from 
liability except in the case of gross negligence or intentional 
misconduct, thereby exempting the transmission provider from liability 
for acts of ordinary negligence. These commenters also request that the 
Commission add to the pro forma OATT a new provision clarifying that 
the transmission provider would not be liable to any transmission 
customer or third party for direct, incidental, consequential, 
indirect, or punitive damages arising from services provided under the 
tariff, except in cases of gross negligence or intentional misconduct 
(in which case, EEI, and Northwest IOUs propose, liability would be 
limited to direct damages). These commenters note that the Commission 
has allowed transmission providers this protection in the tariffs of 
MISO, PJM, ISO New England, SPP, and their member transmission owners 
and generators, but it has not fully explained its basis for treating 
non-RTO member transmission providers differently from RTOs and ISOs. 
EEI further notes that the Commission accepted similar liability 
protection in the Large Generator Interconnection Agreement (``LGIA'') 
and in natural gas pipeline tariffs.\947\ EEI requests that this 
liability limitation be added to the pro forma transmission service 
agreement that would apply to transmission customers acting in good 
faith to carry out the directives of a transmission provider.
---------------------------------------------------------------------------

    \946\ E.g., Southern, EEI, and Northwest IOUs.
    \947\ Citing Article 18, Large Generator Interconnection 
Agreement; ANR Pipeline Co., 98 FERC ] 61,218, order on tariff 
filing, 100 FERC ] 61,132 (2002).
---------------------------------------------------------------------------

    1666. With respect to third party indemnification, EEI notes that 
the Commission reasoned in SPP that, even though a broader liability 
limitation would relieve a transmission provider from liability for 
ordinary negligence, that provision only applies to transmission 
customers under the tariff. EEI states that there are many other 
entities that could initiate legal action against the transmission 
provider in connection with the provision of transmission service, 
thereby making an adequate indemnification provision in the pro forma 
OATT necessary for the same reasons as the limited liability 
provision.\948\
---------------------------------------------------------------------------

    \948\ Citing Southwest Power Pool, Inc., 112 FERC ] 61,100 at P 
39 (2005).
---------------------------------------------------------------------------

    1667. EEI contends that the addition of the Commission's new EPAct 
2005 authority to establish mandatory reliability standards to provide 
open access transmission service to all customers, regardless of their 
risk profile, makes it an appropriate time to revisit the liability 
provisions in the OATT. According to EEI, a limitation on liability in 
the pro forma OATT should be viewed as a necessary element of the 
implementation of the Commission's reliability authority. Because 
transmission providers cannot deny service to particular customers 
based on the risk of potential damages, EEI and Southern assert that 
all transmission providers should be protected from certain risks 
associated with this obligation to serve. EEI argues that increased 
protection from liability would lower the cost of capital for new 
transmission projects and promote the expansion of transmission 
infrastructure. EEI further argues that the technological complexity of 
modern utility systems and the potential for service interruptions 
unrelated to human errors justify liability limitations. According to 
EEI, a limitation on liability to direct damages puts the risk on those 
customers with special reliability needs, rather than spreading the 
risk among all customers.
    1668. EEI notes that the Commission has denied requests for 
exemptions from liability for ordinary negligence in the 
indemnification provision on the grounds that liability and 
indemnification were ``separate issue[s]'' and that transmission 
providers seeking liability protections could rely on state laws.\949\ 
EEI argues, however, that an OATT and the accompanying service 
agreement constitute a contract between the transmission provider and 
the customer that is established pursuant to federal law and, as a 
result, it is not at all clear that a state law limitation on liability 
would apply. Southern asserts that adopting liability limits would 
provide uniformity, certainty, and reduce risk since reliance on state 
law is an issue not free from doubt.
---------------------------------------------------------------------------

    \949\ Citing Order No. 888-A at 30,301.
---------------------------------------------------------------------------

    1669. Entegra argues on reply that the NOPR did not contemplate any 
modification to these provisions of the pro forma OATT and neither EEI 
nor Southern has established a nexus between such a modification and 
the goals set forth in the NOPR. TDU Systems on reply similarly argue 
that EEI's request is outside the scope of the rulemaking and neither 
EEI nor Southern show a change in circumstance justifying a new 
limitation

[[Page 12480]]

on liability. Immunizing transmission providers from these liability 
risks, TDU Systems contend, would simply transfer risk to customers 
that have no control over the transmission provider's negligence. 
Entegra and TDU Systems further argue that Southern previously sought 
the same relief in a tariff filing rejected by the Commission less than 
a year ago, stating that the Commission thus already rejected the 
notion that Southern was similarly situated to the RTOs and ISOs that 
have this protection.\950\ Entegra notes that Southern did not seek 
rehearing of that order and its comments here are therefore an 
impermissible collateral attack on a final Commission order. As for the 
argument regarding EPAct 2005, TDU Systems note that the Commission 
presumably was aware of its new reliability authorities when it issued 
the Southern order four months after EPAct was enacted.
---------------------------------------------------------------------------

    \950\ See Entegra Reply (citing Southern Company Services, Inc., 
113 FERC ]61,239 (2005)).
---------------------------------------------------------------------------

    1670. TDU Systems also point out that the tariff language proposed 
by EEI would not protect a transmission customer from being sued by a 
third party for the negligence or willful misconduct of the 
transmission provider. In such lawsuits, TDU Systems claim, a third 
party would not be limited to direct damages. According to TDU systems, 
any indemnification as between the transmission provider and the 
transmission customer that is limited to direct damages would leave the 
customer holding the bag for the indirect damages caused by the 
transmission provider's negligence or willful misconduct.
Commission Determination
    1671. We will retain the current liability protections in the pro 
forma OATT for the same reasons that the Commission has rejected 
similar past proposals. While the Commission explained in Order Nos. 
888-A and 888-B that the pro forma tariff was not intended to address 
liability issues, as EEI notes, the Commission stated that liability 
was a separate issue from indemnification.\951\ The Commission further 
explained that transmission providers were not precluded from relying 
on state laws that protected utilities or others from claims founded in 
ordinary negligence.\952\ The Commission declined to adopt a uniform 
federal liability standard and decided that, while it was appropriate 
to protect the transmission provider through force majeure and 
indemnification provisions from damages or liability when service is 
provided by the transmission provider without negligence, it would 
leave the determination of liability in other instances to other 
proceedings.\953\
---------------------------------------------------------------------------

    \951\ See Order No. 888-A at 30,301 and Order No. 888-B at 
62,081 (section 10.2 of the pro forma OATT).
    \952\ Order No. 888-A at 30,301.
    \953\ Order No. 888-B at 62,081.
---------------------------------------------------------------------------

    1672. On the issue of a negligence standard for the indemnification 
provision, we decline to depart from our policy set forth in Order No. 
888, as affirmed in Order No. 888-A and subsequent orders.\954\ In 
Order No. 888, the Commission stated:
---------------------------------------------------------------------------

    \954\ See, e.g., Northeast Utilities Services Co., 111 FERC ] 
61,333 (2005) (Northeast Utilities).

    We have limited the indemnification portion of the provision so 
that it is now only the transmission customer who indemnifies the 
transmission provider from the claims of third parties. The customer 
is taking service from the transmission provider and may 
appropriately be asked to bear the risks of third-party suits 
arising from the provision of service to the customer under the 
tariff. We find that this new indemnification provision would be too 
strict if it required customers to indemnify transmission providers 
even in cases where the transmission provider is negligent. 
Accordingly, the revised provision provides that the customer will 
not be required to indemnify the transmission provider in the case 
of negligence or intentional wrongdoing by the transmission 
provider.\955\
---------------------------------------------------------------------------

    \955\ Order No. 888 at 31,765.

    1673. The Commission subsequently addressed this issue in Northeast 
Utilities. There, the Commission found that a broader customer 
indemnification obligation that would include ordinary negligence would 
not give any incentive to the transmission provider to avoid negligent 
actions. In Northeast Utilities, the Commission explained again why it 
permitted a gross negligence exception in the pro forma LGIA section 
18.1 in order to further limit the transmission provider's liability. 
As the Commission explained in Order No. 2003, interconnection warrants 
a different standard because it presents a greater risk of liability 
than exists for the provision of transmission service. The Commission 
further found that because risk exposure can increase interconnection 
costs, a broader indemnity standard is appropriate in the 
interconnection context.\956\
---------------------------------------------------------------------------

    \956\ Order No. 2003 at P 636; Order No. 2003-A at 31,162.
---------------------------------------------------------------------------

    1674. Further, unlike Order No. 888 in which the transmission 
customer indemnifies the transmission provider, in Order No. 2003 the 
indemnity provision is expressly bilateral. In Order No. 2003 the 
interconnecting generator and the transmission provider each 
indemnifies the other from all damages to third parties arising under 
the LGIA from conduct on behalf of the indemnifying party, except in 
cases of gross negligence. Given that the indemnification provision in 
the pro forma LGIA is bilateral, in contrast to the pro forma OATT, it 
is reasonable to permit a gross negligence standard in the case of an 
interconnection.
    1675. We also reject commenters' assertions that the liability 
standard the Commission has approved for RTOs/ISOs and gas pipelines is 
appropriate for other transmission providers. In the Reliability Policy 
Statement,\957\ the Commission stated that it would consider, on a 
case-by-case basis, proposals by public utilities to amend their OATTs 
to include limitations on liability. The Commission further noted that 
while this issue has not been resolved on a standardized basis, the 
Commission has entertained RTO transmission providers' specific 
proposals to amend their OATTs to include provisions addressing 
limitations on liability.\958\
---------------------------------------------------------------------------

    \957\ Policy Statement on Matters Related to Bulk Power System 
Reliability, 107 FERC ] 61,052 (2004) (Reliability Policy 
Statement).
    \958\ Reliability Policy Statement at P 40 (citations omitted).
---------------------------------------------------------------------------

    1676. In subsequent orders, the Commission found that the gross 
negligence and intentional wrongdoing indemnification and liability 
standard is appropriate for RTOs and ISOs. However, the Commission has 
declined to extend this protection to all transmission providers. In 
Southwest Power Pool, Inc., the Commission explicitly stated ``that our 
acceptance here of the gross negligence and intentional wrongdoing 
indemnity standard is limited to SPP, in its role as an RTO, and its 
TOs; we do not intend to extend such protection to all transmission 
providers.'' \959\ In Southern Company Services, Inc., the Commission 
stated that:
---------------------------------------------------------------------------

    \959\ 112 FERC ] 61,100 at P 39 (2005).

    Having considered Southern Companies' proposed limitation on 
liability and indemnification provisions pursuant to our Reliability 
Policy Statement cited above, we find that Southern Companies have 
not shown that they are similarly situated to the RTOs/ISOs they 
cite in support. While Southern Companies claim that they ``may not 
be protected by any State-regulated limitations on liability,'' 
Southern Companies offer no evidence to support this concern. The 
Commission has provided such liability protection to RTOs/ISOs 
because they were created by and solely regulated by the Commission, 
and otherwise would be without limitations on liability. Southern 
Companies have proffered no evidence of any

[[Page 12481]]

change in circumstances vis-[agrave]-vis their liability exposure 
post-Order No. 888.\960\
---------------------------------------------------------------------------

    \960\ 113 FERC ] 61,239 at P 7 (2005).

    1677. Commenters offer no new arguments that demonstrate that they 
are unable to rely on state laws, i.e., the state laws provide 
inadequate protection. While EEI and Southern assert that there is 
uncertainty in whether state law on liability would apply to a service 
agreement between a transmission provider and a transmission customer, 
we note that neither provide any evidence that transmission providers 
are actually precluded from relying on state law for liability 
protection. EEI and Southern thus fail to show that the potential for a 
legal and regulatory gap is so great as to warrant inclusion of 
liability protections in the pro forma OATT for all transmission 
providers. In this regard, the Commission also finds without merit 
assertions that increased liability protections in the pro forma OATT 
should be viewed as a necessary element of the implementation of the 
Commission's reliability authority. As none of the arguments proffered 
by commenters persuade us to change our policy regarding liability 
protections applicable to non-RTO and non-ISO transmission providers, 
we decline to modify the liability protections in the pro forma OATT.
10. OATT Definitions
    1678. In order to support the reforms adopted in this Final Rule 
and otherwise clarify the requirements of the pro forma OATT, the 
Commission adds and amends various definitions in the pro forma OATT, 
as set forth below.
a. Affiliate
NOPR Proposal
    1679. In the NOPR, the Commission proposed a new definition of 
Affiliate incident to the proposed change to the pricing of reassigned 
capacity.
Comments
    1680. Some commenters request clarification that the proposed 
definition of Affiliate would not apply to transmission-only 
cooperatives or independent entities such as RTOs. NRECA asserts that 
in Order No. 2004-A, the Commission concluded that ``[g]eneration and 
transmission cooperatives (G&T) are not subject to the Standards of 
Conduct consistent with the policies established under Order No. 888.'' 
NRECA asks for confirmation that distribution and generation and 
transmission cooperatives will not be considered affiliates of each 
other for OATT and Standards of Conduct purposes because recent 
pleadings reveal that there continues to be confusion about this 
definition. TranServ asks for clarification of the application of the 
definition of ``affiliate'' with respect to a merchant affiliate of a 
transmission provider that has turned over tariff administration 
functions to an ISO, RTO, or other independent entity. PNM-TNMP 
suggests that the definition of Affiliate be expanded or clarified to 
encompass divisions of an entity that operate as a functional unit. 
PNM-TNMP asserts that such a change would make clear that an Affiliate 
includes not only separate legal entities, but also may apply to 
divisions and functional units within the entity.
Commission Determination
    1681. As discussed in section V.C.4, the Commission lifts the price 
cap on reassigned transmission capacity for all transmission customers, 
regardless of affiliation with the transmission provider. It is 
therefore no longer necessary to define an affiliate for purposes of 
that provision. The Commission nonetheless adopts the proposed 
definition of Affiliate to implement the reforms associated with 
distribution of operational penalties discussed in section V.C.5.b.
    1682. With regard to the request that we clarify that an Affiliate 
does not apply to transmission-only cooperatives, we agree with NRECA 
that the Commission made clear in Order No. 888-A that there was no 
corporate affiliation between G&T cooperatives and their member 
distribution cooperatives.\961\
---------------------------------------------------------------------------

    \961\ Order No. 888-A at 30,286 and 30,366.
---------------------------------------------------------------------------

    1683. TranServ requests clarification regarding the use of the term 
``affiliate'' in the context of a transmission owner that has turned 
over operational control of its transmission facilities to an RTO, ISO, 
or to an independent entity. We clarify that, for purposes of the 
distribution of penalties, if such transmission owner is not required 
to be a transmission provider under a Commission-approved tariff, the 
merchant affiliate of such transmission owner would not be considered 
to be an ``affiliate'' of the RTO, ISO, or independent entity under the 
definition adopted in this Final Rule. The affiliation of a merchant to 
a transmission owner does not establish an affiliation between such 
merchant and the RTO, ISO, or independent entity transmission provider.
    1684. As to PNM-TNMP's request that the definition of ``affiliate'' 
be expanded or clarified to encompass divisions of an entity that 
operate as a functional unit, we note that PNM-TNMP's concern appears 
to have been raised in the context of lifting the price cap for 
capacity reassignment, initially proposed only for non-affiliated 
transmission customers. We believe we have addressed PNM-TNMP's 
concerns by lifting the price cap for capacity reassignment for all 
customers, including affiliates of the transmission provider and the 
transmission provider's merchant function.
b. Good Utility Practice
NOPR Proposal
    1685. In the NOPR, the Commission proposed to incorporate the 
definition of reliable operation from FPA section 215 in the definition 
of Good Utility Practice in the pro forma OATT.
Comments
    1686. No commenters oppose the Commission's proposal to modify the 
definition of Good Utility Practice to reference the reliable operation 
standard of FPA section 215.
Commission Determination
    1687. The Commission adopts the NOPR proposal to incorporate the 
definition of reliable operation from FPA section 215 in the definition 
of Good Utility Practice in the pro forma OATT. FPA section 215(b) 
obligates all users, owners and operators of the bulk power system to 
comply with reliability standards that will take effect under that 
section. Referencing section 215 in the definition of Good Utility 
Practice is appropriate to ensure that the reliability standards 
ultimately developed by the ERO and approved by the Commission are 
reflected in the pro forma OATT.
c. Non-Firm Sales
NOPR Proposal
    1688. The Commission proposed to add a definition for Non-Firm 
Sales to clarify the treatment of such sales under section 30.4 of the 
pro forma OATT.\962\ The Commission proposed defining a Non-Firm Sale 
as ``an energy sale for which delivery or receipt of the energy may be 
interrupted for any reason or for no reason, without liability on the 
part of either the buyer or seller.'' The Commission also proposed to 
clarify that, for the purposes of applying

[[Page 12482]]

section 30.4, energy sales that can only be interrupted to maintain 
system reliability would be considered firm sales.
---------------------------------------------------------------------------

    \962\ Section 30.4 as proposed in the NOPR provides, in relevant 
part, that ``[t]he Network Customer shall not operate its designated 
Network Resources located in the Network Customer's or the 
Transmission Customer's Control Area such that the output of those 
facilities exceeds its designated Network Load, plus Non-Firm Sales 
delivered pursuant to Part II of the Tariff, plus losses.''
---------------------------------------------------------------------------

Comments
    1689. Several commenters argue that the proposed definition of Non-
Firm Sales could impede a network customer's ability to obtain 
transmission service for certain types of energy products. In 
particular, Duke, EEI, and Southern question the treatment of power 
purchase agreements with LD provisions under the proposed definition. 
Duke contends that a contract with an LD provision might be 
interruptible for any reason, but it would still provide for liability 
in the form of LD payments. As a result, the LD contract might not fall 
within the definition of a Non-Firm Sale. At the same time, network 
customers can only designate resources from system purchases not linked 
to a specific generating unit if the purchase power agreement is not 
interruptible for economic reasons, does not excuse seller performance 
for economic reasons, and requires the network customer to pay for the 
purchase.
    1690. Commenters are thus concerned that some contracts with LD 
provisions may be too firm to be a Non-Firm Sale, but not firm enough 
to be designated as a network resource. Duke argues that network 
customers should be allowed to operate their Network Resources to both 
serve load and sell a firm LD product. EEI is concerned that the 
proposed definition of Non-Firm Sales would prohibit a network customer 
from making an off-system sale of a firm LD product or any other 
product that does not result in undesignation of a Network Resource, 
given the restrictions set forth in section 30.4. Duke and EEI 
therefore propose that a Non-Firm Sale should be defined as any sale 
that is not sufficiently firm to be designated a Network Resource of 
the purchasing entity. Raising concerns similar to those raised by Duke 
and EEI, Southern proposes to define Non-Firm Sales as any sale that 
does not commit the associated resource to a third party and otherwise 
keeps the resource available for network service on a non-interruptible 
basis.
    1691. NRECA, however, argues that contracts with LD provisions are 
typically considered firm products, so long as they cannot be curtailed 
for economic reasons alone. NRECA requests that the Commission confirm 
its understanding that the mere inclusion of an LD provision in a 
contract does not make the sale non-firm, provided that the sale cannot 
be curtailed only for economic reasons.
Commission Determination
    1692. The Commission adopts the proposed definition of a Non-Firm 
Sale and incorporates that defined term in section 30.4 of the pro 
forma OATT. Network customers may use network resources for third party 
sales only if the sale is on a non-firm basis. This ensures that the 
network resource is available to serve the network load on an 
uninterruptible basis. We conclude that it would be inappropriate, as 
some commenters suggest, to relax the definition of a Non-Firm Sale to 
include any sale that is not otherwise firm enough to be designated as 
a network resource. We address the requirements for designation of 
network resources in section V.D.6, concluding that not all contracts 
with LD provisions are sufficiently firm to be eligible for 
designation. There we explain that only LD provisions that provide for 
``make whole'' remedies are sufficiently firm to be designated as 
network resources. It does not follow, however, that all remaining 
contracts with LD provisions are non-firm. The very existence of an LD 
provision indicates that interruption of service will result in 
liability and, thus, such contracts cannot automatically be considered 
Non-Firm Sales for purposes of section 30.4. To allow otherwise would 
create conflicting incentives for the network customer.
d. Pre-Confirmed Application
NOPR Proposal
    1693. Incident to the proposal to give priority to requests that 
are pre-confirmed, the NOPR proposed a new definition of Pre-Confirmed 
Application.
Comments
    1694. No commenters oppose the Commission's proposed definition of 
a Pre-Confirmed Application.
Commission Determination
    1695. The Commission adopts the proposed definition of Pre-
Confirmed Application in order to implement the reforms adopted above 
regarding the priority of transmission service requests under the pro 
forma OATT.
e. NOPR Proposals Not Adopted
Economy Energy
    1696. The Commission also proposed in the NOPR to adopt a 
definition of ``economy energy'' incident to its proposed changes to 
section 28.4 regarding the use of secondary network service. As 
discussed in section V.D.7, the Commission retains the existing 
requirement in section 28.4 that permits use of secondary network 
service ``to deliver energy to its Network Loads.'' The proposed 
definition of ``economy energy'' is therefore unnecessary.
f. Commenter Proposals
    1697. Several commenters request that the Commission amend or add 
other definitions in the pro forma OATT.
(1) Network Transmission Service
Comments
    1698. TDU Systems and Northwest Parties contend that, to help 
eliminate undue discrimination, the Commission should modify the 
definitions of ``network load'' and ``network operating committee'' in 
the pro forma OATT. Although the pro forma OATT already defines 
``network load'' to include wholesale native load, TDU Systems contend 
that transmission providers frequently either give preference to their 
own retail native load or ignore wholesale customer native load in 
planning and expansion of the system and in ATC calculations for 
processing transmission service requests. TDU Systems argue that 
comparable treatment of wholesale native load and retail native load is 
required in all respects in light of the definition of ``network 
load.'' At the same time, TDU Systems argue that the definition of 
``network load'' unreasonably restricts a transmission customer from 
serving a part of its load at a given delivery point with non-network 
resources since it provides that a customer ``may not designate only 
part of the load at a discrete Point of Delivery.''
    1699. Northwest Parties also assert that the Commission should 
revise the definition of ``network load'' to permit point-to-point 
service and network service to the same network load if the point-to-
point service is ignored in calculating load ratio share. Northwest 
Parties also argue that the Commission should allow point-to-point and 
network service to the same network load if the point-to-point service 
is purchased as non-firm.
    1700. EEI replies in opposition to TDU Systems' proposal to 
eliminate the requirement that a network customer may designate only 
part of its load delivery as a network load. EEI argues that TDU 
Systems are incorrect in asserting that the definition of ``network 
load'' prohibits a network customer from serving part of its load with 
non-network resources and secondary network service to serve part, or 
even

[[Page 12483]]

all, of its network load. EEI contends that adoption of TDU Systems' 
proposal would eliminate one of the fundamental principles on which 
network service is founded: That the network customer must pay for 
network service based on its entire load, including load served by 
behind the meter generation, since the transmission provider must plan 
its transmission system to serve the customer's entire load.
    1701. PNM-TNMP agree on reply that Commission should reject a 
change to the definition in the pro forma OATT regarding network load. 
PNM-TNMP state that the proposal presupposes that transmission 
providers discriminate against transmission customers and provides 
preferential treatment to their own retail native load in terms of 
planning and expansion of the system and in ATC calculations for 
processing transmission service requests. PNM-TNMP contend that they 
treat retail native load comparably with other network customers in all 
aspects and believe that any problems encountered by a transmission 
customer regarding undue discrimination should be addressed through the 
enforcement or complaint process, and that a change to the pro forma 
OATT is not warranted.
Commission Determination
    1702. The Commission declines to modify the definitions of 
``network load'' and ``network operating committee.'' The reforms 
related to ATC calculation and transmission planning adopted in this 
Final Rule adequately address the concerns regarding undue preference 
of native load in those areas. With regard to the request to allow 
network customers to serve part of their load with non-firm point-to-
point service and part with network service, the Commission already 
determined in Order Nos. 888 and 888-A that a transmission customer is 
not allowed to take a combination of both network and point-to-point 
transmission service to serve the same discrete load.\963\ We are not 
persuaded to modify that policy here.
---------------------------------------------------------------------------

    \963\ See Order No. 888 at 31,736; Order No. 888-A at 30,259.
---------------------------------------------------------------------------

(2) Firm and Non-Firm Transmission Service
Comments
    1703. Powerex contends that ``firm transmission service'' is not 
adequately defined or sufficiently described in the pro forma OATT to 
ensure that a transmission customer is not being required to pay for 
firm service that is curtailed on a regular basis. For example, Powerex 
states the Commission could require that firm transmission service be 
available at least 95 percent of the time (excluding force majeure 
curtailments) in order for transmission to be defined as ``firm.''
    1704. Powerex also contends that ``non-firm transmission service'' 
is interpreted differently in different regions. In the Pacific 
Northwest, Powerex asserts that non-firm service implies a lower 
curtailment priority but only as a result of actual transmission system 
constraints (i.e., once the operating hour has begun, higher priority 
firm reservations cannot implement schedules over lower priority non-
firm reservation). In contrast, Powerex argues that, for some 
transmission providers located in the Desert Southwest, transmission 
capacity associated with firm service reservations that have capacity 
schedules attached to them (e.g., to deliver operating reserves) can 
also be sold as non-firm service that could be interrupted in the 
operating hour by the firm reservation. Powerex believes that these two 
types of service could be described as non-firm, non-interruptible (for 
the Pacific Northwest) and non-firm, interruptible (for the Desert 
Southwest).
Commission Determination
    1705. The Commission finds that the clarifications proposed by 
Powerex are unnecessary to remedy undue discrimination in the provision 
of open access transmission service. In section V.D.8 of this Final 
Rule, the Commission requires transmission providers to post additional 
information regarding curtailments in order to provide transparency and 
allow customers to determine whether they have been treated in the same 
manner as other transmission system users. We conclude that existing 
compliance and enforcement procedures, coupled with these new posting 
requirements, are sufficient to address improper curtailments of 
service.
(3) System Impact Study
Comments
    1706. Powerex urges the Commission to modify sections 1.47 and 17.5 
of the pro forma OATT to clarify that transmission providers are not 
required to perform system impact studies for short-term service 
requests. Specifically, Powerex requests that the Commission amend the 
definition of a ``system impact study'' to refer only to requests for 
long-term firm point-to-point service or network service. Powerex 
argues that short-term firm point-to-point service requests do not 
require transmission providers to upgrade their systems and, as a 
result, requiring system impact studies for short-term requests often 
creates unnecessary burdens for transmission providers by mandating 
them to use limited resources to perform studies that do not offer 
significant benefits to customers. Powerex contends that the 60-day 
study period is particularly ill-suited for short-term transmission 
requests, most of which are for service that must commence within the 
study period.
Commission Determination
    1707. The Commission declines to modify the definition of ``system 
impact study'' or otherwise modify section 17.5 to restrict system 
impact studies only to exclude reference to short-term point-to-point 
service. Regardless of the length of a service request, a transmission 
provider must assess whether a system impact study is required to 
evaluate the request for transmission service. Only upon the completion 
of such an assessment will the transmission provider be able to 
identify the impact a particular request will have on the grid. We 
conclude that eliminating or shortening the system impact study period 
could jeopardize system reliability and therefore reject the 
modifications proposed by Powerex.
(4) Definitions for RTOs, ISOs and ITCs
Comments
    1708. Wisconsin Electric and International Transmission argue that 
the terms used in the pro forma OATT are inadequate when applied to RTO 
regions, especially in MISO. International Transmission and Wisconsin 
Electric assert that, in an RTO, the transmission provider and 
transmission owner are separate entities with separate functions, thus 
creating a need for separate definitions. They also contend that 
additional definitions may be needed when the transmission owner is an 
independent stand-alone transmission company operating within the RTO.
    1709. Wisconsin Electric requests that the Commission define the 
term ``transmission owner'' in the pro forma OATT and specify which of 
its provisions are applicable to the transmission provider and which 
apply to the ``transmission owner.'' Additionally, Wisconsin Electric 
states that the pro forma OATT includes a definition for ``control 
area'' and the NOPR refers to the geographic area served by 
transmission providers as its control area, which in Wisconsin 
Electric's view is inaccurate in the case of MISO. Wisconsin Electric 
explains MISO has shifted to the use of the NERC

[[Page 12484]]

functional model and uses terms such as ``balancing authorities,'' 
``generator operators,'' ``reliability authorities,'' and the like. 
Wisconsin Electric therefore requests that the Commission supplant the 
term ``control area'' in the pro forma OATT with a term that is 
predicated on the performance of a particular function, not the type of 
entity performing the function.
    1710. International Transmission does not object to the 
Commission's proposal to largely retain the existing definitions set 
forth in the pro forma OATT, but asserts that the Commission should 
explicitly recognize in the Final Rule that such definitions may be 
inadequate when applied to RTOs. International Transmission also asks 
the Commission not to require RTOs with additional definitions in their 
tariffs to remove those definitions when complying with the Final Rule 
and, instead, expressly allow RTOs to propose additional definitions 
that may be necessary.
Commission Determination
    1711. As explained in section IV.C, all transmission providers--
including ISOs and RTOs--will have an opportunity to demonstrate that 
departures from the pro forma OATT, as modified by this Final Rule, are 
consistent with or superior to the terms and conditions of the pro 
forma OATT. Proposals to amend terms such as ``control area'' or 
``transmission owner'' based on a particular set of facts are best left 
for case-by-case review.
(5) Other Definitions
Comments
    1712. Ameren advocates the modification of a number of other pro 
forma OATT definitions. Ameren proposes definitions for ``source'' and 
``sink,'' as well as additional provisions in section 22.2 governing 
source and sink of transmission. Ameren also requests clarification of 
the word ``use'' in section 30.8, arguing that some entities have 
assumed that ``use'' means scheduled amounts. Ameren argues for an 
improved definition of ``transmission peak'' because the data necessary 
no longer resides with the transmission owner in an RTO or ISO. 
Finally, Ameren suggests a revised definition of ``long-term firm,'' 
which would include only contracts that are longer than one year, not 
just one year or longer, arguing it would reduce the number of 
contracts that are only one-year in length that are used in the 
denominator for purposes of calculating the load ratio share and for 
ratemaking purposes. On this latter point, Ameren asserts that such 
contracts should be reflected as a revenue credit instead. In addition, 
Ameren believes that the current definition of long-term firm point-to-
point service in section 1.18 of the pro forma OATT makes calculation 
of load ratio share very difficult in the modern RTO/Seams Elimination 
Cost Allocation (SECA) environment.
Commission Determination
    1713. The Commission is not persuaded to adopt the revisions 
proposed by Ameren. We believe that what constitutes source and sink is 
sufficiently addressed in Order No. 888 and OASIS related proceedings 
and we will not expand the discussion here.\964\ Order No. 888 also 
made clear that there are no ``load ratio'' limitations on the use of 
interfaces under section 30.8 of the pro forma OATT.\965\ Otherwise, 
requests for interface capacity are subject to the pro forma OATT 
procedures. Moreover, Ameren has failed to justify revising the 
definition of ``transmission peak.'' While peak load data ultimately 
resides with the RTO or ISO, each transmission provider coordinates 
this type of data with RTO or ISO. Finally, we reaffirm that long-term 
firm service is service with a term of one year or more. Modifying the 
term of long-term service to reduce the number of contracts used in the 
denominator for purposes of calculating the load ratio share and for 
ratemaking purposes may affect how the transmission provider plans its 
system to service customers and has not been justified.
---------------------------------------------------------------------------

    \964\ Redirect-related issues are addressed in section V.D.4.
    \965\ See Order No. 888 at 31,753-54; Order No. 888-A at 30,304-
5; see also Sierra Pacific Power Co., 81 FERC ] 61,136 at 61,139-40 
(1997); New England Power Pool, 83 FERC ] 61,045 at 61,248 (1998).
---------------------------------------------------------------------------

E. Enforcement

    1714. The Commission attaches substantial importance to 
strengthening compliance with the OATT, on monitoring and auditing OATT 
compliance, including its staff's efforts to resolve disputes about 
compliance through the Enforcement Hotline and other dispute resolution 
mechanisms, and on investigating potential and alleged OATT violations. 
The expansion of the Commission's enforcement powers pursuant to EPAct 
2005 directly augmented its ability to enforce the OATT by, among other 
things, providing authority to assess civil penalties of up to $1 
million for each day that an OATT violation continues. The Commission 
intends to use its enforcement powers with respect to the OATT in a 
fair and even-handed manner, pursuant to the principles set forth in 
the Policy Statement on Enforcement.
1. General Policy
a. Compliance Review Regime
NOPR Proposal
    1715. The Commission proposed to maintain a strong program to audit 
compliance with the new pro forma OATT. The audit program would include 
operational audits similar to past OATT compliance audits, during which 
staff may collect information on implementation of a transmission 
provider's OATT. The Commission stated that it would issue public 
reports of audit results and noted that contested audits would be 
subject to the Commission's Final Rule on contested operational 
audits.\966\
---------------------------------------------------------------------------

    \966\ See Procedures for Disposition of Contested Audit Matters, 
Order No. 675, 71 FR 9698 (Feb. 27, 2006), FERC Stats. & Regs. ] 
31,209 (2006) (Contested Audit Matters), order on rehearing and 
clarification, Order No. 675-A, 71 FR 29779 (May 24, 2006), FERC 
Stats. & Regs. ] 31,217 (2006).
---------------------------------------------------------------------------

Comments
    1716. Most initial commenters support a strong staff audit 
program.\967\ Other commenters counter that staff audits will not be 
needed if the Commission issues a corrected pro forma OATT, especially 
with respect to RTOs and ISOs.\968\ These commenters argue that formal 
complaints, Enforcement Hotline calls and random audits sufficiently 
inform staff of OATT compliance issues as to make additional staff 
audits unnecessary. Southern asserts that, under the separation of 
function policy, Commission audit staff should be separated from 
investigative and enforcement staff. Particular commenters contend that 
the Commission should focus compliance efforts on specific OATT 
provisions, such as those concerning network service (Arkansas Cities), 
or on structural issues such as independent planning and operation of 
transmission facilities (Reliant). Nevada Companies suggests that the 
Commission set up regional audit teams to foster strong working 
relationships with transmission providers. EPSA asks the Commission to 
adopt stronger measures than a staff audit program to monitor 
compliance. EPSA's proposed measures include requiring transmission 
providers to: designate compliance officers to report OATT violations 
to company boards; undergo compliance audits by an

[[Page 12485]]

independent auditor in response to material violations; and hire an 
independent administrator to oversee OATT compliance and regional 
planning efforts if a transmission provider has not complied with its 
new OATT within a specified period of time. In reply comments, MISO 
opposes EPSA's proposal for a third-party compliance administrator for 
RTOs and ISOs if they do not timely comply with new OATT provisions, 
arguing that these entities already are independent administrators of 
transmission grids and planning processes. MISO asserts that inserting 
an ``independent'' authority over OATT compliance by RTOs and ISO would 
create a superfluous bureaucratic layer. NRECA opposes EPSA's proposal 
because a third-party compliance administrator or auditor would be too 
expensive and the Commission cannot delegate its compliance authority.
---------------------------------------------------------------------------

    \967\ E.g., APPA, AWEA, EEI, Morgan Stanley, NRG, Southern, 
TAPS, and Williams.
    \968\ E.g., Ameren, PNM-TNMP, and South Carolina E&G. In reply 
comments, TDU Systems urge the Commission to reject this contention.
---------------------------------------------------------------------------

    1717. Noting that the Commission required RTOs to undertake 
extensive market monitoring in Order No. 2000, PJM states that the 
Commission should require in the pro forma OATT a similar degree of 
market monitoring in non-RTO areas to make available to Commission 
staff information needed to ascertain market abuses in these areas. PJM 
asserts that any such market monitoring should be performed by entities 
independent of the non-RTO utilities, with Commission oversight. 
Indicated Parties reply that RTOs' market monitors should examine 
market power in transmission planning because RTOs delegate 
transmission operations and planning duties to constituent transmission 
owners that retain incentives to benefit affiliates or vertically-
integrated divisions.
Commission Determination
    1718. The Commission adopts the NOPR proposal to emphasize a strong 
staff audit program for compliance with OATT requirements, including 
operational audits. Staff audits of OATT compliance may be random or 
targeted with respect to the entities being audited or particular 
provisions of the OATT that are scrutinized. Because its responsibility 
is to assess and ensure compliance with the OATT, staff will maintain 
discretion as to the entities it audits and the subject matter of these 
audits. The Commission encourages transmission providers to designate 
employees as compliance officers for the OATT or to conduct third-party 
audits relating to OATT compliance when appropriate. However, we do not 
believe that staff should forego an audit of an entity's OATT 
compliance solely because a transmission provider has designated an 
OATT compliance officer, engaged a third-party auditor, or transferred 
transmission functions to an independent transmission coordinator. We 
decline EPSA's proposal to require such actions, except on a case-by-
case basis when warranted.
    1719. We disagree with PJM's request that the Commission require 
third-party market monitoring to ascertain market abuses occurring with 
respect to transmission providers outside RTOs and ISOs, subject to 
Commission oversight. In a number of instances since 2000, the 
Commission has established third-party monitoring of a transmission 
provider located outside an RTO or ISO.\969\ These monitors were 
established on a case-specific basis to address concerns related to the 
transmission provider at issue. We have no evidence to support 
requiring monitors for every transmission provider in the Nation. 
Further, the Commission has access to substantial information on OATT 
compliance by transmission providers that are not RTOs or ISOs through 
their postings on OASIS, informal and formal complaints by customers, 
and reports by market monitors for such transmission providers. Indeed, 
the revised pro forma OATT will greatly enhance our oversight and 
enforcement capabilities by increasing the transparency of many 
critical functions under the pro forma OATT, such as ATC calculation 
and transmission planning. PJM has not provided any evidence that the 
enhanced transparency under the OATT, coupled with the Commission's own 
monitoring and audits of OATT compliance and its enhanced enforcement 
authority, will be insufficient to ascertain and deter OATT violations. 
We do not object to the suggestion of Indicated Parties that RTO and 
ISO market monitors examine market power in transmission planning, so 
long as the market monitors' activities in this respect are consistent 
with these roles as set forth in the applicable RTO and ISO tariffs.
---------------------------------------------------------------------------

    \969\ See, e.g., Duke Power, 113 FERC ] 61,288 (2005); 
MidAmerican Energy Holdings Co., 113 FERC ] 61,298 (2005).
---------------------------------------------------------------------------

    1720. We do not agree with Southern's assertion that the 
Commission's audit staff should be separated from its investigative and 
enforcement staff. The Commission's separation of functions regulation 
\970\ generally permits Commission auditors, investigators and 
enforcement staff to speak freely to persons inside the Commission as 
to the subject matter of their inquiries.\971\ Southern has not cited 
any justification for restricting communications among these staff 
members or from them to the Commission. To the contrary, a free flow of 
communications among auditors and investigators, consistent with the 
Commission's rule on staff separation of functions, should increase the 
efficiency of the Commission staff's compliance program and enforcement 
efforts.\972\
---------------------------------------------------------------------------

    \970\ 18 CFR 385.2202.
    \971\ Statement of Administrative Policy on Separation of 
Functions, 101 FERC ] 61,340 at P 24-26 (2002).
    \972\ See also Order No. 675-A at P 25-29 (the Commission's 
regulation and policy statement on separation of functions remain 
applicable following EPAct 2005, and efficiency and sound 
administrative practice continue to favor the sharing of information 
between the Commission's audit staff and investigative staff).
---------------------------------------------------------------------------

b. Use of Independent Third Party Audits
NOPR Proposal
    1721. The Commission proposed not to mandate the use of third party 
auditors and, instead, proposed that Commission staff conduct audits of 
compliance with the pro forma OATT. The Commission stated that it may 
require third party compliance audits as part of a compliance plan 
following a Commission staff audit report. In response to situations 
such as systematic OATT violations, a pattern of repeated violations, 
or violations that require ongoing monitoring, the Commission could 
require an audited party to hire a third party to continue compliance 
audits.
Comments
    1722. Most initial commenters agree with the Commission's proposal 
to require third-party audits only as part of an individual post-audit 
compliance plan.\973\ EEI and Southwestern Coop submit that selection 
of third-party auditors should be subject to Commission review and 
approval, while South Carolina E&G cautions that the Commission should 
carefully weigh the costs and benefits of independent auditors before 
requiring their use. Southern suggests that third-party audits be 
required only for systematic, egregious OATT violations. Entegra doubts 
that third-party auditors can remedy patterns of discrimination by 
transmission providers against independent merchant generators.
---------------------------------------------------------------------------

    \973\ E.g., Alberta Intervenors, Arkansas Commission, 
Constellation, EEI, EPSA, MISO/PJM States, Nevada Companies, PNM-
TNMP, South Carolina E&G, Southwestern Coop, and Suez Energy NA.

---------------------------------------------------------------------------

[[Page 12486]]

Commission Determination
    1723. The Commission adopts the NOPR proposal not to require 
generally the use of third party auditors to assess compliance with the 
OATT. We believe that a requirement for the use of third-party audits 
in compliance plans should depend on particular facts, including the 
egregiousness and extent of violations found during a staff audit or 
investigation and the appropriate scope or cost of a third-party audit. 
As stated above, we encourage transmission providers to use third-party 
compliance audits when appropriate to supplement our staff's audit 
efforts.
2. Civil Penalties
    1724. In the NOI, the Commission asked for comment as to whether it 
should address imposing remedies or penalties against transmission 
providers as part of OATT reform. After the NOI, the Commission issued 
its Policy Statement on Enforcement and, in response to specific 
authority granted it in EPAct 2005, issued Order No. 670, the Anti-
manipulation Rule. \974\
---------------------------------------------------------------------------

    \974\ Prohibition of Energy Market Manipulation, III FERC Stats. 
& Regs. ] 31,202 (2006), order denying rehearing, 114 FERC ] 61,300 
(2006).
---------------------------------------------------------------------------

a. Whether Civil Penalties Should Be Specified in the OATT
NOPR Proposal
    1725. Aside from operational penalties proposed in the NOPR, \975\ 
the Commission proposed not to establish a schedule of enforcement 
remedies and sanctions in the pro forma OATT. Rather, the Commission 
stated that it would address OATT violations and appropriate responses 
on a case-by-case basis, consistent with the Policy Statement on 
Enforcement. The Commission explained that it may impose civil 
penalties when warranted, after consideration of applicable factors 
listed in the Policy Statement on Enforcement; OATT violators also will 
be expected to disgorge unjust profits when they can be determined or 
reasonably estimated.
---------------------------------------------------------------------------

    \975\ NOPR at P 384.
---------------------------------------------------------------------------

Comments
    1726. The majority of parties filing comments on this issue agree 
that the Commission should assess civil penalties on a case-by-case 
basis under the guidance of the Policy Statement on Enforcement. \976\ 
Other commenters instead support incorporation in the pro forma OATT of 
a schedule of significant remedies and sanctions for specific 
violations to assure transparency and certainty as to situations in 
which penalties would be assessed and to deter anticompetitive 
behavior. \977\ EPSA advises that the Commission refrain from setting 
pre-determined limits on penalty amounts because each violation of a 
specific pro forma OATT provision may present different facts that may 
warrant different outcomes. Nevada Companies suggest that the 
Commission provide incentives to construct new transmission 
infrastructure rather than implement an overbearing penalty regime 
because additional transmission capacity itself will resolve many 
complaints.
---------------------------------------------------------------------------

    \976\ E.g., APPA, EEI, EPSA, Nevada Companies, PNM-TNMP, 
Southern, and Southwestern Coop. Southwestern Coop also urges speedy 
review of violations and swift assessment of penalties. In reply 
comments, Sacramento adds that the Commission may assess civil 
penalties against a transmission provider that engages in unduly 
discriminatory behavior in its transmission planning process.
    \977\ E.g., Arkansas Commission and ELCON.
---------------------------------------------------------------------------

    1727. Wisconsin Electric concludes that OATT violations by non-
profit RTOs and ISOs should not be subject to civil penalties because 
they would be passed through to customers and not act as an effective 
deterrent. \978\ Rather than assess a penalty in response to an RTO's 
or ISO's OATT violation, Wisconsin Electric suggests that the 
Commission could intensify oversight of an RTO's or ISO's OATT 
compliance. NorthWestern comments, in contrast, that RTOs and ISOs 
should not be exempted from civil penalty assessments for their OATT 
violations, because these violations could have as much or more adverse 
effects on transmission access or system reliability as would OATT 
violations by other transmission providers.
---------------------------------------------------------------------------

    \978\ Wisconsin Electric asserts that the Commission has 
recognized this principle in other contexts, citing Financial 
Reporting and Cost Accounting, Oversight and Recovery Practices for 
Regional Transmission Organizations and Independent System 
Operators, FERC Stats. & Regs. ] 35,546 at P 9 (2004).
---------------------------------------------------------------------------

    1728. Several commenters support the Commission's proposal to 
consider mitigating factors listed in the Policy Statement on 
Enforcement in assessing civil penalties for OATT violations. \979\ In 
this regard, EEI states that the Commission should clarify that when a 
party engages in self-reporting, compliance programs or cooperation 
with Commission staff, the Commission will recognize the party's 
attorney-client privilege. \980\
---------------------------------------------------------------------------

    \979\ E.g., Nevada Companies and PNM-TNMP.
    \980\ EEI observes that the Commission held in its final rule on 
contested audit procedures that ``an audited person who 
appropriately interposes the attorney-client privilege will not be 
considered non-cooperative.'' Contested Audit Matters at P 35.
---------------------------------------------------------------------------

    1729. EEI suggests that the Commission establish ``safe harbors'' 
against civil penalties for OATT violations involving reasonable 
interpretations of tariff provisions or for actions taken for 
reliability purposes that are consistent with good utility practice. 
PNM-TNMP and Southern ask the Commission to clarify that LSEs will not 
be penalized for OATT violations for taking actions necessary to meet 
their native load obligations since, pursuant to new FPA section 217, 
\981\ LSEs should not be considered to have engaged in ``undue 
discrimination or preference'' for certain actions required to serve 
native load customers. TDU Systems argue in reply comments that a 
``safe harbor'' approach could permit unduly discriminatory or 
preferential behavior that would be penalized under a case-by-case 
approach. Entegra replies that safe harbors for ``reasonable'' tariff 
interpretations would give vertically-integrated utilities license to 
discriminate against competitors, and suggests that the Commission 
ensure that the OATT operates as a sword for attacking undue 
discrimination, not as a shield for defending it. Occidental replies 
that transmission providers with a Commission-approved independent 
transmission coordinator should not be insulated from tariff-based 
civil penalties and other sanctions.
---------------------------------------------------------------------------

    \981\ 16 U.S.C. 824q(k).
---------------------------------------------------------------------------

Commission Determination
    1730. Following enactment in EPAct 2005 of enhanced authority for 
the Commission to assess civil penalties for violations of statutes it 
administers and of regulations and orders under these statutes, the 
Commission issued the Policy Statement on Enforcement to set forth how 
it intends to use this authority consistent with the statute. \982\ 
Underlying this policy is the recognition that the appropriate basis 
for assessment of a civil penalty for a violation is an examination of 
the facts and circumstances relating to that violation, and the use of 
discretion and flexibility to address it on its merits. This 
examination includes a review of all applicable mitigating factors set 
forth in the Policy Statement on Enforcement. While we understand that 
establishing a schedule of civil penalties for violations of particular 
provisions of the pro forma OATT would establish greater specificity 
with respect to civil penalties, the Commission already concluded in 
the Policy Statement on Enforcement that it would ``not prescribe 
specific penalties or develop formulas for different violations.'' 
\983\ We see no justification to depart from

[[Page 12487]]

that decision with respect to violations of OATT provisions.
---------------------------------------------------------------------------

    \982\ Policy Statement on Enforcement at P 1.
    \983\ Id. at P 13.
---------------------------------------------------------------------------

    1731. Several commenters ask that we establish specific ``safe 
harbors'' or exemptions from assessment of civil penalties for OATT 
violations in specific circumstances or with respect to specific types 
of entities that may engage in OATT violations. We decline to create 
automatic safe harbors for specific circumstances or specific types of 
OATT violations. The creation of such exemptions would require us to 
forego the examination of the specific circumstances of particular 
violations that we described in the Policy Statement on Enforcement as 
the touchstone of our policy in assessing civil penalties. Instead, we 
will decide requests for leniency in particular cases by using the 
principles set forth in the Policy Statement on Enforcement and 
considering all applicable mitigating factors listed therein.\984\
---------------------------------------------------------------------------

    \984\ We have also provided clarification on the procedures that 
would apply to the assessment in formal proceedings of civil 
penalties relating to OATT violations in our recent Statement of 
Administrative Policy Regarding the Process for Assessing Civil 
Penalties, 117 FERC ] 61,317 (2006).
---------------------------------------------------------------------------

    1732. Likewise, we will not establish an automatic exemption from 
civil penalty assessments for OATT violations committed by particular 
types of entities such as non-profit RTOs and ISOs. The Commission 
decided last year that it would not automatically exempt RTOs and ISOs 
from penalties assessed by the Electric Reliability Organization or 
Regional Entities for reliability violations pursuant to new FPA 
section 215. In Order No. 672, the Commission stated, ``[w]hile we 
recognize that RTOs and ISOs have some unique characteristics, we do 
not believe that a generic exemption from any type of penalty is 
appropriate for any entity, including an RTO or ISO.'' \985\ We believe 
the same principle applies to civil penalties for OATT violations. 
However, in assessing civil penalties for OATT violations, we will 
consider all applicable facts relating to the violator, including the 
effect of potential penalties on the financial viability of the 
violator.\986\
---------------------------------------------------------------------------

    \985\ Rules Concerning Certification of the Electric Reliability 
Organization; and Procedures for the Establishment, Approval, and 
Enforcement of Electric Reliability Standards, Order No. 672, 71 FR 
8662 (Feb. 17, 2006), FERC Stats. & Regs. ] 31,204 at P 634 (2006), 
order on reh'g, Order No. 672-A, FERC Stats. & Regs. ] 31,212 
(2006).
    \986\ Policy Statement on Enforcement at P 20. Cf. Order No. 
672-A at P 56-57 (holding that for determining a penalty pursuant to 
the FPA section 215 reliability program, circumstances such as 
organization structure or non-for-profit status will be considered, 
but that there should not be an automatic exemption from monetary 
penalties for RTOs and ISOs).
---------------------------------------------------------------------------

    1733. We agree with commenters who state that the Commission and 
its staff should recognize the valid assertion of the attorney-client 
privilege in the context of investigations, audits and other fact-
finding activities. As EEI points out, we recently stated with respect 
to audits that we would not consider an entity to be uncooperative with 
audit staff if the entity appropriately asserts that a communication or 
document is covered by that privilege.\987\ We take the same position 
with respect to investigations or other fact-finding undertakings with 
respect to possible OATT violations.
---------------------------------------------------------------------------

    \987\ Citing Contested Audit Matters at P 35.
---------------------------------------------------------------------------

    1734. In the Policy Statement on Enforcement, however, the 
Commission drew a distinction between cooperation, which we expect from 
entities subject to the Commission's jurisdiction given their statutory 
obligation to provide information to us, and ``exemplary'' cooperation, 
which ``quickly ends wrongful conduct, determines the facts, and 
corrects a problem.'' \988\ The Commission explained that we will give 
some consideration to exemplary cooperation and indicated that one 
example of such cooperation is a situation in which an entity being 
investigated provides to staff internal investigations or audit reports 
relating to misconduct. These investigations and reports may include 
information that an entity could properly shield from disclosure 
pursuant to the attorney-client privilege. We observe that an entity 
that is in a position to assert this privilege validly also has the 
option to waive it. If a waiver of attorney-client privilege, whether 
related to an internal investigation or audit or not, assists staff in 
ascertaining the facts relating to alleged or apparent misconduct, ends 
misconduct quickly or otherwise substantially advances an investigation 
or inquiry, that waiver may be an element in finding ``exemplary 
cooperation'' as described in the Policy Statement on Enforcement.\989\
---------------------------------------------------------------------------

    \988\ Policy Statement on Enforcement at P 26.
    \989\ See In re PacifiCorp, 118 FERC ] 61,026 at P 3, 8 and 
attached stipulation and consent agreement at P 24 (2007) (referring 
to transmission provider's waivers of attorney-client privilege as 
an element in making finding of exemplary cooperation with 
investigation when approving settlement assessing civil penalty that 
resolved a transmission provider's violations of its OATT, among 
other matters); In re Entergy Services, Inc., 118 FERC ] 61,027 at P 
15, 18 (2007) (same).
---------------------------------------------------------------------------

b. Whether Transmission Providers Should Be Subject to Revocation of 
Market-Based Rates for OATT Violations
NOPR Proposal
    1735. The Commission observed in the NOPR that some OATT 
violations, after applying the factors in the Policy Statement on 
Enforcement to all facts and circumstances, may merit revocation of 
market-based rate authority. Before considering revoking an entity's 
market-based rate authority for an OATT violation, the Commission 
proposed that it must find a nexus between the specific facts relating 
to the OATT violation and the entity's market-based rate authority. The 
Commission also proposed that if it determines, as a result of a 
significant OATT violation, to revoke the market-based rate authority 
of a transmission provider within a particular market, each affiliate 
of the transmission provider that possesses market-based rate authority 
would have that authority revoked in that market, effective on the date 
of revocation of the transmission provider's market-based rate 
authority.
Comments
    1736. Most parties that submitted initial comments on this issue 
support the Commission's conclusion that, in certain circumstances, it 
may be appropriate to revoke the market-based rate authority of an 
entity that engages in an OATT violation.\990\ The majority of these 
commenters support the Commission's proposal to do so only if it finds 
a nexus between the OATT violation and the entity's market-based rate 
authority.\991\
---------------------------------------------------------------------------

    \990\ E.g., EEI, ELCON, Morgan Stanley, Nevada Companies, 
Northwest IOUs, Progress Energy, PNM-TNMP, Sempra Global, Southern, 
and TDU Systems.
    \991\ E.g., EEI, Nevada Companies, Northwest IOUs, Progress 
Energy, PNM-TNMP, Sempra Global, and Southern.
---------------------------------------------------------------------------

    1737. Some commenters oppose the requirement for a nexus between 
the OATT violation and the entity's market-based rate authority because 
the Commission has not stated what facts would be sufficient to show 
such a nexus.\992\ EPSA and NRECA (in reply comments) contend that if 
the Commission does not remove the ``nexus'' condition, it should 
clarify what constitutes a ``nexus'' between an OATT violation and an 
entity's market-based rate authority. Similarly, PNM-TNMP argues that 
such a nexus must be clear and fact-specific, consistent with the 
Policy Statement on Enforcement. TDU Systems contend in reply

[[Page 12488]]

comments that, at a minimum, a transmission provider or its affiliate 
that has market-based rate authority must overcome a rebuttable 
presumption that its OATT violation has the requisite ``nexus'' to 
support revocation of such authority.
---------------------------------------------------------------------------

    \992\ E.g., APPA.
---------------------------------------------------------------------------

    1738. Other commenters argue that a serious OATT violation removes 
the mitigation of transmission market power provided by adherence to an 
OATT, thereby eviscerating one of the essential requirements for 
market-based rate authority.\993\ EEI and PNM-TNMP reply that not every 
OATT violation diminishes the availability of transmission service so 
as to establish vertical market power.
---------------------------------------------------------------------------

    \993\ E.g., APPA, EPSA, and TAPS.
---------------------------------------------------------------------------

    1739. APPA and TDU Systems suggest in reply comments that the 
proposed nexus condition would unduly limit any sanctions, because the 
shareholders of the violator could still reap the benefits of such a 
violation if an affiliate that did not have any knowledge of the OATT 
violation could continue to engage in transactions under market-based 
rate authority. According to APPA, this possibility could lessen the 
incentive for senior management over a transmission provider and 
affiliates to make OATT compliance a high priority. As such, APPA and 
TAPS suggest that the Commission consider revoking a transmission 
provider's market-based rate authority for a ``material'' OATT 
violation that effectively denies, delays, or diminishes a customer's 
access to transmission service essential to mitigating transmission 
market power.
    1740. TDU Systems caution that revocation of market-based rate 
authority may not be sufficient to deter OATT violations if reversion 
to cost-based rates may provide a transmission provider with the 
ability to recover all costs and receive higher revenues than 
competitive markets might otherwise produce. Therefore, TDU Systems ask 
that the Commission consider assessment of civil penalties in addition 
to revocation of market-based rate authority.
    1741. The majority of commenters disagree, however, with the 
Commission's proposal to revoke the market-based rate authority of all 
affiliates of a transmission provider to the same extent that we revoke 
that transmission provider's market-based rate authority.\994\ These 
commenters assert that affiliates that have no knowledge of, or 
involvement in, their affiliated transmission provider's unlawful 
activities should not lose their market-based rate authority as a 
result of the transmission provider's OATT violation. NRECA replies 
that market-based rate authority is a privilege, not a right, and 
asserts that the Commission should revoke market-based rate authority 
in response to an OATT violation that indicates that a public utility 
possesses market power.
---------------------------------------------------------------------------

    \994\ E.g., EEI, Nevada Companies, Northwest IOUs, Progress 
Energy, PNM-TNMP, Sempra Global, and Southern.
---------------------------------------------------------------------------

    1742. APPA also suggests that, short of revocation of a 
transmission provider's market-based rate authority in response to an 
OATT violation, the Commission could condition that authority, or the 
market-based rate authority of the transmission provider's affiliates. 
APPA provides the following examples of such conditions: A requirement 
to participate in joint planning of transmission facilities with the 
transmission provider's network customers and offer these customers 
appropriate credits under OATT section 30.9; an offer of joint 
transmission ownership opportunities to LSEs for new transmission 
facilities on reasonable terms and conditions; and an offer to network 
service customers to participate in the ownership of the transmission 
provider's existing transmission system on a load ratio share basis.
Commission Determination
    1743. We adopt the NOPR proposal to revoke an entity's market-based 
rate authority in response to an OATT violation only upon a finding of 
a specific factual nexus between the violation and the entity's market-
based rate authority. We believe that the ``nexus condition'' is 
required in order to ensure that our actions are not arbitrary or 
capricious or based on an inadequate factual record. We note that in 
this context the Commission has the burden to show a factual nexus. We 
do not assign a burden on the violator to show the lack of this nexus.
    1744. Determining what would be a sufficient factual nexus between 
an OATT violation and revocation of the violator's market-based rate 
authority is best left to a case-by-case consideration. The wide range 
of positions among commenters on how to define a sufficient factual 
nexus itself suggests that this finding is best made after review of a 
specific factual situation. Some commenters assert that a finding of a 
``serious'' or ``material'' violation of the OATT would be sufficient. 
We disagree. While an entity's inconsequential OATT violation would not 
serve as a basis for revoking that entity's market-based rate 
authority, our view is that the nexus condition requires us to find 
both that a substantial OATT violation has occurred and that the 
violation either related to the exercise of the violator's market-based 
rate authority or violated a specific condition of that authority.
    1745. The Commission emphasizes that we have discretion to fashion 
remedies for OATT violations that relate to the violator's market-based 
rate authority in instances in which we do not find a factual nexus 
justifying revocation of that authority. For example, in appropriate 
circumstances, we may modify or add additional conditions to the 
violator's market-based rate authority or impose other requirements to 
help ensure that the violator does not commit future, similar 
misconduct. Nor is revocation of market-based rate authority the only 
action we may take to respond to an OATT violation that meets the nexus 
condition. We will consider whether to impose sanctions such as 
assessment of civil penalties for particularly serious OATT violations 
in addition to revocation of the violator's market-based rate 
authority.
    1746. We do not adopt our proposal from the NOPR to revoke the 
market-based rate authority of each affiliate of a transmission 
provider that loses its market-based rate authority within a particular 
market as a result of an OATT violation. Rather, we will create a 
rebuttable presumption that all affiliates of a transmission provider 
should lose their market-based rate authority in each market in which 
their affiliated transmission provider loses its market-based rate 
authority as a result of an OATT violation. We will allow an affiliate 
of a transmission provider to retain its market-based rate authority in 
a market area if the affiliate overcomes the rebuttable presumption 
with respect to that market area.
    1747. We expect that the issue of potential revocation of market-
based rate authority will arise as a result of an OATT violation in a 
market in which the transmission provider possesses transmission market 
power through the ownership of transmission facilities in that market. 
For these markets, we have evaluated whether a transmission provider 
should receive authority to make sales of electric power for resale at 
market-based rates using a four-prong analysis. In this analysis we 
consider whether the transmission provider and its affiliates have 
adequately mitigated market power in generation and transmission, 
whether the transmission provider or its affiliates can erect other 
barriers to entry, and whether there is evidence that the transmission 
provider and its affiliates have engaged in

[[Page 12489]]

affiliate abuse or reciprocal dealing.\995\ In particular, we have long 
held that the existence of an OATT is deemed to mitigate vertical 
market power and transmission market power held by a transmission 
provider and its affiliates in a particular market. An OATT violation 
by a transmission provider in a market in which it possesses 
transmission market power that merits revocation of the transmission 
provider's market-based rate authority may call into question whether 
the transmission provider's affiliates continue to qualify for market-
based rates in that market under the standards that we have 
established.\996\ As a result, we believe that it is appropriate to 
establish a presumption in this circumstance that if we find that a 
transmission provider should lose its market-based rate authority in a 
market in which it possesses transmission market power, we will revoke 
the market-based rate authority in that market of all affiliates of the 
transmission provider.
---------------------------------------------------------------------------

    \995\ In our recent NOPR on market-based rates for wholesale 
sales of electricity, the Commission proposed to discontinue 
referring to affiliate abuse among a transmission provider and its 
affiliates as a separate ``prong'' of our analysis of whether to 
grant market-base rate authority. The Commission instead proposed to 
address affiliate abuse by requiring that transmission providers and 
their affiliates comply with restrictions and conditions set forth 
in the regulations we propose in that proceeding. Market-Based Rates 
for Wholesale Sales of Electric Energy, Capacity and Ancillary 
Services by Public Utilities, 71 FR 33102 (Jun. 7, 2006), FERC 
Stats. & Regs. ] 32,602 at P 13 (2006).
    \996\ We observe that specific situations in which transmission 
providers have agreed to resolve staff allegations that they engaged 
in OATT violations have involved transactions with affiliates. See 
Idaho Power (settlement of, among other issues, an Enforcement staff 
allegation that a transmission provider permitted its merchant 
function to request non-firm transmission to enable the merchant 
function to make off-system sales that by definition were not used 
to serve native load, so that the transmission did not qualify for 
the ``native load'' priority specified in section 28.4 of the 
transmission provider's OATT); Cleco Corp., 104 FERC ] 61,125 (2003) 
(settlement between Enforcement staff and a utility holding company 
and its subsidiaries relating, in part, to the provision by a 
transmission provider of a unique type of transmission service that 
was neither made available to non-affiliates nor included in its 
FERC tariff); Tucson Electric Power Co., 109 FERC ] 61,272 (2004) 
(operational audit in which staff found that, among other matters, a 
transmission provider permitted its wholesale merchant function to 
purchase hourly non-firm and monthly firm point-to-point 
transmission service using an off-OASIS scheduling procedure while 
the transmission provider did not post on its OASIS the availability 
of capacity on these paths); South Carolina Electric & Gas Co., 111 
FERC ] 61,217 (2005) (settlement of Enforcement staff allegation 
that a transmission provider made available firm point-to-point 
transmission service to its affiliated merchant function that did 
not submit transmission schedules with specific receipt points for 
the service as required by section 13.8 of the transmission 
provider's OATT); and MidAmerican Energy Co., 112 FERC ] 61,346 
(2005) (operational audit in which staff found, among other things, 
that a transmission provider permitted its wholesale merchant 
function to (a) use network transmission service to bring short-term 
energy purchases onto its system while it simultaneously made off-
system sales, inconsistently with the preamble to Part III of the 
transmission provider's OATT and section 28.6 of its OATT; and (b) 
confirm firm network transmission service requests without 
identifying a designated network resource or acquiring an associated 
network resource, in some instances using this service to deliver 
short-term energy purchases used to facilitate off-system sales, 
inconsistent with section 29.2 or section 30.6 of the transmission 
provider's OATT). See also Commission orders cited in note 989 
supra.
---------------------------------------------------------------------------

    1748. We are mindful, however, that the circumstances of a 
particular affiliate may not always justify the imposition of a remedy 
so severe as revocation of market-based rate authority in a particular 
market when its affiliated transmission provider loses its market-based 
rate authority in that market as a result of an OATT violation. To 
afford due process to a transmission provider's affiliates in that 
situation, and to ensure that a determination to revoke market-based 
rate authority in a particular market for a transmission provider and 
all of its affiliates that possess such authority is adequately based 
upon record evidence and not arbitrary or capricious, we will allow an 
opportunity for each such affiliate to make a showing that it should 
retain its market-based rate authority or that enforcement action 
against it should be less severe than revocation. The determination 
whether an affiliate has overcome the rebuttable presumption depends on 
an analysis of specific facts in the record. Relevant facts would 
include, but are not limited to, whether: (1) The transmission provider 
and the affiliate were under the same control; (2) the affiliate knew 
of, participated in or was an accomplice to the OATT violation; (3) the 
affiliate assisted the transmission provider in exercising market 
power; or (4) the affiliate benefited from the violation.
c. Whether Certain OATT Violations Should Be Considered Market 
Manipulation Under Section 222 of the FPA
NOPR Proposal
    1749. The Commission proposed in the NOPR to decline to identify in 
the pro forma OATT specific conduct that constitutes per se market 
manipulation. The Commission proposed to consider on a case-by-case 
basis, if and when they arise, whether specific circumstances relating 
to OATT violations constitute market manipulation under the standards 
set forth in Order No. 670.
Comments
    1750. All commenters on this issue concur with a case-by-case 
approach to it.\997\ Southwestern Coop suggests that, as the Commission 
gains sufficient experience to describe particular misconduct as market 
manipulation per se, it should identify such misconduct in the OATT. 
While contending that the Commission should act with caution in listing 
behaviors that constitute per se market manipulation in view of the 
dynamic nature of markets, TDU Systems urge the Commission to specify 
in the OATT that transmission planning misconduct could constitute a 
form of market manipulation or abuse.
---------------------------------------------------------------------------

    \997\ APPA, Nevada Companies, PNM-TNMP, Southwestern Coop, and 
TDU Systems.
---------------------------------------------------------------------------

Commission Determination
    1751. We adopt the NOPR proposal for a case-by case approach to 
considering whether OATT violations may constitute market manipulation. 
Without reference to a specific factual pattern developed in an 
investigation or on-the-record proceeding, the Commission is not in a 
position to identify market manipulation relating to OATT 
violations.\998\
---------------------------------------------------------------------------

    \998\ Similarly, in issuing the Anti-manipulation Rule, we 
declined to provide specific examples of what would constitute 
market manipulation. Order No. 670 at P 64-67.
---------------------------------------------------------------------------

VI. Information Collection Statement

    1752. The Office of Management and Budget (OMB) regulations require 
that OMB approve certain reporting, record keeping, and public 
disclosure (collections of information) imposed by an agency.\999\ 
Pursuant to OMB regulations, the Commission is providing notice of its 
proposed information collections to OMB for review under section 
3507(d) of the Paperwork Reduction Act of 1995.\1000\
---------------------------------------------------------------------------

    \999\ 5 CFR 1320.11.
    \1000\ 44 U.S.C. 3507(d).
---------------------------------------------------------------------------

    1753. The Commission identifies the information provided under Part 
35 subpart C as contained in FERC-516 and Part 37 as contained in FERC-
717. The Commission solicited comments on the need for this 
information, whether the information will have practical utility, ways 
to enhance the quality, utility, and clarity of the information to be 
collected, and any suggested methods for minimizing respondents' 
burden, including the use of automated information exchanges. The 
Commission did not receive any specific comments regarding its burden 
estimates. Where commenters raised concerns that specific information 
collection requirements would be burdensome to implement, the

[[Page 12490]]

Commission has address those concerns elsewhere in the rule.
    1754. The Commission estimates the burden for complying with the 
Final Rule is as follows: \1001\
---------------------------------------------------------------------------

    \1001\ These burden estimates applied only to the Final Rule and 
do not reflect upon all of FERC-516 or FERC-717.

----------------------------------------------------------------------------------------------------------------
                                                     Number of       Number of       Hours per     Total annual
                 Data collection                    respondents      responses       response          hours
----------------------------------------------------------------------------------------------------------------
                                               Part 35 (FERC-516)
----------------------------------------------------------------------------------------------------------------
Conforming tariff changes.......................             116               1              25           2,900
Revision of Imbalance Charges...................             116               1               5             580
ATC revisions...................................             116               1              40           4,640
Planning (Attachment K).........................             116               1             200          23,200
Congestion studies..............................             116               1             300          34,800
Attestation of network resource commitment......             116               1               1             116
Capacity reassignment...........................             116               1             100          11,600
Operational Penalty annual filing...............             116               1              10           1,160
Creditworthiness--include criteria in the tariff             116               1              40           4,640
                                                 ---------------------------------------------------------------
    Sub Total Part 35...........................  ..............  ..............  ..............          83,636
----------------------------------------------------------------------------------------------------------------
                                               Part 37 (FERC-717)
----------------------------------------------------------------------------------------------------------------
ATC-related standards:
    NERC/NAESB Team to develop..................               1               1           1,920           1,920
    Review and comment by utility...............             116               1              20           2,320
    Implementation by each utility..............             116               1              40           4,640
Mandatory data exchanges........................             116               1              80           9,280
Explanation of change of ATC values.............             116               1             100          11,600
Reevaluate CBM and post quarterly...............             116               1              20           2,320
Post OASIS metrics; requests accepted/denied....             116               1              90          10,440
Post planning redispatch offers and reliability              116               1              20           2,320
 redispatch data................................
Post curtailment data...........................             116               1              10          11,160
Post Planning and System Impact Studies.........             116               1               5             580
Posting of metrics for System Impact Studies....             116               1             100          11,600
Post all rules to OASIS.........................             116               1               5             580
    Sub Total (Part 37).........................  ..............  ..............  ..............          68,760
                                                 ---------------------------------------------------------------
        Total (Part 35 + Part 37)...............  ..............  ..............  ..............         140,476
                                                 ---------------------------------------------------------------
Recordkeeping...................................             116               1              40           4,640
----------------------------------------------------------------------------------------------------------------

    1755. Information Collection Costs: No comments were received 
regarding the Commission's estimate of costs to comply with these 
requirements. The Commission has projected costs of compliance as 
follows:
    Total Annual Hours for Collection:
    Reporting + recordkeeping hours = 152,396 + 4,640 = 157,036 hours.
    Cost to Comply:

Reporting = $17,373,144
hour), consultant ($150), technical ($80), and administrative support 
($25))
Recordkeeping = $7,478,888
$78,880
    Storage 8,000 sq. ft. x $925 (off site storage) = $7,400,000
Total costs = $24,852,024
    Labor $ ($17,373,144 + $78,880) + Recordkeeping Storage Costs 
($7,400,000)

    Title: FERC-516, Electric Rate Schedules and Tariff Filings; FERC-
717 Standards for Business Practices and Communication Protocols for 
Public Utilities.
    Action: Proposed Collections.
    OMB Control Nos. 1902-0096 and 1902-0173.
    Respondents: Business or other for profit.
    Frequency of responses: On occasion.
    Necessity of the Information: The Federal Energy Regulatory 
Commission adopts these amendments to its regulations adopted in Order 
Nos. 888 and 889, and to the pro forma open access transmission tariff, 
to ensure that transmission services are provided on a basis that is 
just, reasonable and not unduly discriminatory or preferential. The 
purpose of this rulemaking is to strengthen the pro forma OATT to 
ensure that it achieves its original purpose--remedying undue 
discrimination--not to create new market structures. We propose to 
achieve this goal by increasing the clarity and transparency of the 
rules applicable to the planning and use of the transmission system and 
by addressing ambiguities and the lack of sufficient detail in several 
important areas of the pro forma OATT. The lack of specificity in the 
pro forma OATT creates opportunities for undue discrimination as well 
as making the undue discrimination that does occur more difficult to 
detect. To accomplish this we are proposing five objectives: (1) To 
improve transparency and consistency in several critical areas, by 
providing for greater consistency in the calculation of ATC, (2) to 
reform the transmission planning requirements of the pro forma OATT to 
eliminate potential undue discrimination and support the construction 
of adequate transmission facilities to meet the needs of all LSEs, (3) 
to remedy certain portions of the pro forma OATT that may have 
permitted utilities to

[[Page 12491]]

discriminate against new merchant generation, including intermittent 
generation, (4) to provide for greater transparency in the provision of 
transmission service to allow transmission customers better access to 
information to make their resource procurement and investment 
decisions, as well as to increase the Commission's ability to detect 
any remaining incidents of undue discrimination; and (5) to reform and 
provide greater clarity in areas that have generated recurring disputes 
over the past 10 years, such as rollover rights, ``redirects,'' and 
generation redispatch. The reforms proposed in this Final Rule are 
intended to address deficiencies in the pro forma OATT that have become 
apparent since the implementation of Order No. 888 in 1996 and to 
facilitate improved planning and operation of transmission facilities.
    1756. Interested persons may obtain information on the reporting 
requirements by contacting the following: Federal Energy Regulatory 
Commission, 888 First Street, NE., Washington, DC 20426, Attention: 
Michael Miller, Office of the Executive Director, Phone: (202) 502-
8415, fax: (202) 273-0873, e-mail: michael.miller@ferc.gov.
    1757. For submitting comments concerning the collections of 
information and the associated burden estimate(s), please send your 
comments to the contact listed above and to the Office of Information 
and Regulatory Affairs, Office of Management and Budget, 725 17th 
Street, NW., Washington, DC 20503 Attention: Desk Officer for the 
Federal Energy Regulatory Commission, phone (202) 395-3122, fax: (202) 
395-7285. Due to security concerns, comments should be sent 
electronically to the following e-mail address: 
oira_submission@omb.eop.gov. Please reference the docket number of this 

rulemaking in your submission.

VII. Environmental Analysis

    1758. The Commission is required to prepare an Environmental 
Assessment or an Environmental Impact Statement for any action that may 
have a significant adverse effect on the human environment.\1002\ The 
Commission concludes that neither an Environmental Assessment nor an 
Environmental Impact Statement is required for this Final Rule under 
section 380.4(a)(15) of the Commission's regulations, which provides a 
categorical exemption for approval of actions under sections 205 and 
206 of the FPA relating to the filing of schedules containing all rates 
and charges for the transmission or sale subject to the Commission's 
jurisdiction, plus the classification, practices, contracts and 
regulations that affect rates, charges, classifications and 
services.\1003\
---------------------------------------------------------------------------

    \1002\ Regulations Implementing the National Environmental 
Policy Act, Order No. 486, 52 FR 47897 (Dec. 17, 1987), FERC Stats. 
& Regs. ] 30,783 (1987).
    \1003\ 18 CFR 380.4(a)(15).
---------------------------------------------------------------------------

VIII. Regulatory Flexibility Act Analysis

    1759. The Regulatory Flexibility Act of 1980 (RFA) \1004\ generally 
requires a description and analysis of final rules that will have 
significant economic impact on a substantial number of small entities. 
This rule applies to public utilities that own, control or operate 
interstate transmission facilities other than those that have received 
waiver of the obligation to comply with Order Nos. 888 and 889. The 
total number of public utilities that, absent waiver, would have to 
modify their current OATTs by filing the revised pro forma OATT is 
116.\1005\ Of these only six public utilities, or less than two 
percent, have output of four million MWh or less per year.\1006\ The 
Commission does not consider this a substantial number and, in any 
event, each of these entities retains its rights to waiver of these 
requirements.\1007\ The criteria for waiver that would be applied under 
this rulemaking for small entities is unchanged from that used to 
evaluate requests for waiver under Order Nos. 888 and 889. Accordingly, 
the Commission certifies that the Final Rule will not have a 
significant economic impact on a substantial number of small entities.
---------------------------------------------------------------------------

    \1004\ 5 U.S.C. 601-612.
    \1005\ The Commission has identified 116 transmission providers 
with tariffs on file. We note that this figure is lower than our 
initial estimate in the NOPR, based on FERC Form No. 1 and FERC Form 
No. 1-F data.
    \1006\ Id.
    \1007\ The Regulatory Flexibility Act defines a ``small entity'' 
as ``one which is independently owned and operated and which is not 
dominant in its field of operation.'' See 5 U.S.C. 601(3) and 
601(6); 15 U.S.C. 632(a)(1). In Mid-Tex Elec. Coop. v. FERC, 773 
F.2d 327, 340-43 (D.C. Cir. 1985), the court accepted the 
Commission's conclusion that, since virtually all of the public 
utilities that it regulates do not fall within the meaning of the 
term ``small entities'' as defined in the Regulatory Flexibility 
Act, the Commission did not need to prepare a regulatory flexibility 
analysis in connection with its proposed rule governing the 
allocation of costs for construction work in progress (CWIP). The 
CWIP rules applied to all public utilities. The revised pro forma 
OATT will apply only to those public utilities that own, control or 
operate interstate transmission facilities. These entities are a 
subset of the group of public utilities found not to require 
preparation of a regulatory flexibility analysis for the CWIP rule.
---------------------------------------------------------------------------

IX. Document Availability

    1760. In addition to publishing the full text of this document in 
the Federal Register, the Commission provides all interested persons an 
opportunity to view and/or print the contents of this document via the 
Internet through the Commission's Home Page (http://www.ferc.gov) and 

in the Commission's Public Reference Room during normal business hours 
(8:30 a.m. to 5 p.m. Eastern time) at 888 First Street, NE., Room 2A, 
Washington DC 20426.
    1761. From the Commission's Home Page on the Internet, this 
information is available in the Commission's document management 
system, eLibrary. The full text of this document is available on 
eLibrary in PDF and Microsoft Word format for viewing, printing, and/or 
downloading. To access this document in eLibrary, type ``RM05-25'' or 
``RM05-17'' in the docket number field.
    1762. User assistance is available for eLibrary and the 
Commission's website during normal business hours. For assistance, 
please contact the Commission's Online Support at 1-866-208-3676 (toll 
free) or 202-502-6652 (e-mail at FERCOnlineSupport@FERC.gov), or the 
Public Reference Room at 202-502-8371, TTY 202-502-8659 (e-mail at 
public.referenceroom@ferc.gov).


X. Effective Date and Congressional Notification

    1763. These regulations are effective May 14, 2007. The Commission 
has determined, with the concurrence of the Administrator of the Office 
of Information and Regulatory Affairs of OMB, that this rule is not a 
``major rule'' as defined in section 351 of the Small Business 
Regulatory Enforcement Fairness Act of 1996. The Commission will submit 
the Final Rule to both houses of Congress and to the General Accounting 
Office.

List of Subjects

18 CFR Part 35

    Electric power rates, Electric utilities, Reporting and 
recordkeeping requirements.

18 CFR Part 37

    Conflict of interests, Electric power plants, Electric utilities, 
Reporting and recordkeeping requirements.

    By the Commission.
Magalie R. Salas,
Secretary.

0
In consideration of the foregoing, the Commission amends parts 35 and 
37,

[[Page 12492]]

Chapter I, Title 18 of the Code of Federal Regulations, as follows:

PART 35--FILING OF RATE SCHEDULES AND TARIFFS

0
1. The authority citation for part 35 continues to read as follows:

    Authority: 16 U.S.C. 791a-825r, 2601-2645; 31 U.S.C. 9701; 42 
U.S.C. 71-7352.


0
2. Amend Sec.  35.28 as follows:
0
a. Paragraph (c) is revised.
0
b. Paragraphs (d)(i) and (d)(ii) are redesignated as paragraphs (d)(1) 
and (d)(2).
0
c. Newly redesignated paragraph (d)(1) is revised.
0
d. Paragraph (e)(1) introductory text is revised.
0
e. Paragraph (e)(1)(ii) is revised.


Sec.  35.28  Non-discriminatory open access transmission tariff.

* * * * *
    (c) Non-discriminatory open access transmission tariffs. (1) Every 
public utility that owns, controls, or operates facilities used for the 
transmission of electric energy in interstate commerce must have on 
file with the Commission a tariff of general applicability for 
transmission services, including ancillary services, over such 
facilities. Such tariff must be the open access pro forma tariff 
contained in Order No. 888, FERC Stats. & Regs. ] 31,036 (Final Rule on 
Open Access and Stranded Costs), as revised by the open access pro 
forma tariff contained in Order No. 890, FERC Stats. & Regs. ] 31,241 
(Final Rule on Open Access Reforms), or such other open access tariff 
as may be approved by the Commission consistent with Order No. 888, 
FERC Stats. & Regs ] 31,306 and Order No. 890, FERC Stats. & Regs. ] 
31,241.
    (i) Subject to the exceptions in paragraphs (c)(1)(ii), 
(c)(1)(iii), (c)(1)(iv) and (c)(1)(v) of this section, the pro forma 
tariff contained in Order No. 888, FERC Stats. & Regs. ] 31,036, as 
revised by the open access pro forma tariff contained in Order No. 890, 
FERC Stats. & Regs. ] 31,241, and accompanying rates, must be filed no 
later than 60 days prior to the date on which a public utility would 
engage in a sale of electric energy at wholesale in interstate commerce 
or in the transmission of electric energy in interstate commerce.
    (ii) If a public utility owns, controls, or operates facilities 
used for the transmission of electric energy in interstate commerce as 
of May 14, 2007, it must file the revisions to the pro forma tariff 
contained in Order No. 890, FERC Stats. & Regs. ] 31,241, pursuant to 
section 206 of the FPA and accompanying rates pursuant to section 205 
of the FPA in accordance with the procedures set forth in Order No. 
890, FERC Stats. & Regs ] 31,241.
    (iii) If a public utility owns, controls, or operates transmission 
facilities used for the transmission of electric energy in interstate 
commerce as of May 14, 2007, such facilities are jointly owned with a 
non-public utility, and the joint ownership contract prohibits 
transmission service over the facilities to third parties, the public 
utility with respect to access over the public utility's share of the 
jointly owned facilities must file no later than May 14, 2007 the 
revisions to the pro forma tariff contained in Order No. 890, FERC 
Stats. & Regs. ] 31,241, pursuant to section 206 of the FPA and 
accompanying rates pursuant to section 205 of the FPA.
    (iv) Any public utility whose transmission facilities are under the 
independent control of a Commission-approved ISO or RTO may satisfy its 
obligation under paragraph (c)(1) of this section, with respect to such 
facilities, through the open access transmission tariff filed by the 
ISO or RTO.
    (v) If a public utility obtains a waiver of the tariff requirement 
pursuant to paragraph (d) of this section, it does not need to file the 
pro forma tariff required by this section.
    (vi) Any public utility that seeks a deviation from the pro forma 
tariff contained in Order No. 888, FERC Stats. & Regs. ] 31,036, as 
revised in Order No. 890, FERC Stats. & Regs. ] 31,241, must 
demonstrate that the deviation is consistent with the principles of 
Order No. 888, FERC Stats. & Regs ] 31,036 and Order No. 890, FERC 
Stats. & Regs. ] 31,241.
    (vii) Each public utility's open access transmission tariff must 
include the standards incorporated by reference in part 38 of this 
chapter.
    (2) Subject to the exceptions in paragraphs (c)(2)(i) and 
(c)(3)(iii) of this section, every public utility that owns, controls, 
or operates facilities used for the transmission of electric energy in 
interstate commerce, and that uses those facilities to engage in 
wholesale sales and/or purchases of electric energy, or unbundled 
retail sales of electric energy, must take transmission service for 
such sales and/or purchases under the open access transmission tariff 
filed pursuant to this section.
    (i) For sales of electric energy pursuant to a requirements service 
agreement executed on or before July 9, 1996, this requirement will not 
apply unless separately ordered by the Commission. For sales of 
electric energy pursuant to a bilateral economy energy coordination 
agreement executed on or before July 9, 1996, this requirement is 
effective on December 31, 1996. For sales of electric energy pursuant 
to a bilateral non-economy energy coordination agreement executed on or 
before July 9, 1996, this requirement will not apply unless separately 
ordered by the Commission.
    (ii) [Reserved.]
    (3) Every public utility that owns, controls, or operates 
facilities used for the transmission of electric energy in interstate 
commerce, and that is a member of a power pool, public utility holding 
company, or other multi-lateral trading arrangement or agreement that 
contains transmission rates, terms or conditions, must have on file a 
joint pool-wide or system-wide open access transmission tariff, which 
tariff must be the pro forma tariff contained in Order No. 888, FERC 
Stats. & Regs. ] 31,036, as revised by the pro forma tariff contained 
in Order No. 890, FERC Stats. & Regs. ] 31,241, or such other open 
access tariff as may be approved by the Commission consistent with 
Order No. 888, FERC Stats. & Regs. ] 31,036 and Order No. 890, FERC 
Stats. & Regs. ] 31,241.
    (i) For any power pool, public utility holding company or other 
multi-lateral arrangement or agreement that contains transmission 
rates, terms or conditions and that is executed after May 14, 2007, 
this requirement is effective on the date that transactions begin under 
the arrangement or agreement.
    (ii) For any power pool, public utility holding company or other 
multi-lateral arrangement or agreement that contains transmission 
rates, terms or conditions and that is executed on or before May 14, 
2007, a public utility member of such power pool, public utility 
holding company or other multi-lateral arrangement or agreement that 
owns, controls, or operates facilities used for the transmission of 
electric energy in interstate commerce must file the revisions to its 
joint pool-wide or system-wide contained in Order No. 890, FERC Stats. 
& Regs. ] 31,241, pursuant to section 206 of the FPA and accompanying 
rates pursuant to section 205 of the FPA in accordance with the 
procedures set forth in Order No. 890, FERC Stats. & Regs ] 31,241.
    (iii) A public utility member of a power pool, public utility 
holding company or other multi-lateral arrangement or agreement that 
contains transmission rates, terms or conditions and that is executed 
on or before July 9, 1996 must take transmission service under a joint 
pool-wide or system-wide open access transmission tariff filed pursuant 
to this section for wholesale trades among the pool or system members.

[[Page 12493]]

    (4) Consistent with paragraph (c)(1) of this section, every 
Commission-approved ISO or RTO must have on file with the Commission a 
tariff of general applicability for transmission services, including 
ancillary services, over such facilities. Such tariff must be the pro 
forma tariff contained in Order No. 888, FERC Stats. & Regs. ] 31,036, 
as revised by the pro forma tariff contained in Order No. 890, FERC 
Stats. & Regs. ] 31,241, or such other open access tariff as may be 
approved by the Commission consistent with Order No. 888, FERC Stats. & 
Reg. ] 31,036 and Order No. 890, FERC Stats. & Regs. ] 31,241.
    (i) Subject to paragraph (c)(4)(ii) of this section, a Commission-
approved ISO or RTO must file the revisions to the pro forma tariff 
contained in Order No. 890, FERC Stats. & Regs. ] 31,241, pursuant to 
section 206 of the FPA and accompanying rates pursuant to section 205 
of the FPA in accordance with the procedures set forth in Order No. 
890, FERC Stats. & Regs ] 31,241.
    (ii) If a Commission-approved ISO or RTO can demonstrate that its 
existing open access tariff is consistent with or superior to the 
revisions to the pro forma tariff contained in Order No. 888, FERC 
Stats. & Regs. ] 31,036, as revised by the pro forma tariff in Order 
No. 890, FERC Stats. & Regs. ] 31,241, or any portions thereof, the 
Commission-approved ISO or RTO may instead set forth such demonstration 
in its filing pursuant to section 206 in accordance with the procedures 
set forth in Order No. 890, FERC Stats. & Regs ] 31,241.
    (d) Waivers. * * *
    (1) No later than May 14, 2007, or
* * * * *
    (e) Non-public utility procedures for tariff reciprocity 
compliance. (1) A non-public utility may submit a transmission tariff 
and a request for declaratory order that its voluntary transmission 
tariff meets the requirements of Order No. 888, FERC Stats. & Regs. ] 
31,036 and Order No. 890, FERC Stats. & Regs. ] 31,241.
* * * * *
    (ii) If the submittal is found to be an acceptable transmission 
tariff, an applicant in a Federal Power Act (FPA) section 211 or 211A 
proceeding against the non-public utility shall have the burden of 
proof to show why service under the open access tariff is not 
sufficient and why a section 211 or 211A order should be granted.
* * * * *

PART 37--OPEN ACCESS SAME-TIME INFORMATION SYSTEMS

0
3. The authority citation for part 37 continues to read as follows:

    Authority: 16 U.S.C. 791-825r, 2601-2645; 31 U.S.C. 9701; 42 
U.S.C. 7101-7352.


0
4. Amend Sec.  37.6 as follows:
0
a. Paragraph (a)(1) is revised.
0
b. Paragraph (b) introductory text is revised.
0
c. Paragraphs (b)(1)(v) through (b)(1)(viii) are added.
0
d. Paragraphs (b)(2)(i) through (b)(2)(iii) are revised.
0
e. Paragraph (b)(3) is revised.
0
f. Paragraphs (c)(2) and (c)(5) are revised.
0
g. Paragraphs (e)(1) and (e)(2)(ii) are revised.
0
h. Paragraph (e)(3)(ii) is revised.
0
i. Paragraphs (h), (i) and (j) are added.


Sec.  37.6  Information to be posted on the OASIS.

    (a) * * *
    (1) Make requests for transmission services offered by Transmission 
Providers, Resellers and other providers of ancillary services, request 
the designation of a network resource, and request the termination of 
the designation of a network resource;
* * * * *
    (b) Posting transfer capability. The available transfer capability 
on the Transmission Provider's system (ATC) and the total transfer 
capability (TTC) of that system shall be calculated and posted for each 
Posted Path as set out in this section.
    (1) * * *
    (v) Available transfer capability or ATC means the transfer 
capability remaining in the physical transmission network for further 
commercial activity over and above already committed uses, or such 
definition as contained in Commission-approved Reliability Standards.
    (vi) Total transfer capability or TTC means the amount of electric 
power that can be moved or transferred reliably from one area to 
another area of the interconnected transmission systems by way of all 
transmission lines (or paths) between those areas under specified 
system conditions, or such definition as contained in Commission-
approved Reliability Standards.
    (vii) Capacity Benefit Margin or CBM means the amount of TTC 
preserved by the Transmission Provider for load-serving entities, whose 
loads are located on that Transmission Provider's system, to enable 
access by the load-serving entities to generation from interconnected 
systems to meet generation reliability requirements, or such definition 
as contained in Commission-approved Reliability Standards.
    (viii) Transmission Reliability Margin or TRM means the amount of 
TTC necessary to provide reasonable assurance that the interconnected 
transmission network will be secure, or such definition as contained in 
Commission-approved Reliability Standards.
    (2) * * *
    (i) Information used to calculate any posting of ATC and TTC must 
be dated and time-stamped and all calculations shall be performed 
according to consistently applied methodologies referenced in the 
Transmission Provider's transmission tariff and shall be based on 
Commission-approved Reliability Standards as well as current industry 
practices, standards and criteria.
    (ii) On request, the Responsible Party must make all data used to 
calculate ATC, TTC, CBM, and TRM for any constrained posted paths 
publicly available (including the limiting element(s) and the cause of 
the limit (e.g., thermal, voltage, stability), as well as load forecast 
assumptions) in electronic form within one week of the posting. The 
information is required to be provided only in the electronic format in 
which it was created, along with any necessary decoding instructions, 
at a cost limited to the cost of reproducing the material. This 
information is to be retained for six months after the applicable 
posting period.
    (iii) System planning studies, facilities studies, and specific 
network impact studies performed for customers or the Transmission 
Provider's own network resources are to be made publicly available in 
electronic form on request and a list of such studies shall be posted 
on the OASIS. A study is required to be provided only in the electronic 
format in which it was created, along with any necessary decoding 
instructions, at a cost limited to the cost of reproducing the 
material. These studies are to be retained for five years.
    (3) Posting. The ATC, TTC, CBM, and TRM for all Posted Paths must 
be posted in megawatts by specific direction and in the manner 
prescribed in this subsection.
    (i) Constrained posted paths.--(A) For firm ATC and TTC.
    (1) The posting shall show ATC, TTC, CBM, and TRM for a 30-day 
period. For this period postings shall be: by the hour, for the current 
hour and the 168 hours next following; and thereafter, by the day. If 
the Transmission Provider charges separately for on-peak and off-peak 
periods in its tariff, ATC, TTC, CBM, and TRM will be posted daily for 
each period.

[[Page 12494]]

    (2) Postings shall also be made by the month, showing for the 
current month and the 12 months next following.
    (3) If planning and specific requested transmission studies have 
been done, seasonal capability shall be posted for the year following 
the current year and for each year following to the end of the planning 
horizon but not to exceed 10 years.
    (B) For non-firm ATC and TTC. The posting shall show ATC, TTC, CBM 
and TRM for a 30-day period by the hour and days prescribed under 
paragraph (b)(3)(i)(A)(1) of this section and, if so requested, by the 
month and year as prescribed under paragraph (b)(3)(i)(A) (2) and (3) 
of this section. The posting of non-firm ATC and TTC shall show CBM as 
zero.
    (C) Updating posted information for constrained paths.
    (1) The capability posted under paragraphs (b)(3)(i)(A) and (B) of 
this section must be updated when transactions are reserved or service 
ends or whenever the estimate for the path changes by more than 10 
percent.
    (2) All updating of hourly information shall be made on the hour.
    (3) When the monthly and yearly capability posted under paragraphs 
(b)(3)(i)(A) and (B) of this section are updated because of a change in 
TTC by more than 10 percent, the Transmission Provider shall post a 
brief, but specific, narrative explanation of the reason for the 
update. This narrative should include, the specific events which gave 
rise to the update (e.g., scheduling of planned outages and occurrence 
of forced transmission outages, de-ratings of transmission facilities, 
scheduling of planned generation outages and occurrence of forced 
generation outages, changes in load forecast, changes in new 
facilities' in-service dates, or other events or assumption changes) 
and new values for ATC on the path (as opposed to all points on the 
network).
    (4) When the monthly and yearly capability posted under paragraphs 
(b)(3)(i)(A) and (B) of this section remain unchanged at a value of 
zero for a period of six months, the Transmission Provider shall post a 
brief, but specific, narrative explanation of the reason for the 
unavailability of ATC.
    (ii) Unconstrained posted paths.
    (A) Postings of firm and nonfirm ATC, TTC, CBM, and TRM shall be 
posted separately by the day, showing for the current day and the next 
six days following and thereafter, by the month for the 12 months next 
following. If the Transmission Provider charges separately for on-peak 
and off-peak periods in its tariff, ATC, TTC, CBM, and TRM will be 
posted separately for the current day and the next six days following 
for each period. These postings are to be updated whenever the ATC 
changes by more than 20 percent of the Path's TTC.
    (B) If planning and specific requested transmission studies have 
been done, seasonal capability shall be posted for the year following 
the current year and for each year following until the end of the 
planning horizon but not to exceed 10 years.
    (iii) Calculation of CBM.
    (A) The Transmission Provider must reevaluate its CBM needs at 
least every year.
    (B) The Transmission Provider must post its practices for 
reevaluating its CBM needs.
    (iv) Daily load. The Transmission Provider must post on a daily 
basis, its actual daily peak load for the prior day.
    (c) * * *
    (2) Transmission Providers must provide a downloadable file of 
their complete tariffs in the same electronic format as the tariff that 
is filed with the Commission. Transmission Providers also must provide 
a link to all of the rules, standards and practices that relate to 
transmission services posted on the Transmission Providers' public Web 
sites.
* * * * *
    (5) Customers choosing to use the OASIS to offer for resale 
transmission capacity they have purchased must post relevant 
information to the same OASIS as used by the Transmission Provider from 
whom the Reseller purchased the transmission capacity. This information 
must be posted on the same display page, using the same tables, as 
similar capability being sold by the Transmission Provider, and the 
information must be contained in the same downloadable files as the 
Transmission Provider's own available capability.
* * * * *
    (e) Posting specific transmission and ancillary service requests 
and responses.
    (1) General rules.
    (i) All requests for transmission and ancillary service offered by 
Transmission Providers under the pro forma tariff, including requests 
for discounts, and all requests to designate or terminate a network 
resource, must be made on the OASIS and posted prior to the 
Transmission Provider responding to the request, except as discussed in 
paragraphs (e)(1)(ii) and (iii) of this section. The Transmission 
Provider must post all requests for transmission service, for ancillary 
service, and for the designation or termination of a network resource 
comparably. Requests for transmission service, ancillary service, and 
to designate and terminate a network resource, as well as the responses 
to such requests, must be conducted in accordance with the Transmission 
Provider's tariff, the Federal Power Act, and Commission regulations.
    (ii) The requirement in paragraph (e)(1)(i) of this section, to 
post requests for transmission and ancillary service offered by 
Transmission Providers under the pro forma tariff, including requests 
for discounts, prior to the Transmission Provider responding to the 
request, does not apply to requests for next-hour service made during 
Phase I.
    (iii) In the event that a discount is being requested for ancillary 
services that are not in support of basic transmission service provided 
by the Transmission Provider, such request need not be posted on the 
OASIS.
    (iv) In processing a request for transmission or ancillary service, 
the Responsible Party shall post the same information as required in 
paragraphs (c)(4) and (d)(3) of this section, and the following 
information: the date and time when the request is made, its place in 
any queue, the status of that request, and the result (accepted, 
denied, withdrawn). In processing a request to designate or terminate 
the designation of a network resource, the Responsible Party shall post 
the date and time when the request is made.
    (v) For any request to designate or terminate a network resource, 
the Transmission Provider (at the time when the request is received), 
must post on the OASIS (and make available for download) information 
describing the request (including: name of requestor, identification of 
the resource, effective time for the designation or termination, 
identification of whether the transaction involves the Transmission 
Provider's wholesale merchant function or any affiliate; and any other 
relevant terms and conditions) and shall keep such information posted 
on the OASIS for at least 30 days. A record of the transaction must be 
retained and kept available as part of the audit log required in Sec.  
37.7.
    (vi) The Transmission Provider shall post a list of its current 
designated network resources and all network customers' current 
designated network resources on OASIS. The list of network resources 
should include the name of the resource, its geographic and electrical 
location, its total installed capacity, and the amount of capacity to 
be designated as a network resource.
    (2) * * *

[[Page 12495]]

    (ii) Information to support the reason for the denial, including 
the operating status of relevant facilities, must be maintained for 
five years and provided, upon request, to the potential Transmission 
Customer and the Commission's Staff.
* * * * *
    (3) * * *
    (ii) Information to support any such curtailment or interruption, 
including the operating status of the facilities involved in the 
constraint or interruption, must be maintained and made available upon 
request, to the curtailed or interrupted customer, the Commission's 
Staff, and any other person who requests it, for five years.
* * * * *
    (h) Posting information summarizing the time to complete 
transmission service request studies. (1) For each calendar quarter, 
the Responsible Party must post the set of measures detailed in 
paragraph (h)(1)(i) through paragraph (h)(1)(vi) of this section 
related to the Responsible Party's processing of transmission service 
request system impact studies and facilities studies. The Responsible 
Party must calculate and post the measures in paragraph (h)(1)(i) 
through paragraph (h)(1)(vi) of this section separately for requests 
for short-term firm point-to-point transmission service, long-term firm 
point-to-point transmission service, and requests to designate a new 
network resource and must be calculated and posted separately for 
transmission service requests from Affiliates and transmission service 
requests from Transmission Customers who are not Affiliates. The 
Responsible Party is required to include in the calculations of the 
measures in paragraph (h)(1)(i) through paragraph (h)(1)(vi) of this 
section all studies the Responsible Party conducts of transmission 
service requests on another Transmission Provider's OASIS.
    (i) Process time from initial service request to offer of system 
impact study agreement.
    (A) Number of new system impact study agreements delivered during 
the reporting quarter to entities that request transmission service,
    (B) Number of new system impact study agreements delivered during 
the reporting quarter to entities that request transmission service 
more than thirty (30) days after the Responsible Party received the 
request for transmission service,
    (C) Mean time (in days), for all requests acted on by the 
Responsible Party during the reporting quarter, from the date when the 
Responsible Party received the request for transmission service to when 
the Responsible Party changed the transmission service request status 
to indicate that the Responsible Party could offer transmission service 
or needed to perform a system impact study,
    (D) Mean time (in days), for all system impact study agreements 
delivered by the Responsible Party during the reporting quarter, from 
the date when the Responsible Party received the request for 
transmission service to the date when the Responsible Party delivered a 
system impact study agreement, and
    (E) Number of new system impact study agreements executed during 
the reporting quarter.
    (ii) System impact study processing time.
    (A) Number of system impact studies completed by the Responsible 
Party during the reporting quarter,
    (B) Number of system impact studies completed by the Responsible 
Party during the reporting quarter more than 60 days after the 
Responsible Party received an executed system impact study agreement,
    (C) For all system impact studies completed more than 60 days after 
receipt of an executed system impact study agreement, average number of 
days study was delayed due to transmission customer's actions (e.g., 
delays in providing needed data),
    (D) Mean time (in days), for all system impact studies completed by 
the Responsible Party during the reporting quarter, from the date when 
the Responsible Party received the executed system impact study 
agreement to the date when the Responsible Party provided the system 
impact study to the entity who executed the system impact study 
agreement, and
    (E) Mean cost of system impact studies completed by the Responsible 
Party during the reporting quarter.
    (iii) Transmission service requests withdrawn from the system 
impact study queue.
    (A) Number of transmission service requests withdrawn from the 
Responsible Party's system impact study queue during the reporting 
quarter,
    (B) Number of transmission service requests withdrawn from the 
Responsible Party's system impact study queue during the reporting 
quarter more than 60 days after the Responsible Party received the 
executed system impact study agreement, and
    (C) Mean time (in days), for all transmission service requests 
withdrawn from the Responsible Party's system impact study queue during 
the reporting quarter, from the date the Responsible Party received the 
executed system impact study agreement to date when request was 
withdrawn from the Responsible Party's system impact study queue.
    (iv) Process time from completed system impact study to offer of 
facilities study.
    (A) Number of new facilities study agreements delivered during the 
reporting quarter to entities that request transmission service,
    (B) Number of new facilities study agreements delivered during the 
reporting quarter to entities that request transmission service more 
than thirty (30) days after the Responsible Party completed the system 
impact study,
    (C) Mean time (in days), for all facilities study agreements 
delivered by the Responsible Party during the reporting quarter, from 
the date when the Responsible Party completed the system impact study 
to the date when the Responsible Party delivered a facilities study 
agreement, and
    (D) Number of new facilities study agreements executed during the 
reporting quarter.
    (v) Facilities study processing time.
    (A) Number of facilities studies completed by the Responsible Party 
during the reporting quarter,
    (B) Number of facilities studies completed by the Responsible Party 
during the reporting quarter more than 60 days after the Responsible 
Party received an executed facilities study agreement,
    (C) For all facilities studies completed more than 60 days after 
receipt of an executed facilities study agreement, average number of 
days study was delayed due to transmission customer's actions (e.g., 
delays in providing needed data),
    (D) Mean time (in days), for all facilities studies completed by 
the Responsible Party during the reporting quarter, from the date when 
the Responsible Party received the executed facilities study agreement 
to the date when the Responsible Party provided the facilities study to 
the entity who executed the facilities study agreement,
    (E) Mean cost of facilities studies completed by the Responsible 
Party during the reporting quarter, and
    (F) Mean cost of upgrades recommended in facilities studies 
completed during the reporting quarter.
    (vi) Service requests withdrawn from facilities study queue.
    (A) Number of transmission service requests withdrawn from the 
Responsible Party's facilities study queue during the reporting 
quarter,
    (B) Number of transmission service requests withdrawn from the

[[Page 12496]]

Responsible Party's facilities study queue during the reporting quarter 
more than 60 days after the Responsible Party received the executed 
facilities study agreement, and
    (C) Mean time (in days), for all transmission service requests 
withdrawn from the Responsible Party's facilities study queue during 
the reporting quarter, from the date the Responsible Party received the 
executed facilities study agreement to date when request was withdrawn 
from the Responsible Party's facilities study queue.
    (2) The Responsible Party is required to post the measures in 
paragraph (h)(1)(i) through paragraph (h)(1)(vi) of this section for 
each calendar quarter within 15 days of the end of the calendar 
quarter. The Responsible Party will keep the quarterly measures posted 
on OASIS for three calendar years.
    (3) The Responsible Party will be required to post on OASIS the 
measures in paragraph (h)(3)(i) through paragraph (h)(3)(iv) of this 
section in the event the Responsible Party, for two consecutive 
calendar quarters, completes more than twenty (20) percent of the 
studies associated with requests for transmission service from entities 
that are not Affiliates of the Responsible Party more than sixty (60) 
days after the Responsible Party delivers the appropriate study 
agreement. The Responsible Party will have to post the measures in 
paragraph (h)(3)(i) through paragraph (h)(3)(iv) of this section until 
it processes at least ninety (90) percent of all studies within 60 days 
after it has received the appropriate executed study agreement. For the 
purposes of calculating the percent of studies completed more than 
sixty (60) days after the Responsible Party delivers the appropriate 
study agreement, the Responsible Party should aggregate all system 
impact studies and facilities studies that it completes during the 
reporting quarter. The Responsible Party must calculate and post the 
measures in paragraph (h)(3)(i) through paragraph (h)(3)(iv) of this 
section separately for requests for short-term firm point-to-point 
transmission service, long-term firm point-to-point transmission 
service, and requests to designate a new network resource and must be 
calculated and posted separately for transmission service requests from 
Affiliates and transmission service requests from Transmission 
Customers who are not Affiliates.
    (i) Mean, across all system impact studies the Responsible Party 
completes during the reporting quarter, of the employee-hours expended 
per system impact study the Responsible Party completes during 
reporting period;
    (ii) Mean, across all facilities studies the Responsible Party 
completes during the reporting quarter, of the employee-hours expended 
per facilities study the Responsible Party completes during reporting 
period;
    (iii) The number of employees the Responsible Party has assigned to 
process system impact studies;
    (iv) The number of employees the Responsible Party has assigned to 
process facilities studies.
    (4) The Responsible Party is required to post the measures in 
paragraph (h)(3)(i) through paragraph (h)(3)(iv) of this section for 
each calendar quarter within 15 days of the end of the calendar 
quarter. The Responsible Party will keep the quarterly measures posted 
on OASIS for five calendar years.
    (i) Posting data related to grants and denials of service. The 
Responsible Party is required to post data each month listing, by path 
or flowgate, the number of transmission service requests that have been 
accepted and the number of transmission service requests that have been 
denied during the prior month. This posting must distinguish between 
the length of the service request (e.g., short-term or long-term 
requests) and between the type of service requested (e.g., firm point-
to-point, non-firm point-to-point or network service). The posted data 
must show:
    (1) The number of non-Affiliate requests for transmission service 
that have been rejected,
    (2) The total number of non-Affiliate requests for transmission 
service that have been made,
    (3) The number of Affiliate requests for transmission service that 
have been rejected, and
    (4) The total number of Affiliate requests for transmission service 
that have been made.
    (j) Posting redispatch data.
    (1) The Transmission Provider must allow the posting on OASIS of 
any third party offer to relieve a specified congested transmission 
facility.
    (2) The Transmission Provider must post on OASIS (i) its monthly 
average cost of planning and reliability redispatch, for which it 
invoices customers, at each internal transmission facility or interface 
over which it provides redispatch service and (ii) a high and low 
redispatch cost for the month for each of these same transmission 
facilities. The transmission provider must post this data on OASIS as 
soon as practical after the end of each month, but no later than when 
it sends invoices to transmission customers for redispatch-related 
services.


0
5. In Sec.  37.7, paragraph (b) is revised to read as follows:


Sec.  37.7  Auditing Transmission Service Information.

* * * * *
    (b) Audit data must remain available for download on the OASIS for 
90 days, except ATC/TTC postings that must remain available for 
download on the OASIS for 20 days. The audit data are to be retained 
and made available upon request for download for five years from the 
date when they are first posted in the same electronic form as used 
when they originally were posted on the OASIS.

    Note: The following appendices will not be published in the Code 
of Federal Regulations.

Appendix A: Summary of Compliance Filing Requirements

    For a more detailed description of compliance obligations please 
refer to the Final Rule paragraph number. For further information 
related to the Final Rule, such as electronic versions of the pro forma 
OATT showing tariff changes adopted in the Final Rule in redline/
strikeout format, and further information regarding docketing of 
compliance filings and specific filing instructions, please visit our 
Web site at the following location http://www.ferc.gov/industries/electric/indus-act/oatt-reform.asp
.


----------------------------------------------------------------------------------------------------------------
  Deadline (days after publication in Federal                                                       Final rule
                   Register)                                    Compliance action                  paragraph No.
----------------------------------------------------------------------------------------------------------------
30............................................  Optional Implementation FPA section 205 filings            P 139
                                                 allowing transmission providers to propose
                                                 previously approved variations from the pro
                                                 forma OATT that have been affected by pro forma
                                                 OATT Final Rule reforms to remain in effect
                                                 subject to a demonstration that such variations
                                                 continue to be consistent with or superior to
                                                 the revised Final Rule pro forma OATT (non RTO/
                                                 ISO transmission providers). Such optional
                                                 filings must request a 90 day effective date to
                                                 facilitate Commission review under section 205.

[[Page 12497]]


60............................................  Non-ISO/RTO transmission providers submit FPA              P 135
                                                 section 206 filings that contain the non-rate
                                                 terms and conditions set forth in Final Rule.
                                                 These filings need only contain the revised
                                                 provisions adopted in the Final Rule.
                                                 Transmission providers utilizing the optional
                                                 Implementation FPA section 205 filing described
                                                 above, need only submit tariff sheets necessary
                                                 to implement the remaining modifications
                                                 required under the Final Rule, i.e.,
                                                 modifications related to tariff provisions that
                                                 did not implicate previously-approved
                                                 variations.
75............................................  Transmission Providers must post a ``strawman''            P 443
                                                 proposal for compliance with each of the nine
                                                 planning principles adopted in the Final Rule.
                                                 This may be posted on the Transmission
                                                 Providers Web site or its OASIS site.
90............................................  NERC/NAESB status report and work plan for                 P 223
                                                 completion of ATC related business practices
                                                 and standards.
                                                NAESB status report and work plan for completion           P 141
                                                 of OASIS functionality or uniform business
                                                 practices (other than those related to ATC).
120...........................................  Transmission Providers must submit redesigned              P 263
                                                 transmission charges that reflect the Capacity
                                                 Benefit Margin set-aside through a limited
                                                 issue section 205 rate filing as part of their
                                                 initial ATC related compliance filings.
180...........................................  Submit compliance filings with Attachment C                P 140
                                                 (ATC) of the pro forma OATT.
210...........................................  ISOs and RTOs, and transmission providers           P 157, P 161
                                                 located within an ISO/RTO footprint, submit FPA
                                                 section 206 filings that contain the non-rate
                                                 terms and conditions set forth in the Final
                                                 Rule. These filings need only contain the
                                                 revised provisions adopted in the Final Rule or
                                                 a demonstration that previously approved
                                                 variations continue to be consistent with or
                                                 superior to the revised pro forma OATT.
210...........................................  Submit compliance filings with Attachment K         P 140, P 442
                                                 (Planning) of the pro forma OATT or RTOs and
                                                 ISOs file a demonstration that their planning
                                                 processes are consistent with or superior to
                                                 the planning principles in the Final Rule.
N/A...........................................  Transmission Providers must file a revised                 P 325
                                                 Attachment C to incorporate any changes to
                                                 NERC's and NAESB's reliability and business
                                                 practice standards to achieve consistency in
                                                 ATC within 60 days of completion of the NERC
                                                 and NAESB processes.
N/A...........................................  After the submission of FPA section 206                    P 135
                                                 compliance filings, transmission providers may
                                                 submit FPA section 205 filings proposing rates
                                                 for the services provided for in the tariff, as
                                                 well as non-rate terms and conditions that
                                                 differ from those set forth in the Final Rule
                                                 if those provisions are ``consistent with or
                                                 superior to'' the pro forma OATT.
----------------------------------------------------------------------------------------------------------------

Appendix B: Commenting Party Acronyms

                           Initial Commenters
------------------------------------------------------------------------
           Abbreviation                      Initial commenters
------------------------------------------------------------------------
Alberta Intervenors...............  Alberta Intervenors (TransCanada
                                     Energy Ltd., ENMAX Energy
                                     Marketing, Inc.; EPCOR Merchant and
                                     Capital, LP; and TransAlta
                                     Corporation).
Alcoa.............................  Alcoa Inc. and Alcoa Power
                                     Generating Inc.
Allegheny.........................  Allegheny Power and Allegheny Energy
                                     Supply Company, LLC.
Ameren............................  Ameren Services Company.
American Transmission.............  American Transmission Company LLC.
AMP-Ohio..........................  American Municipal Power-Ohio, Inc.
Anaheim...........................  Cities of Anaheim, Azusa, Banning,
                                     Colton, Pasadena, and Riverside,
                                     California.
APPA..............................  American Public Power Association.
ARC...............................  Alliance for Retail Choice.
Arkansas Commission...............  Arkansas Public Service Commission.
Arkansas Municipal................  Arkansas Municipal Power
                                     Association.
AWEA..............................  American Wind Energy Association.
Barrick...........................  Barrick Goldstrike Mines Inc.
BART..............................  San Francisco Bay Area Rapid Transit
                                     District.
Bonneville........................  Bonneville Power Administration.
BP Energy.........................  BP Energy Company.
Bureau of Reclamation.............  U.S. Bureau of Reclamation.
CAC/EPUC..........................  Cogeneration Association of
                                     California (Coalinga Cogeneration
                                     Co., Mid-Set Cogeneration Co., Kern
                                     River Cogeneration Co., Sycamore
                                     Cogeneration Co., Sargent Canyon
                                     Cogeneration Co., Salinas River
                                     Cogeneration Co., Midwest Sunset
                                     Cogeneration Co. and Watson
                                     Cogeneration Co.) and Energy
                                     Producers and Users Coalition (Aera
                                     Energy LLC, BP American, Inc.,
                                     Chevron USA, Inc., ConocoPhilips
                                     Co., ExxonMobil Power and Gas
                                     Services, Inc., Shell Oil Products,
                                     US, THUMS Long Beach Co.,
                                     Occidental Elk Hills, Inc., and
                                     Valero Refining Co.--California).
CAISO.............................  California Independent System
                                     Operator Corporation.
California Commission.............  Public Utilities Commission of the
                                     State of California.
Calpine...........................  Calpine Corporation.
Chandley-Hogan....................  John D. Chandley and William W.
                                     Hogan.

[[Page 12498]]


ColumbiaGrid......................  ColumbiaGrid Members (Bonneville
                                     Power Administration; Avista Corp.;
                                     Public Utility District No. 1 of
                                     Chelan County, Washington; Public
                                     Utility District No. 2 of Grant
                                     County, Washington; Puget Sound
                                     Energy, Inc.; Seattle City Light;
                                     and Tacoma Power.
Community Power Alliance..........  Community Power Alliance Members
                                     (Entergy, Progress Energy, Salt
                                     River Project Agricultural
                                     Improvement and Power District, and
                                     Southern Co.).
Constellation.....................  Constellation Energy Group, Inc.
CREPC.............................  Committee on Regional Electric Power
                                     Corp.
Dominion..........................  Dominion Resources Services, Inc.
                                     (Armstrong Energy Limited
                                     Partnership, LLLP; Dominion Energy
                                     Marketing, Inc.; Elwood Energy,
                                     LLC; Fairless Energy, LLC;
                                     Pleasants Energy, LLC and Virginia
                                     Electric and Power Co. d/b/a
                                     Dominion Virginia Power).
Dow...............................  Dow Chemical Corp.
Duke..............................  Duke Energy Corp.
E.ON..............................  E.ON U.S. LLC.
East Texas Cooperatives...........  East Texas Electric Cooperative,
                                     Inc.; Northeast Texas Electric
                                     Cooperative, Inc.; Sam Rayburn
                                     Generation and Electric
                                     Cooperative, Inc. and Tex-La
                                     Electric Cooperative of Texas, Inc.
Eastern North Carolina............  Eastern NC Towns (Towns of Black
                                     Creek, NC; Lucama, NC;
                                     Stantonsburg, NC).
EEI...............................  Edison Electric Institute.
ELCON.............................  Electricity Consumers Resource
                                     Council, American Iron and Steel
                                     Institute, and American Forest &
                                     Paper Institute.
Emerald...........................  Emerald People's Utility District.
Entegra...........................  Entegra Power Group LLC and LS Power
                                     Associates, L.P.
Entergy...........................  Entergy Services, Inc.
EPSA..............................  Electric Power Supply Association.
Exelon............................  Exelon Corporation.
Fayetteville......................  Public Works Commission of the City
                                     of Fayetteville, North Carolina.
Fertilizer Institute..............  Fertilizer Institute.
FirstEnergy.......................  FirstEnergy Service Company (First
                                     Energy Solutions; American
                                     Transmission Systems, Inc.; Jersey
                                     Central Power and Light Co.;
                                     Metropolitan Edison Co.; and
                                     Pennsylvania Electric Co.).
Flathead..........................  Flathead Electric Cooperative.
Florida Commission................  Florida Public Service Commission.
Florida Industrial Cogeneration     Florida Industrial Cogeneration
 Association.                        Association.
FMPA..............................  Florida Municipal Power Agency and
                                     Midwest Municipal Transmission
                                     Group.
Geothermal Producers..............  CE Generation, LLC; Ormat
                                     Technologies, Inc.; Caithness
                                     Energy, LLC; and Geothermal Energy
                                     Association.
Grant.............................  Grant County PUD, Chelan County PUD
                                     and Pend Oreille County PUD.
Great Northern....................  Great Northern Power Development,
                                     L.P.
Imperial..........................  Imperial Irrigation District.
Indianapolis Power................  Indianapolis Power & Light Co.
Indicated New York Transmission     Central Hudson Gas & Electric Corp.;
 Owners.                             Consolidated Edison Co. of New
                                     York, Inc.; LIPA; New York Power
                                     Authority; New York State Electric
                                     & Gas Corp.; Orange and Rockland
                                     Utilities, Inc.; and Rochester Gas
                                     and Electric Corp.
International Transmission........  International Transmission Co. d/b/a
                                     ITCTransmission and Michigan
                                     Electric Transmission Co., LLC.
IRH Management....................  IRH Management Committee and the
                                     Schedule 20A Service Providers.
ISO New England...................  ISO New England, Inc. and New
                                     England Power Pool.
ISO/RTO Council...................  ISO/RTO Council.
Lassen............................  Lassen Municipal Utility District.
LDWP..............................  City of Los Angeles Department of
                                     Water and Power.
LPPC..............................  Large Public Power Council.
Manitoba Hydro....................  Manitoba Hydro.
MDEA..............................  Mississippi Delta Energy Agency,
                                     Clarksdale Public Utilities
                                     Commission, and Public Service
                                     Commission of Yazoo City.
MidAmerican.......................  MidAmerican Energy Company and
                                     PacifiCorp.
MISO..............................  Midwest Independent Transmission
                                     System Operator, Inc.
MISO Transmission Owners..........  Midwest ISO Transmission Owners.
MISO/PJM States...................  Organization of MISO States and
                                     Organization of PJM States, Inc.
Morgan Stanley....................  Morgan Stanley Capital Group Inc.
NAESB.............................  North American Energy Standards
                                     Board.
NARUC.............................  National Association of Regulatory
                                     Utility Commissioners.
National Grid.....................  National Grid USA.
NCEMC.............................  North Carolina Electric Membership
                                     Corporation.
NCPA..............................  Northern California Power Agency.
NERC..............................  North American Electric Reliability
                                     Corporation.
Nevada Commission.................  Public Utilities Commission of
                                     Nevada.
Nevada Companies..................  Nevada Power Company and Sierra
                                     Pacific Power Company.
New Jersey Board..................  New Jersey Board of Public
                                     Utilities.
New Mexico Attorney General.......  New Mexico Attorney General.
New York Commission...............  New York State Public Service
                                     Commission.

[[Page 12499]]


Newfoundland......................  Newfoundland and Labrador Hydro.
Newmont Mining....................  Newmont USA Limited, dba Newmont
                                     Mining Corp.
Northeast Utilities...............  Northeast Utilities Service Company
                                     (Connecticut Light and Power Co.;
                                     Western Massachusetts Electric Co.;
                                     Public Service Co. of New
                                     Hampshire; Holyoke Water Power Co.;
                                     and Holyoke Power and Electric
                                     Co.).
Northwest IOUs....................  Northwest Investor-Owned Utilities
                                     (Avista Corp., Portland General
                                     Electric Co., and Puget Sound
                                     Energy, Inc.).
Northwest Parties.................  Northwest Parties (Avista Corp.,
                                     Bonneville Power Administration,
                                     PacifiCorp, PNGC Power, Portland
                                     General Electric Co., Public Power
                                     Council, Public Utility Commission
                                     of Oregon and Puget Sound Energy,
                                     Inc.).
NorthWestern......................  NorthWestern Corporation.
NPPD..............................  Nebraska Public Power District.
NRECA.............................  National Rural Electric Cooperative
                                     Association.
NRG...............................  NRG Energy, Inc.
NYAPP.............................  New York Association of Public
                                     Power.
Occidental........................  Occidental Chemical Corporation.
Oklahoma Commission...............  Oklahoma Corporation Commission.
Old Dominion......................  Old Dominion Electric Cooperative.
Oversight Resources...............  Oversight Resources, LLC.
PGP...............................  Public Generating Pool and Chelan
                                     County PUD.
Pinnacle..........................  Pinnacle West Capital Corporation;
                                     Arizona Public Service Company; and
                                     APS Energy Services Company, Inc.
PJM...............................  PJM Interconnection, LLC.
PNM-TNMP..........................  Public Service Company of New Mexico
                                     and Texas-New Mexico Power Company.
Powerex...........................  Powerex Corp.
PPL...............................  PPL Companies.
PPM...............................  PPM Energy, Inc.
Progress Energy...................  Progress Energy, Inc. (Carolina
                                     Power & Light Co. d/b/a Progress
                                     Energy Carolinas and Florida Power
                                     Corp., d/b/a Progress Energy
                                     Florida; and Progress Ventures,
                                     Inc.).
Project for Sustainable FERC        Project for Sustainable FERC Energy
 Energy Policy.                      Policy (American Wind Energy
                                     Association, Delaware Division of
                                     the Public Advocate, Environmental
                                     Law & Policy Center, Illinois
                                     Citizens Utility Board, Natural
                                     Resources Defense Council,
                                     Northwest Energy Coalition, Office
                                     of the Ohio Consumers' Counsel,
                                     Pace Energy Project, Project for
                                     Sustainable FERC Energy Policy,
                                     Renewable Northwest Project, West
                                     Wind Wires, and Wind on the Wires).
PSEG..............................  Public Service Electric and Gas
                                     Company; PSEG Power LLC; and PSEC
                                     Energy Resources & Trade LLC (PSEG
                                     Companies).
Public Power Council..............  Public Power Council.
Reliant...........................  Reliant Energy, Inc.
Sacramento........................  Sacramento Municipal Utility
                                     District.
Salt River........................  Salt River Project Agricultural
                                     Improvement and Power District.
San Diego G&E.....................  San Diego Gas & Electric Company.
Santa Clara.......................  City of Santa Clara, California d/b/
                                     a Silicon Valley Power.
Santee Cooper.....................  South Carolina Public Service
                                     Authority.
SCE...............................  Southern California Edison.
Seattle...........................  City of Seattle--City Light
                                     Department.
Sempra Global.....................  Sempra Global.
South Carolina E&G................  South Carolina Electric & Gas
                                     Company.
South Carolina Regulatory Staff...  South Carolina Office of Regulatory
                                     Staff.
Southern..........................  Southern Company Services, Inc.
Southwest Transmission............  Southwest Area Transmission Sub-
                                     Regional Planning Group.
Southwestern Coop.................  Southwestern Electric Cooperative,
                                     Inc.
SPP...............................  Southwest Power Pool, Inc.
Steel Manufacturers Association...  Steel Manufacturers Association.
Suez Energy NA....................  Suez Energy North America, Inc.
Tacoma............................  Tacoma Power.
TANC..............................  Transmission Agency of Northern
                                     California.
TAPS..............................  Transmission Access Policy Study
                                     Group.
TDU Systems.......................  Transmission Dependent Utilities
                                     Systems.
TransAlta.........................  TransAlta Energy Marketing (US) Inc.
TranServ..........................  TranServ International, Inc.
Tucson............................  Tucson Electric Power Company.
TVA...............................  Tennessee Valley Authority.
Utah Municipals...................  Utah Associated Municipal Power
                                     Systems.
WAPA..............................  Western Area Power Administration.
WECC..............................  Western Electricity Coordinating
                                     Council.
WestConnect.......................  WestConnect Companies.
Western Governors.................  Western Governors' Association.
Williams..........................  Williams Power Company, Inc.
Wisconsin Electric................  Wisconsin Electric Power Company.
WSPP..............................  Western Systems Power Pool, Inc.

[[Page 12500]]


Xcel..............................  Xcel Energy Services, Inc.
------------------------------------------------------------------------


                            Reply commenters
------------------------------------------------------------------------
           Abbreviation                       Reply commenters
------------------------------------------------------------------------
Alberta Intervenors...............  Alberta Intervenors (TransCanada
                                     Energy Ltd., ENMAX Energy
                                     Marketing, Inc.; EPCOR Merchant and
                                     Capital, LP; and TransAlta
                                     Corporation).
Anaheim...........................  Cities of Anaheim, Azusa, Banning,
                                     Colton, Pasadena, and Riverside,
                                     California.
APPA..............................  American Public Power Association.
Barrick...........................  Barrick Goldstrike Mines Inc.
Bonneville........................  Bonneville Power Administration.
CAISO.............................  California Independent System
                                     Operator Corporation.
California Commission.............  Public Utilities Commission of the
                                     State of California.
Canadian Electricity Association..  Canadian Electricity Association.
Chandley-Hogan....................  John D. Chandley and William W.
                                     Hogan.
CMUA..............................  California Municipal Utilities
                                     Association.
ColumbiaGrid......................  ColumbiaGrid Members (Bonneville
                                     Power Administration; Avista Corp.;
                                     Public Utility District No. 1 of
                                     Chelan County, Washington; Public
                                     Utility District No. 2 of Grant
                                     County, Washington; Puget Sound
                                     Energy, Inc.; Seattle City Light;
                                     and Tacoma Power.
Community Power Alliance..........  Community Power Alliance Members
                                     (Entergy, Progress Energy, Salt
                                     River Project Agricultural
                                     Improvement and Power District, and
                                     Southern Co.).
Detroit Edison....................  Detroit Edison Co.
Duke..............................  Duke Energy Corp.
Dynegy............................  Dynegy Power Marketing, Inc.
East Texas Cooperatives...........  East Texas Electric Cooperative,
                                     Inc.; Northeast Texas Electric
                                     Cooperative, Inc.; Sam Rayburn
                                     Generation and Electric
                                     Cooperative, Inc. and Tex-La
                                     Electric Cooperative of Texas, Inc.
EEI...............................  Edison Electric Institute.
ElectriCities.....................  ElectriCities of North Carolina,
                                     Inc.
Entegra...........................  Entegra Power Group LLC and LS Power
                                     Associates, L.P.
Entergy...........................  Entergy Services, Inc.
EPSA..............................  Electric Power Supply Association.
Exelon............................  Exelon Corporation.
Fayetteville......................  Public Works Commission of the City
                                     of Fayetteville, North Carolina.
Fertilizer Institute..............  Fertilizer Institute.
FMPA..............................  Florida Municipal Power Agency and
                                     Midwest Municipal Transmission
                                     Group.
Great Northern....................  Great Northern Power Development,
                                     L.P.
Hoosier...........................  Hoosier Energy Rural Electric
                                     Cooperative, Inc.
H.Q. Energy.......................  H.Q. Energy Services (U.S.), Inc.
Indianapolis Power................  Indianapolis Power & Light Co.
Industrial Customers of Northwest   Industrial Customers of Northwest
 Utilities.                          Utilities (Air Liquide; Air
                                     Products; BPB Gypsum, Inc.; Blue
                                     Heron Paper Company; Boeing; Boise
                                     Cascade; CNC Containers, Northwest;
                                     Chemi-Con Materials Corporation;
                                     Dyno Nobel, Inc.; ConAgra Foods;
                                     Eka Chemicals, Inc.; Evanite Fiber;
                                     Georgia-Pacific; Grays Harbor
                                     Paper, L.P.; Hewlett-Packard;
                                     Inland Empire Paper Co.; Intel;
                                     J.R. Simplot; Kimberly-Clark
                                     Corporation; Longview Fibre;
                                     Microsoft Corporation; Norpac
                                     Foods; Noveon Kalama, Inc.; Oregon
                                     Steel Mills; PCC Structurals, Inc.;
                                     Ponderay Newsprint Co; Shell Oil
                                     Products US; Simpson Paper; Simpson
                                     Timber; Solar Grade Silicon LLC; SP
                                     Newsprint Co.; Tesoro Refining and
                                     Marketing Co.; Wah Chang; West Linn
                                     Paper Company; Weyerhaeuser).
International Transmission........  International Transmission Co. d/b/a
                                     ITCTransmission and Michigan
                                     Electric Transmission Co., LLC.
ISO/RTO Council...................  ISO/RTO Council.
Lassen............................  Lassen Municipal Utility District.
LPPC..............................  Large Public Power Council.
MAPP..............................  Mid-Continent Area Power Pool.
Mark Lively.......................  Mark B. Lively.
MDEA..............................  Mississippi Delta Energy Agency,
                                     Clarksdale Public Utilities
                                     Commission, Public Service
                                     Commission of Yazoo City, Arkansas
                                     Electric Cooperative Corporation,
                                     Municipal Energy Agency of
                                     Mississippi, and Lafayette
                                     Utilities System*.\1008\
MidAmerican.......................  MidAmerican Energy Company and
                                     PacifiCorp.
MISO..............................  Midwest Independent Transmission
                                     System Operator, Inc.
Morgan Stanley....................  Morgan Stanley Capital Group Inc.
NARUC.............................  National Association of Regulatory
                                     Utility Commissioners.
NC Transmission Planning            North Carolina Transmission Planning
 Participants.                       Collaborative Participants.
NCPA..............................  Northern California Power Agency.
Newmont Mining....................  Newmont USA Limited, dba Newmont
                                     Mining Corp.
North Carolina Commission.........  North Carolina Utilities Commission;
                                     Public Staff of the North Carolina
                                     Utilities Commission; and the
                                     Attorney General of the State of
                                     North Carolina.

[[Page 12501]]


Northwest IOUs....................  Northwest Investor-Owned Utilities
                                     (Avista Corp., Portland General
                                     Electric Co., and Puget Sound
                                     Energy, Inc.).
NorthWestern......................  NorthWestern Corporation.
NRECA.............................  National Rural Electric Cooperative
                                     Association.
Occidental........................  Occidental Chemical Corporation.
OG&E..............................  Oklahoma Gas and Electric Company.
Ohio Power Siting Board...........  Ohio Power Siting Board, American
                                     Municipal Power-Ohio, Inc. and
                                     Buckeye Power, Inc.
Old Dominion......................  Old Dominion Electric Cooperative;
                                     Southern Maryland Electric
                                     Cooperative, Inc.; Allegheny
                                     Electric Cooperative, Inc.; and
                                     North Carolina Electric Membership
                                     Corporation.
Omaha Public Power................  Omaha Public Power District.
Pennsylvania Commission...........  Pennsylvania Public Utility
                                     Commission.
PJM...............................  PJM Interconnection, LLC.
PNM-TNMP..........................  Public Service Company of New Mexico
                                     and Texas-New Mexico Power Company.
Powerex...........................  Powerex Corp.
PPM...............................  PPM Energy, Inc.
Progress Energy...................  Progress Energy, Inc. (Carolina
                                     Power & Light Co. d/b/a Progress
                                     Energy Carolinas and Florida Power
                                     Corp., d/b/a Progress Energy
                                     Florida; and Progress Ventures,
                                     Inc.).
Project for Sustainable FERC        Project for Sustainable FERC Energy
 Energy Policy.                      Policy (Delaware Division of the
                                     Public Advocate, Environmental Law
                                     & Policy Center, Fresh Energy,
                                     Natural Resources Defense Council,
                                     Northwest Energy Coalition, Pace
                                     Energy Project, Project for
                                     Sustainable FERC Energy Policy,
                                     Renewable Northwest Project, West
                                     Wind Wires, and Wind on the
                                     Wires).*
Public Power Council..............  Public Power Council.
Sacramento........................  Sacramento Municipal Utility
                                     District.
Salt River........................  Salt River Project Agricultural
                                     Improvement and Power District.
Santa Clara.......................  City of Santa Clara, California d/b/
                                     a Silicon Valley Power.
Seattle...........................  City of Seattle--City Light
                                     Department.
Seminole..........................  Seminole Electric Cooperative, Inc.
South Carolina E&G................  South Carolina Electric & Gas
                                     Company.
Southern..........................  Southern Company Services, Inc.
SPP...............................  Southwest Power Pool, Inc.
Steel Manufacturers Association...  Steel Manufacturers Association.
Strategic Energy..................  Strategic Energy, L.L.C.
TANC..............................  Transmission Agency of Northern
                                     California.
TAPS..............................  Transmission Access Policy Study
                                     Group.
TDU Systems.......................  Transmission Dependent Utilities
                                     Systems.
Transparent Dispatch Advocates....  PJM Interconnection, LLC; Electric
                                     Consumers Resource Council;
                                     Electric Power Supply Association;
                                     Natural Resources Defense Council;
                                     Renewable Northwest Project;
                                     Project for Sustainable FERC Energy
                                     Policy; Center for Energy
                                     Efficiency & Renewable
                                     Technologies; Shell Trading Gas and
                                     Power Company; American Wind Energy
                                     Association; and Exelon.
Utah Municipals...................  Utah Associated Municipal Power
                                     Systems.
WestConnect.......................  WestConnect Companies.
Williams..........................  Williams Power Company, Inc.
Wolverine.........................  Wolverine Power Supply Cooperative,
                                     Inc.
WPS Companies.....................  WPS Companies (Wisconsin Public
                                     Service Corporation and Upper
                                     Peninsula Power Company).
WSPP..............................  Western Systems Power Pool, Inc.
Xcel..............................  Xcel Energy Services, Inc.
------------------------------------------------------------------------


                     Technical Conference Commenters
------------------------------------------------------------------------
           Abbreviation                Technical conference commenters
------------------------------------------------------------------------
APPA*.............................  American Public Power Association.
APS*..............................  Arizona Public Service Company.
Bonneville*.......................  Bonneville Power Administration.
Constellation*....................  Constellation Energy Group, Inc.
EEI*..............................  Exelon Corporation on behalf of
                                     Edison Electric Institute (EEI).
EPSA*\1009\.......................  Electric Power Supply Association.
Exelon*...........................  Exelon.
NAESB*............................  North American Energy Standards
                                     Board.
NARUC*............................  National Association of Regulatory
                                     Utility Commissioners.
National Grid*....................  National Grid USA.
National Grid/Central Hudson......  National Grid USA, Central Hudson
                                     Gas & Electric Corporation, and
                                     American Wind Energy.
NERC*.............................  Prague Power, LLC, on behalf of the
                                     North American Electric Reliability
                                     Corporation.

[[Page 12502]]


New York Parties..................  Consolidated Edison Co. of New York,
                                     Inc., Orange and Rockland
                                     Utilities, Inc., New York Power
                                     Authority, and Independent Power
                                     Producers of New York, Inc.
NRECA*............................  Great River Energy on behalf of
                                     National Rural Electric Cooperative
                                     Association (NRECA).
NRG on behalf of EPSA*............  NRG Energy, Inc. on behalf of
                                     Electric Power Supply Association
                                     (EPSA).
PacifiCorp........................  PacifiCorp.
PJM*..............................  PJM Interconnection, LLC.
AWEA*.............................  PPM Energy, Inc. on behalf of
                                     American Wind Energy Association
Progress Energy*..................  Progress Energy, Inc. (Carolina
                                     Power & Light Company, d/b/a.
                                     Progress Energy Carolinas, Inc. and
                                     Florida Power Corporation, d/b/a
                                     Progress Energy Florida, Inc.).
Renewable Northwest Project*......  Renewable Northwest Project.
San Diego G&E.....................  San Diego Gas & Electric Company.
TAPS*.............................  Southern Minnesota Municipal Power
                                     Agency and Transmission Access
                                     Policy Study Group.
TDU Systems.......................  Transmission Dependent Utilities
                                     Systems.
South Carolina Regulatory Staff...  South Carolina Office of Regulatory
                                     Staff.
Southern*.........................  Southern Company Services, Inc.
WECC*.............................  Western Electricity Coordinating
                                     Council.
Williams*.........................  Williams Power.
Williams*.........................  Williams Power Company, Inc.
Xcel*.............................  Xcel Energy Services, Inc.
------------------------------------------------------------------------


                         Supplemental Commenters
------------------------------------------------------------------------
           Abbreviation                    Supplemental commenters
------------------------------------------------------------------------
Alabama Commission................  Alabama Public Service Commission.
Ameren............................  Ameren Services Company.
APPA..............................  American Public Power Association.
Barrick...........................  Barrick Goldstrike Mines Inc.
Bonneville........................  Bonneville Power Administration.
BP Energy.........................  BP Energy Company.
California Commission.............  Public Utilities Commission of the
                                     State of California.
Community Power Alliance..........  Community Power Alliance Members
                                     (Entergy, Progress Energy, Salt
                                     River Project Agricultural
                                     Improvement and Power District, and
                                     Southern Co.).
Constellation.....................  Constellation Energy Group, Inc.
Duke..............................  Duke Energy Corp.
E.ON..............................  E.ON U.S. LLC.
EEI...............................  Edison Electric Institute.
Entergy...........................  Entergy Services, Inc.
EPSA and AWEA.....................  Electric Power Supply Association
                                     and American Wind Energy
                                     Association.
Florida Commission................  Florida Public Service Commission.
Georgia Commission................  Georgia Public Service Commission.
LPPC..............................  Large Public Power Council.
Mark Lively.......................  Mark B. Lively.
MISO..............................  Midwest Independent Transmission
                                     System Operator, Inc.
Nevada Companies..................  Nevada Power Company and Sierra
                                     Pacific Power Company.
North Carolina Commission.........  North Carolina Utilities Commission;
                                     Public Staff of the North Carolina
                                     Utilities Commission; and the
                                     Attorney General of the State of
                                     North Carolina.
NRECA.............................  National Rural Electric Cooperative
                                     Association.
OG&E..............................  Oklahoma Gas and Electric Company.
Pacific Coast Parties.............  Pacific Coast Parties (Avista
                                     Corporation, Bonneville Power
                                     Administration, PacifiCorp,
                                     Portland General Electric Company,
                                     Puget Sound Energy, Inc., the
                                     Sacramento Municipal Utility
                                     District and the Transmission
                                     Agency of Northern California).
PGP...............................  Public Generating Pool.
Southwest Utilities...............  Pinnacle West Companies, Public
                                     Service Company of New Mexico,
                                     Texas-New Mexico Power Company, and
                                     UniSource Energy Corporation.
PNM-TNMP..........................  Public Service Company of New Mexico
                                     and Texas-New Mexico Power Company.
Powerex...........................  Powerex Corp.
PPL...............................  PPL Companies.
PPM...............................  PPM Energy, Inc.
Progress Energy...................  Progress Energy, Inc. (Carolina
                                     Power & Light Company, d/b/a.
                                     Progress Energy Carolinas, Inc. and
                                     Florida Power Corporation, d/b/a
                                     Progress Energy Florida, Inc.).
Progress Energy and MidAmerican...  Progress Energy, Inc. and
                                     MidAmerican Energy Company.
Public Power Council..............  Public Power Council.
SEARUC............................  Southeastern Association of
                                     Regulatory Utility Commissioners.
South Carolina E&G................  South Carolina Electric & Gas
                                     Company.
South Carolina Regulatory Staff...  South Carolina Office of Regulatory
                                     Staff.

[[Page 12503]]


Southern..........................  Southern Company Services, Inc.
Tacoma............................  Tacoma Power.
TAPS..............................  Transmission Access Policy Study
                                     Group.
TDU Systems.......................  Transmission Dependent Utilities
                                     Systems.
Transparent Dispatch Advocates....  Transparent Dispatch Advocates
                                     (American Wind Energy Association;
                                     Center for Energy Efficiency &
                                     Renewable Technologies; Electric
                                     Consumers Resource Council;
                                     Electric Power Supply Association;
                                     Exelon Corporation; Natural
                                     Resources Defense Council; PJM
                                     Interconnection, LLC; PPM Energy;
                                     Project for Sustainable FERC Energy
                                     Policy; Renewable Northwest
                                     Project; and Shell Trading Gas and
                                     Power Company)*\1010\
Western Governors.................  Western Governors' Association.
Williams..........................  Williams Power Company, Inc.
WIRES.............................  WIRES.
Xcel..............................  Xcel Energy Services, Inc.
------------------------------------------------------------------------

Appendix C: Pro Forma Open Access Transmission Tariff
---------------------------------------------------------------------------

    \1008\ A ``*'' indicates that the composition of this group has 
altered in the reply comment filing.
    \1009\ A ``*'' indicates that this party submitted speaker 
materials at the October 12 Technical Conference.
    \1010\ A ``*'' indicates that the composition of this group has 
altered in this filing.
---------------------------------------------------------------------------

Table of Contents

I. Common Service Provisions
    1 Definitions
    1.1 Affiliate
    1.2 Ancillary Services
    1.3 Annual Transmission Costs
    1.4 Application
    1.5 Commission
    1.6 Completed Application
    1.7 Control Area
    1.8 Curtailment
    1.9 Delivering Party
    1.10 Designated Agent
    1.11 Direct Assignment Facilities
    1.12 Eligible Customer
    1.13 Facilities Study
    1.14 Firm Point-To-Point Transmission Service
    1.15 Good Utility Practice
    1.16 Interruption
    1.17 Load Ratio Share
    1.18 Load Shedding
    1.19 Long-Term Firm Point-To-Point Transmission Service
    1.20 Native Load Customers
    1.21 Network Customer
    1.22 Network Integration Transmission Service
    1.23 Network Load
    1.24 Network Operating Agreement
    1.25 Network Operating Committee
    1.26 Network Resource
    1.27 Network Upgrades
    1.28 Non-Firm Point-To-Point Transmission Service
    1.29 Non-Firm Sale
    1.30 Open Access Same-Time Information System (OASIS)
    1.31 Part I
    1.32 Part II
    1.33 Part III
    1.34 Parties
    1.35 Point(s) of Delivery
    1.36 Point(s) of Receipt
    1.37 Point-To-Point Transmission Service
    1.38 Power Purchaser
    1.39 Pre-Confirmed Application
    1.40 Receiving Party
    1.41 Regional Transmission Group (RTG)
    1.42 Reserved Capacity
    1.43 Service Agreement
    1.44 Service Commencement Date
    1.45 Short-Term Firm Point-To-Point Transmission Service
    1.46 System Condition
    1.47 System Impact Study
    1.48 Third-Party Sale
    1.49 Transmission Customer
    1.50 Transmission Provider
    1.51 Transmission Provider's Monthly Transmission System Peak
    1.52 Transmission Service
    1.53 Transmission System
    2 Initial Allocation and Renewal Procedures
    2.1 Initial Allocation of Available Transfer Capability
    2.2 Reservation Priority for Existing Firm Service Customers
    3 Ancillary Services
    3.1 Scheduling, System Control and Dispatch Service
    3.2 Reactive Supply and Voltage Control From Generation or Other 
Sources Service
    3.3 Regulation and Frequency Response Service
    3.4 Energy Imbalance Service
    3.5 Operating Reserve--Spinning Reserve Service
    3.6 Operating Reserve--Supplemental Reserve Service
    3.7 Generator Imbalance Service
    4 Open Access Same-Time Information System (OASIS)
    5 Local Furnishing Bonds
    5.1 Transmission Providers That Own Facilities Financed by Local 
Furnishing Bonds
    5.2 Alternative Procedures for Requesting Transmission Service
    6 Reciprocity
    7 Billing and Payment
    7.1 Billing Procedure:
    7.2 Interest on Unpaid Balances
    7.3 Customer Default
    8 Accounting for the Transmission Provider's Use of the Tariff
    8.1 Transmission Revenues
    8.2 Study Costs and Revenues
    9 Regulatory Filings
    10 Force Majeure and Indemnification
    10.1 Force Majeure
    10.2 Indemnification
    11 Creditworthiness
    12 Dispute Resolution Procedures
    12.1 Internal Dispute Resolution Procedures
    12.2 External Arbitration Procedures
    12.3 Arbitration Decisions
    12.4 Costs
    12.5 Rights Under the Federal Power Act
II. Point-to-Point Transmission Service
    13 Nature of Firm Point-to-Point Transmission Service
    13.1 Term
    13.2 Reservation Priority
    13.3 Use of Firm Transmission Service by the Transmission 
Provider
    13.4 Service Agreements
    13.5 Transmission Customer Obligations for Facility Additions or 
Redispatch Costs
    13.6 Curtailment of Firm Transmission Service
    13.7 Classification of Firm Transmission Service
    13.8 Scheduling of Firm Point-To-Point Transmission Service
    14 Nature of Non-Firm Point-to-Point Transmission Service
    14.1 Term
    14.2 Reservation Priority
    14.3 Use of Non-Firm Point-To-Point Transmission Service by the 
Transmission Provider
    14.4 Service Agreements
    14.5 Classification of Non-Firm Point-To-Point Transmission 
Service
    14.6 Scheduling of Non-Firm Point-To-Point Transmission Service
    14.7 Curtailment or Interruption of Service
    15 Service Availability
    15.1 General Conditions
    15.2 Determination of Available Transfer Capability
    15.3 Initiating Service in the Absence of an Executed Service 
Agreement
    15.4 Obligation to Provide Transmission Service that Requires 
Expansion or Modification of the Transmission System, Redispatch or 
Conditional Curtailment

[[Page 12504]]

    15.5 Deferral of Service
    15.6 Other Transmission Service Schedules
    15.7 Real Power Losses
    16 Transmission Customer Responsibilities
    16.1 Conditions Required of Transmission Customers
    16.2 Transmission Customer Responsibility for Third-Party 
Arrangements
    17 Procedures For Arranging Firm Point-to-Point Transmission 
Service
    17.1 Application
    17.2 Completed Application
    17.3 Deposit
    17.4 Notice of Deficient Application
    17.5 Response to a Completed Application
    17.6 Execution of Service Agreement
    17.7 Extensions for Commencement of Service
    18 Procedures for Arranging Non-Firm Point-to-Point Transmission 
Service
    18.1 Application
    18.2 Completed Application
    18.3 Reservation of Non-Firm Point-to-Point Transmission Service
    18.4 Determination of Available Transfer Capability
    19 Additional Study Procedures For Firm Point-to-Point 
Transmission Service Requests
    19.1 Notice of Need for System Impact Study
    19.2 System Impact Study Agreement and Cost Reimbursement
    19.3 System Impact Study Procedures
    19.4 Facilities Study Procedures
    19.5 Facilities Study Modifications
    19.6 Due Diligence in Completing New Facilities
    19.7 Partial Interim Service
    19.8 Expedited Procedures for New Facilities
    19.9 Penalties for Failure to Meet Study Deadlines
    20 Procedures if the Transmission Provider is Unable to Complete 
New Transmission Facilities for Firm Point-to-Point Transmission 
Service
    20.1 Delays in Construction of New Facilities:
    20.2 Alternatives to the Original Facility Additions
    20.3 Refund Obligation for Unfinished Facility Additions
    21 Provisions Relating to Transmission Construction and Services 
on the Systems of Other Utilities
    21.1 Responsibility for Third-Party System Additions
    21.2 Coordination of Third-Party System Additions
    22 Changes in Service Specifications
    22.1 Modifications On a Non-Firm Basis
    22.2 Modification On a Firm Basis
    23 Sale or Assignment of Transmission Service
    23.1 Procedures for Assignment or Transfer of Service
    23.2 Limitations on Assignment or Transfer of Service
    23.3 Information on Assignment or Transfer of Service
    24 Metering and Power Factor Correction at Receipt and Delivery 
Points(s)
    24.1 Transmission Customer Obligations
    24.2 Transmission Provider Access to Metering Data
    24.3 Power Factor
    25 Compensation for Transmission Service
    26 Stranded Cost Recovery
    27 Compensation for New Facilities and Redispatch Costs
III. Network Integration Transmission Service
    28 Nature of Network Integration Transmission Service
    28.1 Scope of Service
    28.2 Transmission Provider Responsibilities
    28.3 Network Integration Transmission Service
    28.4 Secondary Service
    28.5 Real Power Losses
    28.6 Restrictions on Use of Service
    29 Initiating Service
    29.1 Condition Precedent for Receiving Service
    29.2 Application Procedures
    29.3 Technical Arrangements to be Completed Prior to 
Commencement of Service
    29.4 Network Customer Facilities
    29.5 Filing of Service Agreement
    30 Network Resources
    30.1 Designation of Network Resources
    30.2 Designation of New Network Resources
    30.3 Termination of Network Resources
    30.4 Operation of Network Resources
    30.5 Network Customer Redispatch Obligation
    30.6 Transmission Arrangements for Network Resources Not 
Physically Interconnected With the Transmission Provider
    30.7 Limitation on Designation of Network Resources
    30.8 Use of Interface Capacity by the Network Customer
    30.9 Network Customer Owned Transmission Facilities
    31 Designation of Network Load
    31.1 Network Load
    31.2 New Network Loads Connected With the Transmission Provider
    31.3 Network Load Not Physically Interconnected With the 
Transmission Provider
    31.4 New Interconnection Points
    31.5 Changes in Service Requests
    31.6 Annual Load and Resource Information Updates
    32 Additional Study Procedures for Network Integration 
Transmission Service Requests
    32.1 Notice of Need for System Impact Study
    32.2 System Impact Study Agreement and Cost Reimbursement
    32.3 System Impact Study Procedures
    32.4 Facilities Study Procedures
    32.5 Penalties for Failure to Meet Study Deadlines
    33 Load Shedding and Curtailments
    33.1 Procedures
    33.2 Transmission Constraints
    33.3 Cost Responsibility for Relieving Transmission Constraints
    33.4 Curtailments of Scheduled Deliveries
    33.5 Allocation of Curtailments
    33.6 Load Shedding
    33.7 System Reliability
    34 Rates and Charges
    34.1 Monthly Demand Charge
    34.2 Determination of Network Customer's Monthly Network Load
    34.3 Determination of Transmission Provider's Monthly 
Transmission System Load
    34.4 Redispatch Charge
    34.5 Stranded Cost Recovery
    35 Operating Arrangements
    35.1 Operation Under The Network Operating Agreement
    35.2 Network Operating Agreement
    35.3 Network Operating Committee

Schedule 1

    Scheduling, System Control and Dispatch Service

Schedule 2

    Reactive Supply and Voltage Control From Generation Sources 
Service

Schedule 3

    Regulation and Frequency Response Service

Schedule 4

    Energy Imbalance Service

Schedule 5

    Operating Reserve--Spinning Reserve Service

Schedule 6

    Operating Reserve--Supplemental Reserve Service

Schedule 7

    Long-Term Firm and Short-Term Firm Point-to-Point

Schedule 8

    Non-Firm Point-to-Point Transmission Service

Schedule 9

    Generator Imbalance Service

Attachment A

    Form of Service Agreement for Firm Point-to-Point Transmission 
Service

Attachment A-1

    Form of Service Agreement for the Resale, Reassignment or 
Transfer of Long-Term Firm Point-to-Point Transmission Service

Attachment B

    Form of Service Agreement for Non-Firm Point-to-Point 
Transmission Service

Attachment C

    Methodology to Assess Available Transfer Capability

Attachment D

    Methodology for Completing a System Impact Study

Attachment E

    Index of Point-to-Point Transmission Service Customers

Attachment F

    Service Agreement for Network Integration Transmission Service

[[Page 12505]]

Attachment G

    Network Operating Agreement

Attachment H

    Annual Transmission Revenue Requirement for Network Integration 
Transmission Service

Attachment I

    Index of Network Integration Transmission Service Customers

Attachment J

    Procedures for Addressing Parallel Flows

Attachment K

    Transmission Planning Process

Attachment L

    Creditworthiness Procedures

I. Common Service Provisions

1 Definitions

1.1 Affiliate
    With respect to a corporation, partnership or other entity, each 
such other corporation, partnership or other entity that directly or 
indirectly, through one or more intermediaries, controls, is controlled 
by, or is under common control with, such corporation, partnership or 
other entity.
1.2 Ancillary Services
    Those services that are necessary to support the transmission of 
capacity and energy from resources to loads while maintaining reliable 
operation of the Transmission Provider's Transmission System in 
accordance with Good Utility Practice.
1.3 Annual Transmission Costs
    The total annual cost of the Transmission System for purposes of 
Network Integration Transmission Service shall be the amount specified 
in Attachment H until amended by the Transmission Provider or modified 
by the Commission.
1.4 Application
    A request by an Eligible Customer for transmission service pursuant 
to the provisions of the Tariff.
1.5 Commission
    The Federal Energy Regulatory Commission.
1.6 Completed Application
    An Application that satisfies all of the information and other 
requirements of the Tariff, including any required deposit.
1.7 Control Area
    An electric power system or combination of electric power systems 
to which a common automatic generation control scheme is applied in 
order to:
    1. Match, at all times, the power output of the generators within 
the electric power system(s) and capacity and energy purchased from 
entities outside the electric power system(s), with the load within the 
electric power system(s);
    2. Maintain scheduled interchange with other Control Areas, within 
the limits of Good Utility Practice;
    3. Maintain the frequency of the electric power system(s) within 
reasonable limits in accordance with Good Utility Practice; and
    4. Provide sufficient generating capacity to maintain operating 
reserves in accordance with Good Utility Practice.
1.8 Curtailment
    A reduction in firm or non-firm transmission service in response to 
a transfer capability shortage as a result of system reliability 
conditions.
1.9 Delivering Party
    The entity supplying capacity and energy to be transmitted at 
Point(s) of Receipt.
1.10 Designated Agent
    Any entity that performs actions or functions on behalf of the 
Transmission Provider, an Eligible Customer, or the Transmission 
Customer required under the Tariff.
1.11 Direct Assignment Facilities
    Facilities or portions of facilities that are constructed by the 
Transmission Provider for the sole use/benefit of a particular 
Transmission Customer requesting service under the Tariff. Direct 
Assignment Facilities shall be specified in the Service Agreement that 
governs service to the Transmission Customer and shall be subject to 
Commission approval.
1.12 Eligible Customer
    i. Any electric utility (including the Transmission Provider and 
any power marketer), Federal power marketing agency, or any person 
generating electric energy for sale for resale is an Eligible Customer 
under the Tariff. Electric energy sold or produced by such entity may 
be electric energy produced in the United States, Canada or Mexico. 
However, with respect to transmission service that the Commission is 
prohibited from ordering by Section 212(h) of the Federal Power Act, 
such entity is eligible only if the service is provided pursuant to a 
state requirement that the Transmission Provider offer the unbundled 
transmission service, or pursuant to a voluntary offer of such service 
by the Transmission Provider.
    ii. Any retail customer taking unbundled transmission service 
pursuant to a state requirement that the Transmission Provider offer 
the transmission service, or pursuant to a voluntary offer of such 
service by the Transmission Provider, is an Eligible Customer under the 
Tariff.
1.13 Facilities Study
    An engineering study conducted by the Transmission Provider to 
determine the required modifications to the Transmission Provider's 
Transmission System, including the cost and scheduled completion date 
for such modifications, that will be required to provide the requested 
transmission service.
1.14 Firm Point-To-Point Transmission Service
    Transmission Service under this Tariff that is reserved and/or 
scheduled between specified Points of Receipt and Delivery pursuant to 
Part II of this Tariff.
1.15 Good Utility Practice
    Any of the practices, methods and acts engaged in or approved by a 
significant portion of the electric utility industry during the 
relevant time period, or any of the practices, methods and acts which, 
in the exercise of reasonable judgment in light of the facts known at 
the time the decision was made, could have been expected to accomplish 
the desired result at a reasonable cost consistent with good business 
practices, reliability, safety and expedition. Good Utility Practice is 
not intended to be limited to the optimum practice, method, or act to 
the exclusion of all others, but rather to be acceptable practices, 
methods, or acts generally accepted in the region, including those 
practices required by Federal Power Act section 215(a)(4).
1.16 Interruption
    A reduction in non-firm transmission service due to economic 
reasons pursuant to Section 14.7.
1.17 Load Ratio Share
    Ratio of a Transmission Customer's Network Load to the Transmission 
Provider's total load computed in accordance with Sections 34.2 and 
34.3 of the Network Integration Transmission Service under Part III of 
the Tariff and calculated on a rolling twelve month basis.

[[Page 12506]]

1.18 Load Shedding
    The systematic reduction of system demand by temporarily decreasing 
load in response to transmission system or area capacity shortages, 
system instability, or voltage control considerations under Part III of 
the Tariff.
1.19 Long-Term Firm Point-To-Point Transmission Service
    Firm Point-To-Point Transmission Service under Part II of the 
Tariff with a term of one year or more.
1.20 Native Load Customers
    The wholesale and retail power customers of the Transmission 
Provider on whose behalf the Transmission Provider, by statute, 
franchise, regulatory requirement, or contract, has undertaken an 
obligation to construct and operate the Transmission Provider's system 
to meet the reliable electric needs of such customers.
1.21 Network Customer
    An entity receiving transmission service pursuant to the terms of 
the Transmission Provider's Network Integration Transmission Service 
under Part III of the Tariff.
1.22 Network Integration Transmission Service
    The transmission service provided under Part III of the Tariff.
1.23 Network Load
    The load that a Network Customer designates for Network Integration 
Transmission Service under Part III of the Tariff. The Network 
Customer's Network Load shall include all load served by the output of 
any Network Resources designated by the Network Customer. A Network 
Customer may elect to designate less than its total load as Network 
Load but may not designate only part of the load at a discrete Point of 
Delivery. Where a Eligible Customer has elected not to designate a 
particular load at discrete points of delivery as Network Load, the 
Eligible Customer is responsible for making separate arrangements under 
Part II of the Tariff for any Point-To-Point Transmission Service that 
may be necessary for such non-designated load.
1.24 Network Operating Agreement
    An executed agreement that contains the terms and conditions under 
which the Network Customer shall operate its facilities and the 
technical and operational matters associated with the implementation of 
Network Integration Transmission Service under Part III of the Tariff.
1.25 Network Operating Committee
    A group made up of representatives from the Network Customer(s) and 
the Transmission Provider established to coordinate operating criteria 
and other technical considerations required for implementation of 
Network Integration Transmission Service under Part III of this Tariff.
1.26 Network Resource
    Any designated generating resource owned, purchased or leased by a 
Network Customer under the Network Integration Transmission Service 
Tariff. Network Resources do not include any resource, or any portion 
thereof, that is committed for sale to third parties or otherwise 
cannot be called upon to meet the Network Customer's Network Load on a 
non-interruptible basis.
1.27 Network Upgrades
    Modifications or additions to transmission-related facilities that 
are integrated with and support the Transmission Provider's overall 
Transmission System for the general benefit of all users of such 
Transmission System.
1.28 Non-Firm Point-To-Point Transmission Service
    Point-To-Point Transmission Service under the Tariff that is 
reserved and scheduled on an as-available basis and is subject to 
Curtailment or Interruption as set forth in Section 14.7 under Part II 
of this Tariff. Non-Firm Point-To-Point Transmission Service is 
available on a stand-alone basis for periods ranging from one hour to 
one month.
1.29 Non-Firm Sale
    An energy sale for which receipt or delivery may be interrupted for 
any reason or no reason, without liability on the part of either the 
buyer or seller.
1.30 Open Access Same-Time Information System (OASIS)
    The information system and standards of conduct contained in Part 
37 of the Commission's regulations and all additional requirements 
implemented by subsequent Commission orders dealing with OASIS.
1.31 Part I
    Tariff Definitions and Common Service Provisions contained in 
Sections 2 through 12.
1.32 Part II
    Tariff Sections 13 through 27 pertaining to Point-To-Point 
Transmission Service in conjunction with the applicable Common Service 
Provisions of Part I and appropriate Schedules and Attachments.
1.33 Part III
    Tariff Sections 28 through 35 pertaining to Network Integration 
Transmission Service in conjunction with the applicable Common Service 
Provisions of Part I and appropriate Schedules and Attachments.
1.34 Parties
    The Transmission Provider and the Transmission Customer receiving 
service under the Tariff.
1.35 Point(s) of Delivery
    Point(s) on the Transmission Provider's Transmission System where 
capacity and energy transmitted by the Transmission Provider will be 
made available to the Receiving Party under Part II of the Tariff. The 
Point(s) of Delivery shall be specified in the Service Agreement for 
Long-Term Firm Point-To-Point Transmission Service.
1.36 Point(s) of Receipt
    Point(s) of interconnection on the Transmission Provider's 
Transmission System where capacity and energy will be made available to 
the Transmission Provider by the Delivering Party under Part II of the 
Tariff. The Point(s) of Receipt shall be specified in the Service 
Agreement for Long-Term Firm Point-To-Point Transmission Service.
1.37 Point-To-Point Transmission Service
    The reservation and transmission of capacity and energy on either a 
firm or non-firm basis from the Point(s) of Receipt to the Point(s) of 
Delivery under Part II of the Tariff.
1.38 Power Purchaser
    The entity that is purchasing the capacity and energy to be 
transmitted under the Tariff.
1.39 Pre-Confirmed Application
    An Application that commits the Transmission Customer to execute a 
Service Agreement upon receipt of notification that the Transmission 
Provider can provide the requested Transmission Service.
1.40 Receiving Party
    The entity receiving the capacity and energy transmitted by the 
Transmission Provider to Point(s) of Delivery.
1.41 Regional Transmission Group (RTG)
    A voluntary organization of transmission owners, transmission users 
and other entities approved by the Commission to efficiently coordinate

[[Page 12507]]

transmission planning (and expansion), operation and use on a regional 
(and interregional) basis.
1.42 Reserved Capacity
    The maximum amount of capacity and energy that the Transmission 
Provider agrees to transmit for the Transmission Customer over the 
Transmission Provider's Transmission System between the Point(s) of 
Receipt and the Point(s) of Delivery under Part II of the Tariff. 
Reserved Capacity shall be expressed in terms of whole megawatts on a 
sixty (60) minute interval (commencing on the clock hour) basis.
1.43 Service Agreement
    The initial agreement and any amendments or supplements thereto 
entered into by the Transmission Customer and the Transmission Provider 
for service under the Tariff.
1.44 Service Commencement Date
    The date the Transmission Provider begins to provide service 
pursuant to the terms of an executed Service Agreement, or the date the 
Transmission Provider begins to provide service in accordance with 
Section 15.3 or Section 29.1 under the Tariff.
1.45 Short-Term Firm Point-To-Point Transmission Service
    Firm Point-To-Point Transmission Service under Part II of the 
Tariff with a term of less than one year.
1.46 System Condition
    A specified condition on the Transmission Provider's system or on a 
neighboring system, such as a constrained transmission element or 
flowgate, that may trigger Curtailment of Long-Term Firm Point-to-Point 
Transmission Service using the curtailment priority pursuant to Section 
13.6. Such conditions must be identified in the Transmission Customer's 
Service Agreement.
1.47 System Impact Study
    An assessment by the Transmission Provider of (i) the adequacy of 
the Transmission System to accommodate a request for either Firm Point-
To-Point Transmission Service or Network Integration Transmission 
Service and (ii) whether any additional costs may be incurred in order 
to provide transmission service.
1.48 Third-Party Sale
    Any sale for resale in interstate commerce to a Power Purchaser 
that is not designated as part of Network Load under the Network 
Integration Transmission Service.
1.49 Transmission Customer
    Any Eligible Customer (or its Designated Agent) that (i) executes a 
Service Agreement, or (ii) requests in writing that the Transmission 
Provider file with the Commission, a proposed unexecuted Service 
Agreement to receive transmission service under Part II of the Tariff. 
This term is used in the Part I Common Service Provisions to include 
customers receiving transmission service under Part II and Part III of 
this Tariff.
1.50 Transmission Provider
    The public utility (or its Designated Agent) that owns, controls, 
or operates facilities used for the transmission of electric energy in 
interstate commerce and provides transmission service under the Tariff.
1.51 Transmission Provider's Monthly Transmission System Peak
    The maximum firm usage of the Transmission Provider's Transmission 
System in a calendar month.
1.52 Transmission Service
    Point-To-Point Transmission Service provided under Part II of the 
Tariff on a firm and non-firm basis.
1.53 Transmission System
    The facilities owned, controlled or operated by the Transmission 
Provider that are used to provide transmission service under Part II 
and Part III of the Tariff.

2 Initial Allocation and Renewal Procedures

2.1 Initial Allocation of Available Transfer Capability
    For purposes of determining whether existing capability on the 
Transmission Provider's Transmission System is adequate to accommodate 
a request for firm service under this Tariff, all Completed 
Applications for new firm transmission service received during the 
initial sixty (60) day period commencing with the effective date of the 
Tariff will be deemed to have been filed simultaneously. A lottery 
system conducted by an independent party shall be used to assign 
priorities for Completed Applications filed simultaneously. All 
Completed Applications for firm transmission service received after the 
initial sixty (60) day period shall be assigned a priority pursuant to 
Section 13.2.
2.2 Reservation Priority For Existing Firm Service Customers
    Existing firm service customers (wholesale requirements and 
transmission-only, with a contract term of five years or more), have 
the right to continue to take transmission service from the 
Transmission Provider when the contract expires, rolls over or is 
renewed. This transmission reservation priority is independent of 
whether the existing customer continues to purchase capacity and energy 
from the Transmission Provider or elects to purchase capacity and 
energy from another supplier. If at the end of the contract term, the 
Transmission Provider's Transmission System cannot accommodate all of 
the requests for transmission service, the existing firm service 
customer must agree to accept a contract term at least equal to the 
longer of a competing request by any new Eligible Customer or five 
years and to pay the current just and reasonable rate, as approved by 
the Commission, for such service. The existing firm service customer 
must provide notice to the Transmission Provider whether it will 
exercise its right of first refusal no less than one year prior to the 
expiration date of its transmission service agreement. This 
transmission reservation priority for existing firm service customers 
is an ongoing right that may be exercised at the end of all firm 
contract terms of five years or longer. Service agreements subject to a 
right of first refusal entered into prior to [the acceptance by the 
Commission of the Transmission Provider's Attachment K], unless 
terminated, will become subject to the five year/one year requirement 
on the first rollover date after [the acceptance by the Commission of 
the Transmission Provider's Attachment K].

3 Ancillary Services

    Ancillary Services are needed with transmission service to maintain 
reliability within and among the Control Areas affected by the 
transmission service. The Transmission Provider is required to provide 
(or offer to arrange with the local Control Area operator as discussed 
below), and the Transmission Customer is required to purchase, the 
following Ancillary Services (i) Scheduling, System Control and 
Dispatch, and (ii) Reactive Supply and Voltage Control from Generation 
or Other Sources.
    The Transmission Provider is required to offer to provide (or offer 
to arrange with the local Control Area operator as discussed below) the 
following Ancillary Services only to the Transmission Customer serving 
load within the Transmission Provider's Control Area (i) Regulation and 
Frequency Response, (ii) Energy Imbalance, (iii) Operating Reserve--

[[Page 12508]]

Spinning, (iv) Operating Reserve--Supplemental, and (v) Generator 
Imbalance. The Transmission Customer serving load within the 
Transmission Provider's Control Area is required to acquire these 
Ancillary Services, whether from the Transmission Provider, from a 
third party, or by self-supply. The Transmission Customer may not 
decline the Transmission Provider's offer of Ancillary Services unless 
it demonstrates that it has acquired the Ancillary Services from 
another source. The Transmission Customer must list in its Application 
which Ancillary Services it will purchase from the Transmission 
Provider. A Transmission Customer that exceeds its firm reserved 
capacity at any Point of Receipt or Point of Delivery or an Eligible 
Customer that uses Transmission Service at a Point of Receipt or Point 
of Delivery that it has not reserved is required to pay for all of the 
Ancillary Services identified in this section that were provided by the 
Transmission Provider associated with the unreserved service. The 
Transmission Customer or Eligible Customer will pay for Ancillary 
Services based on the amount of transmission service it used but did 
not reserve.
    If the Transmission Provider is a public utility providing 
transmission service but is not a Control Area operator, it may be 
unable to provide some or all of the Ancillary Services. In this case, 
the Transmission Provider can fulfill its obligation to provide 
Ancillary Services by acting as the Transmission Customer's agent to 
secure these Ancillary Services from the Control Area operator. The 
Transmission Customer may elect to (i) have the Transmission Provider 
act as its agent, (ii) secure the Ancillary Services directly from the 
Control Area operator, or (iii) secure the Ancillary Services 
(discussed in Schedules 3, 4, 5, 6 and 9) from a third party or by 
self-supply when technically feasible.
    The Transmission Provider shall specify the rate treatment and all 
related terms and conditions in the event of an unauthorized use of 
Ancillary Services by the Transmission Customer.
    The specific Ancillary Services, prices and/or compensation methods 
are described on the Schedules that are attached to and made a part of 
the Tariff. Three principal requirements apply to discounts for 
Ancillary Services provided by the Transmission Provider in conjunction 
with its provision of transmission service as follows: (1) Any offer of 
a discount made by the Transmission Provider must be announced to all 
Eligible Customers solely by posting on the OASIS, (2) any customer-
initiated requests for discounts (including requests for use by one's 
wholesale merchant or an affiliate's use) must occur solely by posting 
on the OASIS, and (3) once a discount is negotiated, details must be 
immediately posted on the OASIS. A discount agreed upon for an 
Ancillary Service must be offered for the same period to all Eligible 
Customers on the Transmission Provider's system. Sections 3.1 through 
3.7 below list the seven Ancillary Services.
3.1 Scheduling, System Control and Dispatch Service
    The rates and/or methodology are described in Schedule 1.
3.2 Reactive Supply and Voltage Control from Generation or Other 
Sources Service
    The rates and/or methodology are described in Schedule 2.
3.3 Regulation and Frequency Response Service
    Where applicable the rates and/or methodology are described in 
Schedule 3.
3.4 Energy Imbalance Service
    Where applicable the rates and/or methodology are described in 
Schedule 4.
3.5 Operating Reserve--Spinning Reserve Service
    Where applicable the rates and/or methodology are described in 
Schedule 5.
3.6 Operating Reserve--Supplemental Reserve Service
    Where applicable the rates and/or methodology are described in 
Schedule 6.
3.7 Generator Imbalance Service
    Where applicable the rates and/or methodology are described in 
Schedule 9.

4 Open Access Same-Time Information System (OASIS)

    Terms and conditions regarding Open Access Same-Time Information 
System and standards of conduct are set forth in 18 CFR part 37 of the 
Commission's regulations (Open Access Same-Time Information System and 
Standards of Conduct for Public Utilities) and 18 CFR part 38 of the 
Commission's regulations (Business Practice Standards and Communication 
Protocols for Public Utilities). In the event available transfer 
capability as posted on the OASIS is insufficient to accommodate a 
request for firm transmission service, additional studies may be 
required as provided by this Tariff pursuant to Sections 19 and 32.
    The Transmission Provider shall post on its public Web site all 
rules, standards and practices that (i) relate to the terms and 
conditions of transmission service, (ii) are not subject to a North 
American Energy Standards Board (NAESB) copyright restriction, and 
(iii) are not otherwise included in this Tariff. The Transmission 
Provider shall post on OASIS an electronic link to these rules, 
standards and practices, and shall post on its public Web site an 
electronic link to the NAESB Web site where any rules, standards and 
practices that are protected by copyright may be obtained. The 
Transmission Provider shall also make available on its public Web site 
a statement of the process by which the Transmission Provider shall 
add, delete or otherwise modify the rules, standards and practices that 
are posted on its website. Such process shall set forth the means by 
which the Transmission Provider shall provide reasonable advance notice 
to Transmission Customers and Eligible Customers of any such additions, 
deletions or modifications, the associated effective date, and any 
additional implementation procedures that the Transmission Provider 
deems appropriate.

5 Local Furnishing Bonds

5.1 Transmission Providers That Own Facilities Financed by Local 
Furnishing Bonds
    This provision is applicable only to Transmission Providers that 
have financed facilities for the local furnishing of electric energy 
with tax-exempt bonds, as described in Section 142(f) of the Internal 
Revenue Code (``local furnishing bonds''). Notwithstanding any other 
provision of this Tariff, the Transmission Provider shall not be 
required to provide transmission service to any Eligible Customer 
pursuant to this Tariff if the provision of such transmission service 
would jeopardize the tax-exempt status of any local furnishing bond(s) 
used to finance the Transmission Provider's facilities that would be 
used in providing such transmission service.
5.2 Alternative Procedures for Requesting Transmission Service
    (i) If the Transmission Provider determines that the provision of 
transmission service requested by an Eligible Customer would jeopardize 
the tax-exempt status of any local

[[Page 12509]]

furnishing bond(s) used to finance its facilities that would be used in 
providing such transmission service, it shall advise the Eligible 
Customer within thirty (30) days of receipt of the Completed 
Application.
    (ii) If the Eligible Customer thereafter renews its request for the 
same transmission service referred to in (i) by tendering an 
application under Section 211 of the Federal Power Act, the 
Transmission Provider, within ten (10) days of receiving a copy of the 
Section 211 application, will waive its rights to a request for service 
under Section 213(a) of the Federal Power Act and to the issuance of a 
proposed order under Section 212(c) of the Federal Power Act. The 
Commission, upon receipt of the Transmission Provider's waiver of its 
rights to a request for service under Section 213(a) of the Federal 
Power Act and to the issuance of a proposed order under Section 212(c) 
of the Federal Power Act, shall issue an order under Section 211 of the 
Federal Power Act. Upon issuance of the order under Section 211 of the 
Federal Power Act, the Transmission Provider shall be required to 
provide the requested transmission service in accordance with the terms 
and conditions of this Tariff.

6 Reciprocity

    A Transmission Customer receiving transmission service under this 
Tariff agrees to provide comparable transmission service that it is 
capable of providing to the Transmission Provider on similar terms and 
conditions over facilities used for the transmission of electric energy 
owned, controlled or operated by the Transmission Customer and over 
facilities used for the transmission of electric energy owned, 
controlled or operated by the Transmission Customer's corporate 
affiliates. A Transmission Customer that is a member of, or takes 
transmission service from, a power pool, Regional Transmission Group, 
Regional Transmission Organization (RTO), Independent System Operator 
(ISO) or other transmission organization approved by the Commission for 
the operation of transmission facilities also agrees to provide 
comparable transmission service to the members of such power pool and 
Regional Transmission Group, RTO, ISO or other transmission 
organization on similar terms and conditions over facilities used for 
the transmission of electric energy owned, controlled or operated by 
the Transmission Customer and over facilities used for the transmission 
of electric energy owned, controlled or operated by the Transmission 
Customer's corporate affiliates.
    This reciprocity requirement applies not only to the Transmission 
Customer that obtains transmission service under the Tariff, but also 
to all parties to a transaction that involves the use of transmission 
service under the Tariff, including the power seller, buyer and any 
intermediary, such as a power marketer. This reciprocity requirement 
also applies to any Eligible Customer that owns, controls or operates 
transmission facilities that uses an intermediary, such as a power 
marketer, to request transmission service under the Tariff. If the 
Transmission Customer does not own, control or operate transmission 
facilities, it must include in its Application a sworn statement of one 
of its duly authorized officers or other representatives that the 
purpose of its Application is not to assist an Eligible Customer to 
avoid the requirements of this provision.

7 Billing and Payment

7.1 Billing Procedure
    Within a reasonable time after the first day of each month, the 
Transmission Provider shall submit an invoice to the Transmission 
Customer for the charges for all services furnished under the Tariff 
during the preceding month. The invoice shall be paid by the 
Transmission Customer within twenty (20) days of receipt. All payments 
shall be made in immediately available funds payable to the 
Transmission Provider, or by wire transfer to a bank named by the 
Transmission Provider.
7.2 Interest on Unpaid Balances
    Interest on any unpaid amounts (including amounts placed in escrow) 
shall be calculated in accordance with the methodology specified for 
interest on refunds in the Commission's regulations at 18 CFR 
35.19a(a)(2)(iii). Interest on delinquent amounts shall be calculated 
from the due date of the bill to the date of payment. When payments are 
made by mail, bills shall be considered as having been paid on the date 
of receipt by the Transmission Provider.
7.3 Customer Default
    In the event the Transmission Customer fails, for any reason other 
than a billing dispute as described below, to make payment to the 
Transmission Provider on or before the due date as described above, and 
such failure of payment is not corrected within thirty (30) calendar 
days after the Transmission Provider notifies the Transmission Customer 
to cure such failure, a default by the Transmission Customer shall be 
deemed to exist. Upon the occurrence of a default, the Transmission 
Provider may initiate a proceeding with the Commission to terminate 
service but shall not terminate service until the Commission so 
approves any such request. In the event of a billing dispute between 
the Transmission Provider and the Transmission Customer, the 
Transmission Provider will continue to provide service under the 
Service Agreement as long as the Transmission Customer (i) continues to 
make all payments not in dispute, and (ii) pays into an independent 
escrow account the portion of the invoice in dispute, pending 
resolution of such dispute. If the Transmission Customer fails to meet 
these two requirements for continuation of service, then the 
Transmission Provider may provide notice to the Transmission Customer 
of its intention to suspend service in sixty (60) days, in accordance 
with Commission policy.

8 Accounting for the Transmission Provider's Use of the Tariff

    The Transmission Provider shall record the following amounts, as 
outlined below.
8.1 Transmission Revenues
    Include in a separate operating revenue account or subaccount the 
revenues it receives from Transmission Service when making Third-Party 
Sales under Part II of the Tariff.
8.2 Study Costs and Revenues
    Include in a separate transmission operating expense account or 
subaccount, costs properly chargeable to expense that are incurred to 
perform any System Impact Studies or Facilities Studies which the 
Transmission Provider conducts to determine if it must construct new 
transmission facilities or upgrades necessary for its own uses, 
including making Third-Party Sales under the Tariff; and include in a 
separate operating revenue account or subaccount the revenues received 
for System Impact Studies or Facilities Studies performed when such 
amounts are separately stated and identified in the Transmission 
Customer's billing under the Tariff.

9 Regulatory Filings

    Nothing contained in the Tariff or any Service Agreement shall be 
construed as affecting in any way the right of the Transmission 
Provider to unilaterally make application to the Commission for a 
change in rates, terms and conditions, charges, classification of 
service, Service Agreement, rule or regulation under Section 205 of the 
Federal Power Act and pursuant to the Commission's rules

[[Page 12510]]

and regulations promulgated thereunder.
    Nothing contained in the Tariff or any Service Agreement shall be 
construed as affecting in any way the ability of any Party receiving 
service under the Tariff to exercise its rights under the Federal Power 
Act and pursuant to the Commission's rules and regulations promulgated 
thereunder.

10 Force Majeure and Indemnification

10.1 Force Majeure
    An event of Force Majeure means any act of God, labor disturbance, 
act of the public enemy, war, insurrection, riot, fire, storm or flood, 
explosion, breakage or accident to machinery or equipment, any 
Curtailment, order, regulation or restriction imposed by governmental 
military or lawfully established civilian authorities, or any other 
cause beyond a Party's control. A Force Majeure event does not include 
an act of negligence or intentional wrongdoing.
    Neither the Transmission Provider nor the Transmission Customer 
will be considered in default as to any obligation under this Tariff if 
prevented from fulfilling the obligation due to an event of Force 
Majeure. However, a Party whose performance under this Tariff is 
hindered by an event of Force Majeure shall make all reasonable efforts 
to perform its obligations under this Tariff.
10.2 Indemnification
    The Transmission Customer shall at all times indemnify, defend, and 
save the Transmission Provider harmless from, any and all damages, 
losses, claims, including claims and actions relating to injury to or 
death of any person or damage to property, demands, suits, recoveries, 
costs and expenses, court costs, attorney fees, and all other 
obligations by or to third parties, arising out of or resulting from 
the Transmission Provider's performance of its obligations under this 
Tariff on behalf of the Transmission Customer, except in cases of 
negligence or intentional wrongdoing by the Transmission Provider.

11 Creditworthiness

    The Transmission Provider will specify its Creditworthiness 
procedures in Attachment L.

12 Dispute Resolution Procedures

12.1 Internal Dispute Resolution Procedures
    Any dispute between a Transmission Customer and the Transmission 
Provider involving transmission service under the Tariff (excluding 
applications for rate changes or other changes to the Tariff, or to any 
Service Agreement entered into under the Tariff, which shall be 
presented directly to the Commission for resolution) shall be referred 
to a designated senior representative of the Transmission Provider and 
a senior representative of the Transmission Customer for resolution on 
an informal basis as promptly as practicable. In the event the 
designated representatives are unable to resolve the dispute within 
thirty (30) days [or such other period as the Parties may agree upon] 
by mutual agreement, such dispute may be submitted to arbitration and 
resolved in accordance with the arbitration procedures set forth below.
12.2 External Arbitration Procedures
    Any arbitration initiated under the Tariff shall be conducted 
before a single neutral arbitrator appointed by the Parties. If the 
Parties fail to agree upon a single arbitrator within ten (10) days of 
the referral of the dispute to arbitration, each Party shall choose one 
arbitrator who shall sit on a three-member arbitration panel. The two 
arbitrators so chosen shall within twenty (20) days select a third 
arbitrator to chair the arbitration panel. In either case, the 
arbitrators shall be knowledgeable in electric utility matters, 
including electric transmission and bulk power issues, and shall not 
have any current or past substantial business or financial 
relationships with any party to the arbitration (except prior 
arbitration). The arbitrator(s) shall provide each of the Parties an 
opportunity to be heard and, except as otherwise provided herein, shall 
generally conduct the arbitration in accordance with the Commercial 
Arbitration Rules of the American Arbitration Association and any 
applicable Commission regulations or Regional Transmission Group rules.
12.3 Arbitration Decisions
    Unless otherwise agreed, the arbitrator(s) shall render a decision 
within ninety (90) days of appointment and shall notify the Parties in 
writing of such decision and the reasons therefor. The arbitrator(s) 
shall be authorized only to interpret and apply the provisions of the 
Tariff and any Service Agreement entered into under the Tariff and 
shall have no power to modify or change any of the above in any manner. 
The decision of the arbitrator(s) shall be final and binding upon the 
Parties, and judgment on the award may be entered in any court having 
jurisdiction. The decision of the arbitrator(s) may be appealed solely 
on the grounds that the conduct of the arbitrator(s), or the decision 
itself, violated the standards set forth in the Federal Arbitration Act 
and/or the Administrative Dispute Resolution Act. The final decision of 
the arbitrator must also be filed with the Commission if it affects 
jurisdictional rates, terms and conditions of service or facilities.
12.4 Costs
    Each Party shall be responsible for its own costs incurred during 
the arbitration process and for the following costs, if applicable:
    1. The cost of the arbitrator chosen by the Party to sit on the 
three member panel and one half of the cost of the third arbitrator 
chosen; or
    2. One half the cost of the single arbitrator jointly chosen by the 
Parties.
12.5 Rights Under the Federal Power Act
    Nothing in this section shall restrict the rights of any party to 
file a Complaint with the Commission under relevant provisions of the 
Federal Power Act.

II. Point-To-Point Transmission Service

Preamble

    The Transmission Provider will provide Firm and Non-Firm Point-To-
Point Transmission Service pursuant to the applicable terms and 
conditions of this Tariff. Point-To-Point Transmission Service is for 
the receipt of capacity and energy at designated Point(s) of Receipt 
and the transfer of such capacity and energy to designated Point(s) of 
Delivery.

13 Nature of Firm Point-To-Point Transmission Service

13.1 Term
    The minimum term of Firm Point-To-Point Transmission Service shall 
be one day and the maximum term shall be specified in the Service 
Agreement.
13.2 Reservation Priority
    (i) Long-Term Firm Point-To-Point Transmission Service shall be 
available on a first-come, first-served basis, i.e., in the 
chronological sequence in which each Transmission Customer has 
requested service.
    (ii) Reservations for Short-Term Firm Point-To-Point Transmission 
Service will be conditional based upon the length of the requested 
transaction. However, Pre-Confirmed Applications for Short-Term Point-
to-Point Transmission Service will receive priority over earlier-
submitted requests that are not Pre-Confirmed and that have equal or 
shorter duration. Among

[[Page 12511]]

requests with the same duration and pre-confirmation status (Pre-
Confirmed or not confirmed), priority will be given to an Eligible 
Customer's request that offers the highest price, followed by the date 
and time of the request.
    (iii) If the Transmission System becomes oversubscribed, requests 
for longer term service may preempt requests for shorter term service 
up to the following deadlines: one day before the commencement of daily 
service, one week before the commencement of weekly service, and one 
month before the commencement of monthly service. Before the 
conditional reservation deadline, if available transfer capability is 
insufficient to satisfy all Applications, an Eligible Customer with a 
reservation for shorter term service or equal duration service and 
lower price has the right of first refusal to match any longer term 
request or equal duration service with a higher price before losing its 
reservation priority. A longer term competing request for Short-Term 
Firm Point-To-Point Transmission Service will be granted if the 
Eligible Customer with the right of first refusal does not agree to 
match the competing request within 24 hours (or earlier if necessary to 
comply with the scheduling deadlines provided in section 13.8) from 
being notified by the Transmission Provider of a longer-term competing 
request for Short-Term Firm Point-To-Point Transmission Service. When a 
longer duration request preempts multiple shorter duration requests, 
the shorter duration requests shall have simultaneous opportunities to 
exercise the right of first refusal. Duration, pre-confirmation status, 
price and time of response will be used to determine the order by which 
the multiple shorter duration requests will be able to exercise the 
right of first refusal. After the conditional reservation deadline, 
service will commence pursuant to the terms of Part II of the Tariff.
    (iv) Firm Point-To-Point Transmission Service will always have a 
reservation priority over Non-Firm Point-To-Point Transmission Service 
under the Tariff. All Long-Term Firm Point-To-Point Transmission 
Service will have equal reservation priority with Native Load Customers 
and Network Customers. Reservation priorities for existing firm service 
customers are provided in Section 2.2.
13.3 Use of Firm Transmission Service by the Transmission Provider
    The Transmission Provider will be subject to the rates, terms and 
conditions of Part II of the Tariff when making Third-Party Sales under 
(i) agreements executed on or after [insert date sixty (60) days after 
publication in Federal Register] or (ii) agreements executed prior to 
the aforementioned date that the Commission requires to be unbundled, 
by the date specified by the Commission. The Transmission Provider will 
maintain separate accounting, pursuant to Section 8, for any use of the 
Point-To-Point Transmission Service to make Third-Party Sales.
13.4 Service Agreements
    The Transmission Provider shall offer a standard form Firm Point-
To-Point Transmission Service Agreement (Attachment A) to an Eligible 
Customer when it submits a Completed Application for Long-Term Firm 
Point-To-Point Transmission Service. The Transmission Provider shall 
offer a standard form Firm Point-To-Point Transmission Service 
Agreement (Attachment A) to an Eligible Customer when it first submits 
a Completed Application for Short-Term Firm Point-To-Point Transmission 
Service pursuant to the Tariff. Executed Service Agreements that 
contain the information required under the Tariff shall be filed with 
the Commission in compliance with applicable Commission regulations. An 
Eligible Customer that uses Transmission Service at a Point of Receipt 
or Point of Delivery that it has not reserved and that has not executed 
a Service Agreement will be deemed, for purposes of assessing any 
appropriate charges and penalties, to have executed the appropriate 
Service Agreement. The Service Agreement shall, when applicable, 
specify any conditional curtailment options selected by the 
Transmission Customer. Where the Service Agreement contains conditional 
curtailment options and is subject to a biennial reassessment as 
described in Section 15.4, the Transmission Provider shall provide the 
Transmission Customer notice of any changes to the curtailment 
conditions no less than 90 days prior to the date for imposition of new 
curtailment conditions. Concurrent with such notice, the Transmission 
Provider shall provide the Transmission Customer with the reassessment 
study and a narrative description of the study, including the reasons 
for changes to the number of hours per year or System Conditions under 
which conditional curtailment may occur.
13.5 Transmission Customer Obligations for Facility Additions or 
Redispatch Costs
    In cases where the Transmission Provider determines that the 
Transmission System is not capable of providing Firm Point-To-Point 
Transmission Service without (1) degrading or impairing the reliability 
of service to Native Load Customers, Network Customers and other 
Transmission Customers taking Firm Point-To-Point Transmission Service, 
or (2) interfering with the Transmission Provider's ability to meet 
prior firm contractual commitments to others, the Transmission Provider 
will be obligated to expand or upgrade its Transmission System pursuant 
to the terms of Section 15.4. The Transmission Customer must agree to 
compensate the Transmission Provider for any necessary transmission 
facility additions pursuant to the terms of Section 27. To the extent 
the Transmission Provider can relieve any system constraint by 
redispatching the Transmission Provider's resources, it shall do so, 
provided that the Eligible Customer agrees to compensate the 
Transmission Provider pursuant to the terms of Section 27 and agrees to 
either (i) compensate the Transmission Provider for any necessary 
transmission facility additions or (ii) accept the service subject to a 
biennial reassessment by the Transmission Provider of redispatch 
requirements as described in Section 15.4. Any redispatch, Network 
Upgrade or Direct Assignment Facilities costs to be charged to the 
Transmission Customer on an incremental basis under the Tariff will be 
specified in the Service Agreement prior to initiating service.
13.6 Curtailment of Firm Transmission Service
    In the event that a Curtailment on the Transmission Provider's 
Transmission System, or a portion thereof, is required to maintain 
reliable operation of such system and the system directly and 
indirectly interconnected with Transmission Provider's Transmission 
System, Curtailments will be made on a non-discriminatory basis to the 
transaction(s) that effectively relieve the constraint. Transmission 
Provider may elect to implement such Curtailments pursuant to the 
Transmission Loading Relief procedures specified in Attachment J. If 
multiple transactions require Curtailment, to the extent practicable 
and consistent with Good Utility Practice, the Transmission Provider 
will curtail service to Network Customers and Transmission Customers 
taking Firm Point-To-Point Transmission Service on a basis comparable 
to the curtailment of service to the Transmission Provider's Native 
Load Customers. All Curtailments will be made on a non-discriminatory 
basis, however, Non-Firm Point-To-Point Transmission Service shall be 
subordinate to Firm Transmission

[[Page 12512]]

Service. Long-Term Firm Point-to-Point Service subject to conditions 
described in Section 15.4 shall be curtailed with secondary service in 
cases where the conditions apply, but otherwise will be curtailed on a 
pro rata basis with other Firm Transmission Service. When the 
Transmission Provider determines that an electrical emergency exists on 
its Transmission System and implements emergency procedures to Curtail 
Firm Transmission Service, the Transmission Customer shall make the 
required reductions upon request of the Transmission Provider. However, 
the Transmission Provider reserves the right to Curtail, in whole or in 
part, any Firm Transmission Service provided under the Tariff when, in 
the Transmission Provider's sole discretion, an emergency or other 
unforeseen condition impairs or degrades the reliability of its 
Transmission System. The Transmission Provider will notify all affected 
Transmission Customers in a timely manner of any scheduled 
Curtailments.
13.7 Classification of Firm Transmission Service
    (a) The Transmission Customer taking Firm Point-To-Point 
Transmission Service may (1) change its Receipt and Delivery Points to 
obtain service on a non-firm basis consistent with the terms of Section 
22.1 or (2) request a modification of the Points of Receipt or Delivery 
on a firm basis pursuant to the terms of Section 22.2.
    (b) The Transmission Customer may purchase transmission service to 
make sales of capacity and energy from multiple generating units that 
are on the Transmission Provider's Transmission System. For such a 
purchase of transmission service, the resources will be designated as 
multiple Points of Receipt, unless the multiple generating units are at 
the same generating plant in which case the units would be treated as a 
single Point of Receipt.
    (c) The Transmission Provider shall provide firm deliveries of 
capacity and energy from the Point(s) of Receipt to the Point(s) of 
Delivery. Each Point of Receipt at which firm transmission capacity is 
reserved by the Transmission Customer shall be set forth in the Firm 
Point-To-Point Service Agreement for Long-Term Firm Transmission 
Service along with a corresponding capacity reservation associated with 
each Point of Receipt. Points of Receipt and corresponding capacity 
reservations shall be as mutually agreed upon by the Parties for Short-
Term Firm Transmission. Each Point of Delivery at which firm transfer 
capability is reserved by the Transmission Customer shall be set forth 
in the Firm Point-To-Point Service Agreement for Long-Term Firm 
Transmission Service along with a corresponding capacity reservation 
associated with each Point of Delivery. Points of Delivery and 
corresponding capacity reservations shall be as mutually agreed upon by 
the Parties for Short-Term Firm Transmission. The greater of either (1) 
the sum of the capacity reservations at the Point(s) of Receipt, or (2) 
the sum of the capacity reservations at the Point(s) of Delivery shall 
be the Transmission Customer's Reserved Capacity. The Transmission 
Customer will be billed for its Reserved Capacity under the terms of 
Schedule 7. The Transmission Customer may not exceed its firm capacity 
reserved at each Point of Receipt and each Point of Delivery except as 
otherwise specified in Section 22. The Transmission Provider shall 
specify the rate treatment and all related terms and conditions 
applicable in the event that a Transmission Customer (including Third-
Party Sales by the Transmission Provider) exceeds its firm reserved 
capacity at any Point of Receipt or Point of Delivery or uses 
Transmission Service at a Point of Receipt or Point of Delivery that it 
has not reserved.
13.8 Scheduling of Firm Point-To-Point Transmission Service
    Schedules for the Transmission Customer's Firm Point-To-Point 
Transmission Service must be submitted to the Transmission Provider no 
later than 10 a.m. [or a reasonable time that is generally accepted in 
the region and is consistently adhered to by the Transmission Provider] 
of the day prior to commencement of such service. Schedules submitted 
after 10 a.m. will be accommodated, if practicable. Hour-to-hour 
schedules of any capacity and energy that is to be delivered must be 
stated in increments of 1,000 kW per hour [or a reasonable increment 
that is generally accepted in the region and is consistently adhered to 
by the Transmission Provider]. Transmission Customers within the 
Transmission Provider's service area with multiple requests for 
Transmission Service at a Point of Receipt, each of which is under 
1,000 kW per hour, may consolidate their service requests at a common 
point of receipt into units of 1,000 kW per hour for scheduling and 
billing purposes. Scheduling changes will be permitted up to twenty 
(20) minutes [or a reasonable time that is generally accepted in the 
region and is consistently adhered to by the Transmission Provider] 
before the start of the next clock hour provided that the Delivering 
Party and Receiving Party also agree to the schedule modification. The 
Transmission Provider will furnish to the Delivering Party's system 
operator, hour-to-hour schedules equal to those furnished by the 
Receiving Party (unless reduced for losses) and shall deliver the 
capacity and energy provided by such schedules. Should the Transmission 
Customer, Delivering Party or Receiving Party revise or terminate any 
schedule, such party shall immediately notify the Transmission 
Provider, and the Transmission Provider shall have the right to adjust 
accordingly the schedule for capacity and energy to be received and to 
be delivered.

14 Nature of Non-Firm Point-To-Point Transmission Service

14.1 Term
    Non-Firm Point-To-Point Transmission Service will be available for 
periods ranging from one (1) hour to one (1) month. However, a 
Purchaser of Non-Firm Point-To-Point Transmission Service will be 
entitled to reserve a sequential term of service (such as a sequential 
monthly term without having to wait for the initial term to expire 
before requesting another monthly term) so that the total time period 
for which the reservation applies is greater than one month, subject to 
the requirements of Section 18.3.
14.2 Reservation Priority
    Non-Firm Point-To-Point Transmission Service shall be available 
from transfer capability in excess of that needed for reliable service 
to Native Load Customers, Network Customers and other Transmission 
Customers taking Long-Term and Short-Term Firm Point-To-Point 
Transmission Service. A higher priority will be assigned first to 
reservations with a longer duration of service and second to Pre-
Confirmed Applications. In the event the Transmission System is 
constrained, competing requests of the same Pre-Confirmation status and 
equal duration will be prioritized based on the highest price offered 
by the Eligible Customer for the Transmission Service. Eligible 
Customers that have already reserved shorter term service have the 
right of first refusal to match any longer term reservation before 
being preempted. A longer term competing request for Non-Firm Point-To-
Point Transmission Service will be granted if the Eligible Customer 
with the right of first refusal does not agree to match the competing 
request: (a) Immediately for hourly Non-Firm Point-To-Point 
Transmission Service after notification by the Transmission Provider; 
and, (b) within 24 hours (or earlier if necessary to

[[Page 12513]]

comply with the scheduling deadlines provided in section 14.6) for Non-
Firm Point-To-Point Transmission Service other than hourly transactions 
after notification by the Transmission Provider. Transmission service 
for Network Customers from resources other than designated Network 
Resources will have a higher priority than any Non-Firm Point-To-Point 
Transmission Service. Non-Firm Point-To-Point Transmission Service over 
secondary Point(s) of Receipt and Point(s) of Delivery will have the 
lowest reservation priority under the Tariff.
14.3 Use of Non-Firm Point-To-Point Transmission Service by the 
Transmission Provider
    The Transmission Provider will be subject to the rates, terms and 
conditions of Part II of the Tariff when making Third-Party Sales under 
(i) agreements executed on or after May 14, 2007 or (ii) agreements 
executed prior to the aforementioned date that the Commission requires 
to be unbundled, by the date specified by the Commission. The 
Transmission Provider will maintain separate accounting, pursuant to 
Section 8, for any use of Non-Firm Point-To-Point Transmission Service 
to make Third-Party Sales.
14.4 Service Agreements
    The Transmission Provider shall offer a standard form Non-Firm 
Point-To-Point Transmission Service Agreement (Attachment B) to an 
Eligible Customer when it first submits a Completed Application for 
Non-Firm Point-To-Point Transmission Service pursuant to the Tariff. 
Executed Service Agreements that contain the information required under 
the Tariff shall be filed with the Commission in compliance with 
applicable Commission regulations.
14.5 Classification of Non-Firm Point-To-Point Transmission Service
    Non-Firm Point-To-Point Transmission Service shall be offered under 
terms and conditions contained in Part II of the Tariff. The 
Transmission Provider undertakes no obligation under the Tariff to plan 
its Transmission System in order to have sufficient capacity for Non-
Firm Point-To-Point Transmission Service. Parties requesting Non-Firm 
Point-To-Point Transmission Service for the transmission of firm power 
do so with the full realization that such service is subject to 
availability and to Curtailment or Interruption under the terms of the 
Tariff. The Transmission Provider shall specify the rate treatment and 
all related terms and conditions applicable in the event that a 
Transmission Customer (including Third-Party Sales by the Transmission 
Provider) exceeds its non-firm capacity reservation. Non-Firm Point-To-
Point Transmission Service shall include transmission of energy on an 
hourly basis and transmission of scheduled short-term capacity and 
energy on a daily, weekly or monthly basis, but not to exceed one 
month's reservation for any one Application, under Schedule 8.
14.6 Scheduling of Non-Firm Point-To-Point Transmission Service
    Schedules for Non-Firm Point-To-Point Transmission Service must be 
submitted to the Transmission Provider no later than 2 p.m. [or a 
reasonable time that is generally accepted in the region and is 
consistently adhered to by the Transmission Provider] of the day prior 
to commencement of such service. Schedules submitted after 2 p.m. will 
be accommodated, if practicable. Hour-to-hour schedules of energy that 
is to be delivered must be stated in increments of 1,000 kW per hour 
[or a reasonable increment that is generally accepted in the region and 
is consistently adhered to by the Transmission Provider]. Transmission 
Customers within the Transmission Provider's service area with multiple 
requests for Transmission Service at a Point of Receipt, each of which 
is under 1,000 kW per hour, may consolidate their schedules at a common 
Point of Receipt into units of 1,000 kW per hour. Scheduling changes 
will be permitted up to twenty (20) minutes [or a reasonable time that 
is generally accepted in the region and is consistently adhered to by 
the Transmission Provider] before the start of the next clock hour 
provided that the Delivering Party and Receiving Party also agree to 
the schedule modification. The Transmission Provider will furnish to 
the Delivering Party's system operator, hour-to-hour schedules equal to 
those furnished by the Receiving Party (unless reduced for losses) and 
shall deliver the capacity and energy provided by such schedules. 
Should the Transmission Customer, Delivering Party or Receiving Party 
revise or terminate any schedule, such party shall immediately notify 
the Transmission Provider, and the Transmission Provider shall have the 
right to adjust accordingly the schedule for capacity and energy to be 
received and to be delivered.
14.7 Curtailment or Interruption of Service
    The Transmission Provider reserves the right to Curtail, in whole 
or in part, Non-Firm Point-To-Point Transmission Service provided under 
the Tariff for reliability reasons when an emergency or other 
unforeseen condition threatens to impair or degrade the reliability of 
its Transmission System or the systems directly and indirectly 
interconnected with Transmission Provider's Transmission System. 
Transmission Provider may elect to implement such Curtailments pursuant 
to the Transmission Loading Relief procedures specified in Attachment 
J. The Transmission Provider reserves the right to Interrupt, in whole 
or in part, Non-Firm Point-To-Point Transmission Service provided under 
the Tariff for economic reasons in order to accommodate (1) a request 
for Firm Transmission Service, (2) a request for Non-Firm Point-To-
Point Transmission Service of greater duration, (3) a request for Non-
Firm Point-To-Point Transmission Service of equal duration with a 
higher price, (4) transmission service for Network Customers from non-
designated resources, or (5) transmission service for Firm Point-to-
Point Transmission Service during conditional curtailment periods as 
described in Section 15.4. The Transmission Provider also will 
discontinue or reduce service to the Transmission Customer to the 
extent that deliveries for transmission are discontinued or reduced at 
the Point(s) of Receipt. Where required, Curtailments or Interruptions 
will be made on a non-discriminatory basis to the transaction(s) that 
effectively relieve the constraint, however, Non-Firm Point-To-Point 
Transmission Service shall be subordinate to Firm Transmission Service. 
If multiple transactions require Curtailment or Interruption, to the 
extent practicable and consistent with Good Utility Practice, 
Curtailments or Interruptions will be made to transactions of the 
shortest term (e.g., hourly non-firm transactions will be Curtailed or 
Interrupted before daily non-firm transactions and daily non-firm 
transactions will be Curtailed or Interrupted before weekly non-firm 
transactions). Transmission service for Network Customers from 
resources other than designated Network Resources will have a higher 
priority than any Non-Firm Point-To-Point Transmission Service under 
the Tariff. Non-Firm Point-To-Point Transmission Service over secondary 
Point(s) of Receipt and Point(s) of Delivery will have a lower priority 
than any Non-Firm Point-To-Point Transmission Service under the Tariff. 
The Transmission Provider will provide advance notice of Curtailment or 
Interruption where such

[[Page 12514]]

notice can be provided consistent with Good Utility Practice.

15 Service Availability

15.1 General Conditions
    The Transmission Provider will provide Firm and Non-Firm Point-To-
Point Transmission Service over, on or across its Transmission System 
to any Transmission Customer that has met the requirements of Section 
16.
15.2 Determination of Available Transfer Capability
    A description of the Transmission Provider's specific methodology 
for assessing available transfer capability posted on the Transmission 
Provider's OASIS (Section 4) is contained in Attachment C of the 
Tariff. In the event sufficient transfer capability may not exist to 
accommodate a service request, the Transmission Provider will respond 
by performing a System Impact Study.
15.3 Initiating Service in the Absence of an Executed Service Agreement
    If the Transmission Provider and the Transmission Customer 
requesting Firm or Non-Firm Point-To-Point Transmission Service cannot 
agree on all the terms and conditions of the Point-To-Point Service 
Agreement, the Transmission Provider shall file with the Commission, 
within thirty (30) days after the date the Transmission Customer 
provides written notification directing the Transmission Provider to 
file, an unexecuted Point-To-Point Service Agreement containing terms 
and conditions deemed appropriate by the Transmission Provider for such 
requested Transmission Service. The Transmission Provider shall 
commence providing Transmission Service subject to the Transmission 
Customer agreeing to (i) compensate the Transmission Provider at 
whatever rate the Commission ultimately determines to be just and 
reasonable, and (ii) comply with the terms and conditions of the Tariff 
including posting appropriate security deposits in accordance with the 
terms of Section 17.3.
15.4 Obligation To Provide Transmission Service That Requires Expansion 
or Modification of the Transmission System, Redispatch or Conditional 
Curtailment
    (a) If the Transmission Provider determines that it cannot 
accommodate a Completed Application for Firm Point-To-Point 
Transmission Service because of insufficient capability on its 
Transmission System, the Transmission Provider will use due diligence 
to expand or modify its Transmission System to provide the requested 
Firm Transmission Service, consistent with its planning obligations in 
Attachment K, provided the Transmission Customer agrees to compensate 
the Transmission Provider for such costs pursuant to the terms of 
Section 27. The Transmission Provider will conform to Good Utility 
Practice and its planning obligations in Attachment K, in determining 
the need for new facilities and in the design and construction of such 
facilities. The obligation applies only to those facilities that the 
Transmission Provider has the right to expand or modify.
    (b) If the Transmission Provider determines that it cannot 
accommodate a Completed Application for Firm Point-To-Point 
Transmission Service because of insufficient capability on its 
Transmission System, the Transmission Provider will use due diligence 
to provide redispatch from its own resources until (i) Network Upgrades 
are completed for the Transmission Customer, (ii) the Transmission 
Provider determines through a biennial reassessment that it can no 
longer reliably provide the redispatch, or (iii) the Transmission 
Customer terminates the service because of redispatch changes resulting 
from the reassessment. A Transmission Provider shall not unreasonably 
deny self-provided redispatch or redispatch arranged by the 
Transmission Customer from a third party resource.
    (c) If the Transmission Provider determines that it cannot 
accommodate a Completed Application for Firm Point-To-Point 
Transmission Service because of insufficient capability on its 
Transmission System, the Transmission Provider will offer the Firm 
Transmission Service with the condition that the Transmission Provider 
may curtail the service prior to the curtailment of other Firm 
Transmission Service for a specified number of hours per year or during 
System Condition(s). If the Transmission Customer accepts the service, 
the Transmission Provider will use due diligence to provide the service 
until (i) Network Upgrades are completed for the Transmission Customer, 
(ii) the Transmission Provider determines through a biennial 
reassessment that it can no longer reliably provide such service, or 
(iii) the Transmission Customer terminates the service because the 
reassessment increased the number of hours per year of conditional 
curtailment or changed the System Conditions.
15.5 Deferral of Service
    The Transmission Provider may defer providing service until it 
completes construction of new transmission facilities or upgrades 
needed to provide Firm Point-To-Point Transmission Service whenever the 
Transmission Provider determines that providing the requested service 
would, without such new facilities or upgrades, impair or degrade 
reliability to any existing firm services.
15.6 Other Transmission Service Schedules
    Eligible Customers receiving transmission service under other 
agreements on file with the Commission may continue to receive 
transmission service under those agreements until such time as those 
agreements may be modified by the Commission.
15.7 Real Power Losses
    Real Power Losses are associated with all transmission service. The 
Transmission Provider is not obligated to provide Real Power Losses. 
The Transmission Customer is responsible for replacing losses 
associated with all transmission service as calculated by the 
Transmission Provider. The applicable Real Power Loss factors are as 
follows: [To be completed by the Transmission Provider].

16 Transmission Customer Responsibilities

16.1 Conditions Required of Transmission Customers
    Point-To-Point Transmission Service shall be provided by the 
Transmission Provider only if the following conditions are satisfied by 
the Transmission Customer:
    (a) The Transmission Customer has pending a Completed Application 
for service;
    (b) The Transmission Customer meets the creditworthiness criteria 
set forth in Section 11;
    (c) The Transmission Customer will have arrangements in place for 
any other transmission service necessary to effect the delivery from 
the generating source to the Transmission Provider prior to the time 
service under Part II of the Tariff commences;
    (d) The Transmission Customer agrees to pay for any facilities 
constructed and chargeable to such Transmission Customer under Part II 
of the Tariff, whether or not the Transmission Customer takes service 
for the full term of its reservation;
    (e) The Transmission Customer provides the information required by 
the Transmission Provider's planning process established in Attachment 
K; and
    (f) The Transmission Customer has executed a Point-To-Point Service


[[Continued on page 12515]]


From the Federal Register Online via GPO Access [wais.access.gpo.gov]
]                         
 
[[pp. 12515-12531]] Preventing Undue Discrimination and Preference in Transmission 
Service

[[Continued from page 12514]]

[[Page 12515]]

Agreement or has agreed to receive service pursuant to Section 15.3.
16.2 Transmission Customer Responsibility for Third-Party Arrangements
    Any scheduling arrangements that may be required by other electric 
systems shall be the responsibility of the Transmission Customer 
requesting service. The Transmission Customer shall provide, unless 
waived by the Transmission Provider, notification to the Transmission 
Provider identifying such systems and authorizing them to schedule the 
capacity and energy to be transmitted by the Transmission Provider 
pursuant to Part II of the Tariff on behalf of the Receiving Party at 
the Point of Delivery or the Delivering Party at the Point of Receipt. 
However, the Transmission Provider will undertake reasonable efforts to 
assist the Transmission Customer in making such arrangements, including 
without limitation, providing any information or data required by such 
other electric system pursuant to Good Utility Practice.

17 Procedures for Arranging Firm Point-To-Point Transmission Service

17.1 Application
    A request for Firm Point-To-Point Transmission Service for periods 
of one year or longer must contain a written Application to: 
[Transmission Provider Name and Address], at least sixty (60) days in 
advance of the calendar month in which service is to commence. The 
Transmission Provider will consider requests for such firm service on 
shorter notice when feasible. Requests for firm service for periods of 
less than one year shall be subject to expedited procedures that shall 
be negotiated between the Parties within the time constraints provided 
in Section 17.5. All Firm Point-To-Point Transmission Service requests 
should be submitted by entering the information listed below on the 
Transmission Provider's OASIS. Prior to implementation of the 
Transmission Provider's OASIS, a Completed Application may be submitted 
by (i) transmitting the required information to the Transmission 
Provider by telefax, or (ii) providing the information by telephone 
over the Transmission Provider's time recorded telephone line. Each of 
these methods will provide a time-stamped record for establishing the 
priority of the Application.
17.2 Completed Application
    A Completed Application shall provide all of the information 
included in 18 CFR 2.20 including but not limited to the following:
    (i) The identity, address, telephone number and facsimile number of 
the entity requesting service;
    (ii) A statement that the entity requesting service is, or will be 
upon commencement of service, an Eligible Customer under the Tariff;
    (iii) The location of the Point(s) of Receipt and Point(s) of 
Delivery and the identities of the Delivering Parties and the Receiving 
Parties;
    (iv) The location of the generating facility(ies) supplying the 
capacity and energy and the location of the load ultimately served by 
the capacity and energy transmitted. The Transmission Provider will 
treat this information as confidential except to the extent that 
disclosure of this information is required by this Tariff, by 
regulatory or judicial order, for reliability purposes pursuant to Good 
Utility Practice or pursuant to RTG transmission information sharing 
agreements. The Transmission Provider shall treat this information 
consistent with the standards of conduct contained in Part 37 of the 
Commission's regulations;
    (v) A description of the supply characteristics of the capacity and 
energy to be delivered;
    (vi) An estimate of the capacity and energy expected to be 
delivered to the Receiving Party;
    (vii) The Service Commencement Date and the term of the requested 
Transmission Service;
    (viii) The transmission capacity requested for each Point of 
Receipt and each Point of Delivery on the Transmission Provider's 
Transmission System; customers may combine their requests for service 
in order to satisfy the minimum transmission capacity requirement;
    (ix) A statement indicating whether the Transmission Customer 
commits to a Pre-Confirmed Request, i.e., will execute a Service 
Agreement upon receipt of notification that the Transmission Provider 
can provide the requested Transmission Service; and
    (x) Any additional information required by the Transmission 
Provider's planning process established in Attachment K.
    The Transmission Provider shall treat this information consistent 
with the standards of conduct contained in Part 37 of the Commission's 
regulations.
17.3 Deposit
    A Completed Application for Firm Point-To-Point Transmission 
Service also shall include a deposit of either one month's charge for 
Reserved Capacity or the full charge for Reserved Capacity for service 
requests of less than one month. If the Application is rejected by the 
Transmission Provider because it does not meet the conditions for 
service as set forth herein, or in the case of requests for service 
arising in connection with losing bidders in a Request For Proposals 
(RFP), said deposit shall be returned with interest less any reasonable 
costs incurred by the Transmission Provider in connection with the 
review of the losing bidder's Application. The deposit also will be 
returned with interest less any reasonable costs incurred by the 
Transmission Provider if the Transmission Provider is unable to 
complete new facilities needed to provide the service. If an 
Application is withdrawn or the Eligible Customer decides not to enter 
into a Service Agreement for Firm Point-To-Point Transmission Service, 
the deposit shall be refunded in full, with interest, less reasonable 
costs incurred by the Transmission Provider to the extent such costs 
have not already been recovered by the Transmission Provider from the 
Eligible Customer. The Transmission Provider will provide to the 
Eligible Customer a complete accounting of all costs deducted from the 
refunded deposit, which the Eligible Customer may contest if there is a 
dispute concerning the deducted costs. Deposits associated with 
construction of new facilities are subject to the provisions of Section 
19. If a Service Agreement for Firm Point-To-Point Transmission Service 
is executed, the deposit, with interest, will be returned to the 
Transmission Customer upon expiration or termination of the Service 
Agreement for Firm Point-To-Point Transmission Service. Applicable 
interest shall be computed in accordance with the Commission's 
regulations at 18 CFR 35.19a(a)(2)(iii), and shall be calculated from 
the day the deposit check is credited to the Transmission Provider's 
account.
17.4 Notice of Deficient Application
    If an Application fails to meet the requirements of the Tariff, the 
Transmission Provider shall notify the entity requesting service within 
fifteen (15) days of receipt of the reasons for such failure. The 
Transmission Provider will attempt to remedy minor deficiencies in the 
Application through informal communications with the Eligible Customer. 
If such efforts are unsuccessful, the Transmission Provider shall 
return the Application, along with any deposit, with interest. Upon 
receipt of a new or revised Application that fully complies with the 
requirements of Part II of the Tariff, the Eligible

[[Page 12516]]

Customer shall be assigned a new priority consistent with the date of 
the new or revised Application.
17.5 Response to a Completed Application
    Following receipt of a Completed Application for Firm Point-To-
Point Transmission Service, the Transmission Provider shall make a 
determination of available transfer capability as required in Section 
15.2. The Transmission Provider shall notify the Eligible Customer as 
soon as practicable, but not later than thirty (30) days after the date 
of receipt of a Completed Application either (i) if it will be able to 
provide service without performing a System Impact Study or (ii) if 
such a study is needed to evaluate the impact of the Application 
pursuant to Section 19.1. Responses by the Transmission Provider must 
be made as soon as practicable to all completed applications (including 
applications by its own merchant function) and the timing of such 
responses must be made on a non-discriminatory basis.
 17.6 Execution of Service Agreement
    Whenever the Transmission Provider determines that a System Impact 
Study is not required and that the service can be provided, it shall 
notify the Eligible Customer as soon as practicable but no later than 
thirty (30) days after receipt of the Completed Application. Where a 
System Impact Study is required, the provisions of Section 19 will 
govern the execution of a Service Agreement. Failure of an Eligible 
Customer to execute and return the Service Agreement or request the 
filing of an unexecuted service agreement pursuant to Section 15.3, 
within fifteen (15) days after it is tendered by the Transmission 
Provider will be deemed a withdrawal and termination of the Application 
and any deposit submitted shall be refunded with interest. Nothing 
herein limits the right of an Eligible Customer to file another 
Application after such withdrawal and termination.
17.7 Extensions for Commencement of Service
    The Transmission Customer can obtain up to five (5) one-year 
extensions for the commencement of service. The Transmission Customer 
may postpone service by paying a non-refundable annual reservation fee 
equal to one-month's charge for Firm Transmission Service for each year 
or fraction thereof. If the Eligible Customer does not pay this non-
refundable reservation fee within 15 days of notifying the Transmission 
Provider it intends to extend the commencement of service, then the 
Eligible Customer's application shall be deemed withdrawn and its 
deposit, pursuant to Section 17.3, shall be returned with interest. If 
during any extension for the commencement of service an Eligible 
Customer submits a Completed Application for Firm Transmission Service, 
and such request can be satisfied only by releasing all or part of the 
Transmission Customer's Reserved Capacity, the original Reserved 
Capacity will be released unless the following condition is satisfied. 
Within thirty (30) days, the original Transmission Customer agrees to 
pay the Firm Point-To-Point transmission rate for its Reserved Capacity 
concurrent with the new Service Commencement Date. In the event the 
Transmission Customer elects to release the Reserved Capacity, the 
reservation fees or portions thereof previously paid will be forfeited.
18 Procedures for Arranging Non-Firm Point-To-Point Transmission 
Service
 18.1 Application
    Eligible Customers seeking Non-Firm Point-To-Point Transmission 
Service must submit a Completed Application to the Transmission 
Provider. Applications should be submitted by entering the information 
listed below on the Transmission Provider's OASIS. Prior to 
implementation of the Transmission Provider's OASIS, a Completed 
Application may be submitted by (i) transmitting the required 
information to the Transmission Provider by telefax, or (ii) providing 
the information by telephone over the Transmission Provider's time 
recorded telephone line. Each of these methods will provide a time-
stamped record for establishing the service priority of the 
Application.
18.2 Completed Application
    A Completed Application shall provide all of the information 
included in 18 CFR 2.20 including but not limited to the following:
    (i) The identity, address, telephone number and facsimile number of 
the entity requesting service;
    (ii) A statement that the entity requesting service is, or will be 
upon commencement of service, an Eligible Customer under the Tariff;
    (iii) The Point(s) of Receipt and the Point(s) of Delivery;
    (iv) The maximum amount of capacity requested at each Point of 
Receipt and Point of Delivery; and
    (v) The proposed dates and hours for initiating and terminating 
transmission service hereunder.
    In addition to the information specified above, when required to 
properly evaluate system conditions, the Transmission Provider also may 
ask the Transmission Customer to provide the following:
    (vi) The electrical location of the initial source of the power to 
be transmitted pursuant to the Transmission Customer's request for 
service; and
    (vii) The electrical location of the ultimate load.
    The Transmission Provider will treat this information in (vi) and 
(vii) as confidential at the request of the Transmission Customer 
except to the extent that disclosure of this information is required by 
this Tariff, by regulatory or judicial order, for reliability purposes 
pursuant to Good Utility Practice, or pursuant to RTG transmission 
information sharing agreements. The Transmission Provider shall treat 
this information consistent with the standards of conduct contained in 
Part 37 of the Commission's regulations.
    (viii) A statement indicating whether the Transmission Customer 
commits to a Pre-Confirmed Request, i.e., will execute a Service 
Agreement upon receipt of notification that the Transmission Provider 
can provide the requested Transmission Service.
18.3 Reservation of Non-Firm Point-to-Point Transmission Service
    Requests for monthly service shall be submitted no earlier than 
sixty (60) days before service is to commence; requests for weekly 
service shall be submitted no earlier than fourteen (14) days before 
service is to commence, requests for daily service shall be submitted 
no earlier than two (2) days before service is to commence, and 
requests for hourly service shall be submitted no earlier than noon the 
day before service is to commence. Requests for service received later 
than 2 p.m. prior to the day service is scheduled to commence will be 
accommodated if practicable [or such reasonable times that are 
generally accepted in the region and are consistently adhered to by the 
Transmission Provider].
18.4 Determination of Available Transfer Capability
    Following receipt of a tendered schedule the Transmission Provider 
will make a determination on a non-discriminatory basis of available 
transfer capability pursuant to Section 15.2. Such determination shall 
be made as soon as reasonably practicable after receipt, but not later 
than the following time periods for the following terms of service (i) 
thirty (30) minutes for hourly service, (ii) thirty (30) minutes for 
daily

[[Page 12517]]

service, (iii) four (4) hours for weekly service, and (iv) two (2) days 
for monthly service. [Or such reasonable times that are generally 
accepted in the region and are consistently adhered to by the 
Transmission Provider].

19 Additional Study Procedures for Firm Point-to-Point Transmission 
Service Requests

19.1 Notice of Need for System Impact Study
    After receiving a request for service, the Transmission Provider 
shall determine on a non-discriminatory basis whether a System Impact 
Study is needed. A description of the Transmission Provider's 
methodology for completing a System Impact Study is provided in 
Attachment D. If the Transmission Provider determines that a System 
Impact Study is necessary to accommodate the requested service, it 
shall so inform the Eligible Customer, as soon as practicable. Once 
informed, the Eligible Customer shall timely notify the Transmission 
Provider if it elects not to have the Transmission Provider study 
redispatch or conditional curtailment as part of the System Impact 
Study. If notification is provided prior to tender of the System Impact 
Study Agreement, the Eligible Customer can avoid the costs associated 
with the study of these options. The Transmission Provider shall within 
thirty (30) days of receipt of a Completed Application, tender a System 
Impact Study Agreement pursuant to which the Eligible Customer shall 
agree to reimburse the Transmission Provider for performing the 
required System Impact Study. For a service request to remain a 
Completed Application, the Eligible Customer shall execute the System 
Impact Study Agreement and return it to the Transmission Provider 
within fifteen (15) days. If the Eligible Customer elects not to 
execute the System Impact Study Agreement, its application shall be 
deemed withdrawn and its deposit, pursuant to Section 17.3, shall be 
returned with interest.
19.2 System Impact Study Agreement and Cost Reimbursement
    (i) The System Impact Study Agreement will clearly specify the 
Transmission Provider's estimate of the actual cost, and time for 
completion of the System Impact Study. The charge shall not exceed the 
actual cost of the study. In performing the System Impact Study, the 
Transmission Provider shall rely, to the extent reasonably practicable, 
on existing transmission planning studies. The Eligible Customer will 
not be assessed a charge for such existing studies; however, the 
Eligible Customer will be responsible for charges associated with any 
modifications to existing planning studies that are reasonably 
necessary to evaluate the impact of the Eligible Customer's request for 
service on the Transmission System.
    (ii) If in response to multiple Eligible Customers requesting 
service in relation to the same competitive solicitation, a single 
System Impact Study is sufficient for the Transmission Provider to 
accommodate the requests for service, the costs of that study shall be 
pro-rated among the Eligible Customers.
    (iii) For System Impact Studies that the Transmission Provider 
conducts on its own behalf, the Transmission Provider shall record the 
cost of the System Impact Studies pursuant to Section 20.
19.3 System Impact Study Procedures
    Upon receipt of an executed System Impact Study Agreement, the 
Transmission Provider will use due diligence to complete the required 
System Impact Study within a sixty (60) day period. The System Impact 
Study shall identify (1) any system constraints, identified with 
specificity by transmission element or flowgate, (2) redispatch options 
(when requested by a Transmission Customer) including an estimate of 
the cost of redispatch, (3) conditional curtailment options (when 
requested by a Transmission Customer) including the number of hours per 
year and the System Conditions during which conditional curtailment may 
occur, and (4) additional Direct Assignment Facilities or Network 
Upgrades required to provide the requested service. For customers 
requesting the study of redispatch options, the System Impact Study 
shall (1) identify all resources located within the Transmission 
Provider's Control Area that can significantly contribute toward 
relieving the system constraint and (2) provide a measurement of each 
resource's impact on the system constraint. If the Transmission 
Provider possesses information indicating that any resource outside its 
Control Area could relieve the constraint, it shall identify each such 
resource in the System Impact Study. In the event that the Transmission 
Provider is unable to complete the required System Impact Study within 
such time period, it shall so notify the Eligible Customer and provide 
an estimated completion date along with an explanation of the reasons 
why additional time is required to complete the required studies. A 
copy of the completed System Impact Study and related work papers shall 
be made available to the Eligible Customer as soon as the System Impact 
Study is complete. The Transmission Provider will use the same due 
diligence in completing the System Impact Study for an Eligible 
Customer as it uses when completing studies for itself. The 
Transmission Provider shall notify the Eligible Customer immediately 
upon completion of the System Impact Study if the Transmission System 
will be adequate to accommodate all or part of a request for service or 
that no costs are likely to be incurred for new transmission facilities 
or upgrades. In order for a request to remain a Completed Application, 
within fifteen (15) days of completion of the System Impact Study the 
Eligible Customer must execute a Service Agreement or request the 
filing of an unexecuted Service Agreement pursuant to Section 15.3, or 
the Application shall be deemed terminated and withdrawn.
19.4 Facilities Study Procedures
    If a System Impact Study indicates that additions or upgrades to 
the Transmission System are needed to supply the Eligible Customer's 
service request, the Transmission Provider, within thirty (30) days of 
the completion of the System Impact Study, shall tender to the Eligible 
Customer a Facilities Study Agreement pursuant to which the Eligible 
Customer shall agree to reimburse the Transmission Provider for 
performing the required Facilities Study. For a service request to 
remain a Completed Application, the Eligible Customer shall execute the 
Facilities Study Agreement and return it to the Transmission Provider 
within fifteen (15) days. If the Eligible Customer elects not to 
execute the Facilities Study Agreement, its application shall be deemed 
withdrawn and its deposit, pursuant to Section 17.3, shall be returned 
with interest. Upon receipt of an executed Facilities Study Agreement, 
the Transmission Provider will use due diligence to complete the 
required Facilities Study within a sixty (60) day period. If the 
Transmission Provider is unable to complete the Facilities Study in the 
allotted time period, the Transmission Provider shall notify the 
Transmission Customer and provide an estimate of the time needed to 
reach a final determination along with an explanation of the reasons 
that additional time is required to complete the study. When completed, 
the Facilities Study will include a good faith estimate of (i) the cost 
of Direct Assignment Facilities to be charged to the Transmission 
Customer, (ii) the Transmission Customer's appropriate share of the 
cost of any required

[[Page 12518]]

Network Upgrades as determined pursuant to the provisions of Part II of 
the Tariff, and (iii) the time required to complete such construction 
and initiate the requested service. The Transmission Customer shall 
provide the Transmission Provider with a letter of credit or other 
reasonable form of security acceptable to the Transmission Provider 
equivalent to the costs of new facilities or upgrades consistent with 
commercial practices as established by the Uniform Commercial Code. The 
Transmission Customer shall have thirty (30) days to execute a Service 
Agreement or request the filing of an unexecuted Service Agreement and 
provide the required letter of credit or other form of security or the 
request will no longer be a Completed Application and shall be deemed 
terminated and withdrawn.
19.5 Facilities Study Modifications
    Any change in design arising from inability to site or construct 
facilities as proposed will require development of a revised good faith 
estimate. New good faith estimates also will be required in the event 
of new statutory or regulatory requirements that are effective before 
the completion of construction or other circumstances beyond the 
control of the Transmission Provider that significantly affect the 
final cost of new facilities or upgrades to be charged to the 
Transmission Customer pursuant to the provisions of Part II of the 
Tariff.
19.6 Due Diligence in Completing New Facilities
    The Transmission Provider shall use due diligence to add necessary 
facilities or upgrade its Transmission System within a reasonable time. 
The Transmission Provider will not upgrade its existing or planned 
Transmission System in order to provide the requested Firm Point-To-
Point Transmission Service if doing so would impair system reliability 
or otherwise impair or degrade existing firm service.
19.7 Partial Interim Service
    If the Transmission Provider determines that it will not have 
adequate transfer capability to satisfy the full amount of a Completed 
Application for Firm Point-To-Point Transmission Service, the 
Transmission Provider nonetheless shall be obligated to offer and 
provide the portion of the requested Firm Point-To-Point Transmission 
Service that can be accommodated without addition of any facilities and 
through redispatch. However, the Transmission Provider shall not be 
obligated to provide the incremental amount of requested Firm Point-To-
Point Transmission Service that requires the addition of facilities or 
upgrades to the Transmission System until such facilities or upgrades 
have been placed in service.
19.8 Expedited Procedures for New Facilities
    In lieu of the procedures set forth above, the Eligible Customer 
shall have the option to expedite the process by requesting the 
Transmission Provider to tender at one time, together with the results 
of required studies, an ``Expedited Service Agreement'' pursuant to 
which the Eligible Customer would agree to compensate the Transmission 
Provider for all costs incurred pursuant to the terms of the Tariff. In 
order to exercise this option, the Eligible Customer shall request in 
writing an expedited Service Agreement covering all of the above-
specified items within thirty (30) days of receiving the results of the 
System Impact Study identifying needed facility additions or upgrades 
or costs incurred in providing the requested service. While the 
Transmission Provider agrees to provide the Eligible Customer with its 
best estimate of the new facility costs and other charges that may be 
incurred, such estimate shall not be binding and the Eligible Customer 
must agree in writing to compensate the Transmission Provider for all 
costs incurred pursuant to the provisions of the Tariff. The Eligible 
Customer shall execute and return such an Expedited Service Agreement 
within fifteen (15) days of its receipt or the Eligible Customer's 
request for service will cease to be a Completed Application and will 
be deemed terminated and withdrawn.
19.9 Penalties for Failure To Meet Study Deadlines
    Sections 19.3 and 19.4 require a Transmission Provider to use due 
diligence to meet 60-day study completion deadlines for System Impact 
Studies and Facilities Studies.
    (i) The Transmission Provider is required to file a notice with the 
Commission in the event that more than twenty (20) percent of non-
Affiliates' System Impact Studies and Facilities Studies completed by 
the Transmission Provider in any two consecutive calendar quarters are 
not completed within the 60-day study completion deadlines. Such notice 
must be filed within thirty (30) days of the end of the calendar 
quarter triggering the notice requirement.
    (ii) For the purposes of calculating the percent of non-Affiliates' 
System Impact Studies and Facilities Studies processed outside of the 
60-day study completion deadlines, the Transmission Provider shall 
consider all System Impact Studies and Facilities Studies that it 
completes for non-Affiliates during the calendar quarter. The 
percentage should be calculated by dividing the number of those studies 
which are completed on time by the total number of completed studies. 
The Transmission Provider may provide an explanation in its 
notification filing to the Commission if it believes there are 
extenuating circumstances that prevented it from meeting the 60-day 
study completion deadlines.
    (iii) The Transmission Provider is subject to an operational 
penalty if it completes ten (10) percent or more of non-Affiliates' 
System Impact Studies and Facilities Studies outside of the 60-day 
study completion deadlines for each of the two calendar quarters 
immediately following the quarter that triggered its notification 
filing to the Commission. The operational penalty will be assessed for 
each calendar quarter for which an operational penalty applies, 
starting with the calendar quarter immediately following the quarter 
that triggered the Transmission Provider's notification filing to the 
Commission. The operational penalty will continue to be assessed each 
quarter until the Transmission Provider completes at least ninety (90) 
percent of all non-Affiliates' System Impact Studies and Facilities 
Studies within the 60-day deadline.
    (iv) For penalties assessed in accordance with subsection (iii) 
above, the penalty amount for each System Impact Study or Facilities 
Study shall be equal to $500 for each day the Transmission Provider 
takes to complete that study beyond the 60-day deadline.

20 Procedures if the Transmission Provider Is Unable To Complete New 
Transmission Facilities for Firm Point-to-Point Transmission Service

20.1 Delays in Construction of New Facilities
    If any event occurs that will materially affect the time for 
completion of new facilities, or the ability to complete them, the 
Transmission Provider shall promptly notify the Transmission Customer. 
In such circumstances, the Transmission Provider shall within thirty 
(30) days of notifying the Transmission Customer of such delays, 
convene a technical meeting with the Transmission Customer to evaluate 
the alternatives available to the Transmission Customer. The 
Transmission Provider also shall make available to the Transmission

[[Page 12519]]

Customer studies and work papers related to the delay, including all 
information that is in the possession of the Transmission Provider that 
is reasonably needed by the Transmission Customer to evaluate any 
alternatives.
20.2 Alternatives to the Original Facility Additions
    When the review process of Section 20.1 determines that one or more 
alternatives exist to the originally planned construction project, the 
Transmission Provider shall present such alternatives for consideration 
by the Transmission Customer. If, upon review of any alternatives, the 
Transmission Customer desires to maintain its Completed Application 
subject to construction of the alternative facilities, it may request 
the Transmission Provider to submit a revised Service Agreement for 
Firm Point-To-Point Transmission Service. If the alternative approach 
solely involves Non-Firm Point-To-Point Transmission Service, the 
Transmission Provider shall promptly tender a Service Agreement for 
Non-Firm Point-To-Point Transmission Service providing for the service. 
In the event the Transmission Provider concludes that no reasonable 
alternative exists and the Transmission Customer disagrees, the 
Transmission Customer may seek relief under the dispute resolution 
procedures pursuant to Section 12 or it may refer the dispute to the 
Commission for resolution.
20.3 Refund Obligation for Unfinished Facility Additions
    If the Transmission Provider and the Transmission Customer mutually 
agree that no other reasonable alternatives exist and the requested 
service cannot be provided out of existing capability under the 
conditions of Part II of the Tariff, the obligation to provide the 
requested Firm Point-To-Point Transmission Service shall terminate and 
any deposit made by the Transmission Customer shall be returned with 
interest pursuant to Commission regulations 35.19a(a)(2)(iii). However, 
the Transmission Customer shall be responsible for all prudently 
incurred costs by the Transmission Provider through the time 
construction was suspended.

21 Provisions Relating to Transmission Construction and Services on the 
Systems of Other Utilities

21.1 Responsibility for Third-Party System Additions
    The Transmission Provider shall not be responsible for making 
arrangements for any necessary engineering, permitting, and 
construction of transmission or distribution facilities on the 
system(s) of any other entity or for obtaining any regulatory approval 
for such facilities. The Transmission Provider will undertake 
reasonable efforts to assist the Transmission Customer in obtaining 
such arrangements, including without limitation, providing any 
information or data required by such other electric system pursuant to 
Good Utility Practice.
21.2 Coordination of Third-Party System Additions
    In circumstances where the need for transmission facilities or 
upgrades is identified pursuant to the provisions of Part II of the 
Tariff, and if such upgrades further require the addition of 
transmission facilities on other systems, the Transmission Provider 
shall have the right to coordinate construction on its own system with 
the construction required by others. The Transmission Provider, after 
consultation with the Transmission Customer and representatives of such 
other systems, may defer construction of its new transmission 
facilities, if the new transmission facilities on another system cannot 
be completed in a timely manner. The Transmission Provider shall notify 
the Transmission Customer in writing of the basis for any decision to 
defer construction and the specific problems which must be resolved 
before it will initiate or resume construction of new facilities. 
Within sixty (60) days of receiving written notification by the 
Transmission Provider of its intent to defer construction pursuant to 
this section, the Transmission Customer may challenge the decision in 
accordance with the dispute resolution procedures pursuant to Section 
12 or it may refer the dispute to the Commission for resolution.

22 Changes in Service Specifications

22.1 Modifications On a Non-Firm Basis
    The Transmission Customer taking Firm Point-To-Point Transmission 
Service may request the Transmission Provider to provide transmission 
service on a non-firm basis over Receipt and Delivery Points other than 
those specified in the Service Agreement (``Secondary Receipt and 
Delivery Points''), in amounts not to exceed its firm capacity 
reservation, without incurring an additional Non-Firm Point-To-Point 
Transmission Service charge or executing a new Service Agreement, 
subject to the following conditions.
    (a) Service provided over Secondary Receipt and Delivery Points 
will be non-firm only, on an as-available basis and will not displace 
any firm or non-firm service reserved or scheduled by third-parties 
under the Tariff or by the Transmission Provider on behalf of its 
Native Load Customers.
    (b) The sum of all Firm and non-firm Point-To-Point Transmission 
Service provided to the Transmission Customer at any time pursuant to 
this section shall not exceed the Reserved Capacity in the relevant 
Service Agreement under which such services are provided.
    (c) The Transmission Customer shall retain its right to schedule 
Firm Point-To-Point Transmission Service at the Receipt and Delivery 
Points specified in the relevant Service Agreement in the amount of its 
original capacity reservation.
    (d) Service over Secondary Receipt and Delivery Points on a non-
firm basis shall not require the filing of an Application for Non-Firm 
Point-To-Point Transmission Service under the Tariff. However, all 
other requirements of Part II of the Tariff (except as to transmission 
rates) shall apply to transmission service on a non-firm basis over 
Secondary Receipt and Delivery Points.
22.2 Modification On a Firm Basis
    Any request by a Transmission Customer to modify Receipt and 
Delivery Points on a firm basis shall be treated as a new request for 
service in accordance with Section 17 hereof, except that such 
Transmission Customer shall not be obligated to pay any additional 
deposit if the capacity reservation does not exceed the amount reserved 
in the existing Service Agreement. While such new request is pending, 
the Transmission Customer shall retain its priority for service at the 
existing firm Receipt and Delivery Points specified in its Service 
Agreement.

23 Sale or Assignment of Transmission Service

23.1 Procedures for Assignment or Transfer of Service
    Subject to Commission approval of any necessary filings, a 
Transmission Customer may sell, assign, or transfer all or a portion of 
its rights under its Service Agreement, but only to another Eligible 
Customer (the Assignee). The Transmission Customer that sells, assigns 
or transfers its rights under its Service Agreement is hereafter 
referred to as the Reseller. Compensation to Resellers shall be at 
rates established by agreement with the Assignee. The

[[Page 12520]]

Assignee must execute a service agreement with the Transmission 
Provider prior to the date on which the reassigned service commences 
that will govern the provision of reassigned service. The Transmission 
Provider shall credit or charge the Reseller, as appropriate, for any 
differences between the price reflected in the Assignee's Service 
Agreement and the Reseller's Service Agreement with the Transmission 
Provider. If the Assignee does not request any change in the Point(s) 
of Receipt or the Point(s) of Delivery, or a change in any other term 
or condition set forth in the original Service Agreement, the Assignee 
will receive the same services as did the Reseller and the priority of 
service for the Assignee will be the same as that of the Reseller. The 
Assignee will be subject to all terms and conditions of this Tariff. If 
the Assignee requests a change in service, the reservation priority of 
service will be determined by the Transmission Provider pursuant to 
Section 13.2.
23.2 Limitations on Assignment or Transfer of Service
    If the Assignee requests a change in the Point(s) of Receipt or 
Point(s) of Delivery, or a change in any other specifications set forth 
in the original Service Agreement, the Transmission Provider will 
consent to such change subject to the provisions of the Tariff, 
provided that the change will not impair the operation and reliability 
of the Transmission Provider's generation, transmission, or 
distribution systems. The Assignee shall compensate the Transmission 
Provider for performing any System Impact Study needed to evaluate the 
capability of the Transmission System to accommodate the proposed 
change and any additional costs resulting from such change. The 
Reseller shall remain liable for the performance of all obligations 
under the Service Agreement, except as specifically agreed to by the 
Transmission Provider and the Reseller through an amendment to the 
Service Agreement.
23.3 Information on Assignment or Transfer of Service
    In accordance with Section 4, all sales or assignments of capacity 
must be conducted through or otherwise posted on the Transmission 
Provider's OASIS on or before the date the reassigned service commences 
and are subject to Section 23.1. Resellers may also use the 
Transmission Provider's OASIS to post transmission capacity available 
for resale.

24 Metering and Power Factor Correction at Receipt and Delivery 
Points(s)

24.1 Transmission Customer Obligations
    Unless otherwise agreed, the Transmission Customer shall be 
responsible for installing and maintaining compatible metering and 
communications equipment to accurately account for the capacity and 
energy being transmitted under Part II of the Tariff and to communicate 
the information to the Transmission Provider. Such equipment shall 
remain the property of the Transmission Customer.
24.2 Transmission Provider Access to Metering Data
    The Transmission Provider shall have access to metering data, which 
may reasonably be required to facilitate measurements and billing under 
the Service Agreement.
24.3 Power Factor
    Unless otherwise agreed, the Transmission Customer is required to 
maintain a power factor within the same range as the Transmission 
Provider pursuant to Good Utility Practices. The power factor 
requirements are specified in the Service Agreement where applicable.

25 Compensation for Transmission Service

    Rates for Firm and Non-Firm Point-To-Point Transmission Service are 
provided in the Schedules appended to the Tariff: Firm Point-To-Point 
Transmission Service (Schedule 7); and Non-Firm Point-To-Point 
Transmission Service (Schedule 8). The Transmission Provider shall use 
Part II of the Tariff to make its Third-Party Sales. The Transmission 
Provider shall account for such use at the applicable Tariff rates, 
pursuant to Section 8.

26 Stranded Cost Recovery

    The Transmission Provider may seek to recover stranded costs from 
the Transmission Customer pursuant to this Tariff in accordance with 
the terms, conditions and procedures set forth in FERC Order No. 888. 
However, the Transmission Provider must separately file any specific 
proposed stranded cost charge under Section 205 of the Federal Power 
Act.

27 Compensation for New Facilities and Redispatch Costs

    Whenever a System Impact Study performed by the Transmission 
Provider in connection with the provision of Firm Point-To-Point 
Transmission Service identifies the need for new facilities, the 
Transmission Customer shall be responsible for such costs to the extent 
consistent with Commission policy. Whenever a System Impact Study 
performed by the Transmission Provider identifies capacity constraints 
that may be relieved by redispatching the Transmission Provider's 
resources to eliminate such constraints, the Transmission Customer 
shall be responsible for the redispatch costs to the extent consistent 
with Commission policy.

III. Network Integration Transmission Service

Preamble

    The Transmission Provider will provide Network Integration 
Transmission Service pursuant to the applicable terms and conditions 
contained in the Tariff and Service Agreement. Network Integration 
Transmission Service allows the Network Customer to integrate, 
economically dispatch and regulate its current and planned Network 
Resources to serve its Network Load in a manner comparable to that in 
which the Transmission Provider utilizes its Transmission System to 
serve its Native Load Customers. Network Integration Transmission 
Service also may be used by the Network Customer to deliver economy 
energy purchases to its Network Load from non-designated resources on 
an as-available basis without additional charge. Transmission service 
for sales to non-designated loads will be provided pursuant to the 
applicable terms and conditions of Part II of the Tariff.

28 Nature of Network Integration Transmission Service

28.1 Scope of Service
    Network Integration Transmission Service is a transmission service 
that allows Network Customers to efficiently and economically utilize 
their Network Resources (as well as other non-designated generation 
resources) to serve their Network Load located in the Transmission 
Provider's Control Area and any additional load that may be designated 
pursuant to Section 31.3 of the Tariff. The Network Customer taking 
Network Integration Transmission Service must obtain or provide 
Ancillary Services pursuant to Section 3.
28.2 Transmission Provider Responsibilities
    The Transmission Provider will plan, construct, operate and 
maintain its

[[Page 12521]]

Transmission System in accordance with Good Utility Practice and its 
planning obligations in Attachment K in order to provide the Network 
Customer with Network Integration Transmission Service over the 
Transmission Provider's Transmission System. The Transmission Provider, 
on behalf of its Native Load Customers, shall be required to designate 
resources and loads in the same manner as any Network Customer under 
Part III of this Tariff. This information must be consistent with the 
information used by the Transmission Provider to calculate available 
transfer capability. The Transmission Provider shall include the 
Network Customer's Network Load in its Transmission System planning and 
shall, consistent with Good Utility Practice and Attachment K, endeavor 
to construct and place into service sufficient transfer capability to 
deliver the Network Customer's Network Resources to serve its Network 
Load on a basis comparable to the Transmission Provider's delivery of 
its own generating and purchased resources to its Native Load 
Customers.
28.3 Network Integration Transmission Service
    The Transmission Provider will provide firm transmission service 
over its Transmission System to the Network Customer for the delivery 
of capacity and energy from its designated Network Resources to service 
its Network Loads on a basis that is comparable to the Transmission 
Provider's use of the Transmission System to reliably serve its Native 
Load Customers.
28.4 Secondary Service
    The Network Customer may use the Transmission Provider's 
Transmission System to deliver energy to its Network Loads from 
resources that have not been designated as Network Resources. Such 
energy shall be transmitted, on an as-available basis, at no additional 
charge. Secondary service shall not require the filing of an 
Application for Network Integration Transmission Service under the 
Tariff. However, all other requirements of Part III of the Tariff 
(except for transmission rates) shall apply to secondary service. 
Deliveries from resources other than Network Resources will have a 
higher priority than any Non-Firm Point-To-Point Transmission Service 
under Part II of the Tariff.
28.5 Real Power Losses
    Real Power Losses are associated with all transmission service. The 
Transmission Provider is not obligated to provide Real Power Losses. 
The Network Customer is responsible for replacing losses associated 
with all transmission service as calculated by the Transmission 
Provider. The applicable Real Power Loss factors are as follows: [To be 
completed by the Transmission Provider].
28.6 Restrictions on Use of Service
    The Network Customer shall not use Network Integration Transmission 
Service for (i) sales of capacity and energy to non-designated loads, 
or (ii) direct or indirect provision of transmission service by the 
Network Customer to third parties. All Network Customers taking Network 
Integration Transmission Service shall use Point-To-Point Transmission 
Service under Part II of the Tariff for any Third-Party Sale which 
requires use of the Transmission Provider's Transmission System. The 
Transmission Provider shall specify any appropriate charges and 
penalties and all related terms and conditions applicable in the event 
that a Network Customer uses Network Integration Transmission Service 
or secondary service pursuant to Section 28.4 to facilitate a wholesale 
sale that does not serve a Network Load.

29 Initiating Service

29.1 Condition Precedent for Receiving Service
    Subject to the terms and conditions of Part III of the Tariff, the 
Transmission Provider will provide Network Integration Transmission 
Service to any Eligible Customer, provided that (i) the Eligible 
Customer completes an Application for service as provided under Part 
III of the Tariff, (ii) the Eligible Customer and the Transmission 
Provider complete the technical arrangements set forth in Sections 29.3 
and 29.4, (iii) the Eligible Customer executes a Service Agreement 
pursuant to Attachment F for service under Part III of the Tariff or 
requests in writing that the Transmission Provider file a proposed 
unexecuted Service Agreement with the Commission, and (iv) the Eligible 
Customer executes a Network Operating Agreement with the Transmission 
Provider pursuant to Attachment G, or requests in writing that the 
Transmission Provider file a proposed unexecuted Network Operating 
Agreement.
29.2 Application Procedures
    An Eligible Customer requesting service under Part III of the 
Tariff must submit an Application, with a deposit approximating the 
charge for one month of service, to the Transmission Provider as far as 
possible in advance of the month in which service is to commence. 
Unless subject to the procedures in Section 2, Completed Applications 
for Network Integration Transmission Service will be assigned a 
priority according to the date and time the Application is received, 
with the earliest Application receiving the highest priority. 
Applications should be submitted by entering the information listed 
below on the Transmission Provider's OASIS. Prior to implementation of 
the Transmission Provider's OASIS, a Completed Application may be 
submitted by (i) transmitting the required information to the 
Transmission Provider by telefax, or (ii) providing the information by 
telephone over the Transmission Provider's time recorded telephone 
line. Each of these methods will provide a time-stamped record for 
establishing the service priority of the Application. A Completed 
Application shall provide all of the information included in 18 CFR 
2.20 including but not limited to the following:
    (i) The identity, address, telephone number and facsimile number of 
the party requesting service;
    (ii) A statement that the party requesting service is, or will be 
upon commencement of service, an Eligible Customer under the Tariff;
    (iii) A description of the Network Load at each delivery point. 
This description should separately identify and provide the Eligible 
Customer's best estimate of the total loads to be served at each 
transmission voltage level, and the loads to be served from each 
Transmission Provider substation at the same transmission voltage 
level. The description should include a ten (10) year forecast of 
summer and winter load and resource requirements beginning with the 
first year after the service is scheduled to commence;
    (iv) The amount and location of any interruptible loads included in 
the Network Load. This shall include the summer and winter capacity 
requirements for each interruptible load (had such load not been 
interruptible), that portion of the load subject to interruption, the 
conditions under which an interruption can be implemented and any 
limitations on the amount and frequency of interruptions. An Eligible 
Customer should identify the amount of interruptible customer load (if 
any) included in the 10 year load forecast provided in response to 
(iii) above;
    (v) A description of Network Resources (current and 10-year 
projection). For each on-system Network Resource, such description 
shall include:

[[Page 12522]]

     Unit size and amount of capacity from that unit to be 
designated as Network Resource
     VAR capability (both leading and lagging) of all 
generators
     Operating restrictions

--Any periods of restricted operations throughout the year
--Maintenance schedules
--Minimum loading level of unit
--Normal operating level of unit
--Any must-run unit designations required for system reliability or 
contract reasons

     Approximate variable generating cost ($/MWH) for 
redispatch computations
     Arrangements governing sale and delivery of power to third 
parties from generating facilities located in the Transmission Provider 
Control Area, where only a portion of unit output is designated as a 
Network Resource;
    For each off-system Network Resource, such description shall 
include:
     Identification of the Network Resource as an off-system 
resource
     Amount of power to which the customer has rights
     Identification of the control area(s) from which the power 
will originate
     Delivery point(s) to the Transmission Provider's 
Transmission System
     Transmission arrangements on the external transmission 
system(s)
     Operating restrictions, if any

--Any periods of restricted operations throughout the year
--Maintenance schedules
--Minimum loading level of unit
--Normal operating level of unit
--Any must-run unit designations required for system reliability or 
contract reasons

     Approximate variable generating cost ($/MWH) for 
redispatch computations;
    (vi) Description of Eligible Customer's transmission system:
     Load flow and stability data, such as real and reactive 
parts of the load, lines, transformers, reactive devices and load type, 
including normal and emergency ratings of all transmission equipment in 
a load flow format compatible with that used by the Transmission 
Provider
     Operating restrictions needed for reliability
     Operating guides employed by system operators
     Contractual restrictions or committed uses of the Eligible 
Customer's transmission system, other than the Eligible Customer's 
Network Loads and Resources
     Location of Network Resources described in subsection (v) 
above
     10 year projection of system expansions or upgrades
     Transmission System maps that include any proposed 
expansions or upgrades
     Thermal ratings of Eligible Customer's Control Area ties 
with other Control Areas;
    (vii) Service Commencement Date and the term of the requested 
Network Integration Transmission Service. The minimum term for Network 
Integration Transmission Service is one year;
    (viii) A statement signed by an authorized officer from or agent of 
the Network Customer attesting that all of the network resources listed 
pursuant to Section 29.2(v) satisfy the following conditions:
    (1) The Network Customer owns the resource, has committed to 
purchase generation pursuant to an executed contract, or has committed 
to purchase generation where execution of a contract is contingent upon 
the availability of transmission service under Part III of the Tariff; 
and (2) the Network Resources do not include any resources, or any 
portion thereof, that are committed for sale to non-designated third 
party load or otherwise cannot be called upon to meet the Network 
Customer's Network Load on a non-interruptible basis; and
    (ix) Any additional information required of the Transmission 
Customer as specified in the Transmission Provider's planning process 
established in Attachment K.
    Unless the Parties agree to a different time frame, the 
Transmission Provider must acknowledge the request within ten (10) days 
of receipt. The acknowledgement must include a date by which a 
response, including a Service Agreement, will be sent to the Eligible 
Customer. If an Application fails to meet the requirements of this 
section, the Transmission Provider shall notify the Eligible Customer 
requesting service within fifteen (15) days of receipt and specify the 
reasons for such failure. Wherever possible, the Transmission Provider 
will attempt to remedy deficiencies in the Application through informal 
communications with the Eligible Customer. If such efforts are 
unsuccessful, the Transmission Provider shall return the Application 
without prejudice to the Eligible Customer filing a new or revised 
Application that fully complies with the requirements of this section. 
The Eligible Customer will be assigned a new priority consistent with 
the date of the new or revised Application. The Transmission Provider 
shall treat this information consistent with the standards of conduct 
contained in Part 37 of the Commission's regulations.
29.3 Technical Arrangements to be Completed Prior to Commencement of 
Service
    Network Integration Transmission Service shall not commence until 
the Transmission Provider and the Network Customer, or a third party, 
have completed installation of all equipment specified under the 
Network Operating Agreement consistent with Good Utility Practice and 
any additional requirements reasonably and consistently imposed to 
ensure the reliable operation of the Transmission System. The 
Transmission Provider shall exercise reasonable efforts, in 
coordination with the Network Customer, to complete such arrangements 
as soon as practicable taking into consideration the Service 
Commencement Date.
29.4 Network Customer Facilities
    The provision of Network Integration Transmission Service shall be 
conditioned upon the Network Customer's constructing, maintaining and 
operating the facilities on its side of each delivery point or 
interconnection necessary to reliably deliver capacity and energy from 
the Transmission Provider's Transmission System to the Network 
Customer. The Network Customer shall be solely responsible for 
constructing or installing all facilities on the Network Customer's 
side of each such delivery point or interconnection.
29.5 Filing of Service Agreement
    The Transmission Provider will file Service Agreements with the 
Commission in compliance with applicable Commission regulations.

30 Network Resources

30.1 Designation of Network Resources
    Network Resources shall include all generation owned, purchased or 
leased by the Network Customer designated to serve Network Load under 
the Tariff. Network Resources may not include resources, or any portion 
thereof, that are committed for sale to non-designated third party load 
or otherwise cannot be called upon to meet the Network Customer's 
Network Load on a non-interruptible basis. Any owned or purchased 
resources that were serving the Network Customer's loads under firm 
agreements entered into on or before the Service Commencement Date 
shall initially be designated as Network Resources until the Network 
Customer terminates the designation of such resources.

[[Page 12523]]

30.2 Designation of New Network Resources
    The Network Customer may designate a new Network Resource by 
providing the Transmission Provider with as much advance notice as 
practicable. A designation of a new Network Resource must be made 
through the Transmission Provider's OASIS by a request for modification 
of service pursuant to an Application under Section 29. This request 
must include a statement that the new network resource satisfies the 
following conditions: (1) the Network Customer owns the resource, has 
committed to purchase generation pursuant to an executed contract, or 
has committed to purchase generation where execution of a contract is 
contingent upon the availability of transmission service under Part III 
of the Tariff; and (2) The Network Resources do not include any 
resources, or any portion thereof, that are committed for sale to non-
designated third party load or otherwise cannot be called upon to meet 
the Network Customer's Network Load on a non-interruptible basis. The 
Network Customer's request will be deemed deficient if it does not 
include this statement and the Transmission Provider will follow the 
procedures for a deficient application as described in Section 29.2 of 
the Tariff.
30.3 Termination of Network Resources
    The Network Customer may terminate the designation of all or part 
of a generating resource as a Network Resource by providing 
notification to the Transmission Provider through OASIS as soon as 
reasonably practicable, but not later than the firm scheduling deadline 
for the period of termination. Any request for termination of Network 
Resource status must be submitted on OASIS, and should indicate whether 
the request is for indefinite or temporary termination. A request for 
indefinite termination of Network Resource status must indicate the 
date and time that the termination is to be effective, and the 
identification and capacity of the resource(s) or portions thereof to 
be indefinitely terminated. A request for temporary termination of 
Network Resource status must include the following:
    (i) Effective date and time of temporary termination;
    (ii) Effective date and time of redesignation, following period of 
temporary termination;
    (iii) Identification and capacity of resource(s) or portions 
thereof to be temporarily terminated;
    (iv) Resource description and attestation for redesignating the 
network resource following the temporary termination, in accordance 
with Section 30.2; and
    (v) Identification of any related transmission service requests to 
be evaluated concomitantly with the request for temporary termination, 
such that the requests for undesignation and the request for these 
related transmission service requests must be approved or denied as a 
single request. The evaluation of these related transmission service 
requests must take into account the termination of the network 
resources identified in (iii) above, as well as all competing 
transmission service requests of higher priority.
    As part of a temporary termination, a Network Customer may only 
redesignate the same resource that was originally designated, or a 
portion thereof. Requests to redesignate a different resource and/or a 
resource with increased capacity will be deemed deficient and the 
Transmission Provider will follow the procedures for a deficient 
application as described in Section 29.2 of the Tariff.
30.4 Operation of Network Resources
    The Network Customer shall not operate its designated Network 
Resources located in the Network Customer's or Transmission Provider's 
Control Area such that the output of those facilities exceeds its 
designated Network Load, plus Non-Firm Sales delivered pursuant to Part 
II of the Tariff, plus losses. This limitation shall not apply to 
changes in the operation of a Transmission Customer's Network Resources 
at the request of the Transmission Provider to respond to an emergency 
or other unforeseen condition which may impair or degrade the 
reliability of the Transmission System. For all Network Resources not 
physically connected with the Transmission Provider's Transmission 
System, the Network Customer may not schedule delivery of energy in 
excess of the Network Resource's capacity, as specified in the Network 
Customer's Application pursuant to Section 29, unless the Network 
Customer supports such delivery within the Transmission Provider's 
Transmission System by either obtaining Point-to-Point Transmission 
Service or utilizing secondary service pursuant to Section 28.4. The 
Transmission Provider shall specify the rate treatment and all related 
terms and conditions applicable in the event that a Network Customer's 
schedule at the delivery point for a Network Resource not physically 
interconnected with the Transmission Provider's Transmission System 
exceeds the Network Resource's designated capacity, excluding energy 
delivered using secondary service or Point-to-Point Transmission 
Service.
30.5 Network Customer Redispatch Obligation
    As a condition to receiving Network Integration Transmission 
Service, the Network Customer agrees to redispatch its Network 
Resources as requested by the Transmission Provider pursuant to Section 
33.2. To the extent practical, the redispatch of resources pursuant to 
this section shall be on a least cost, non-discriminatory basis between 
all Network Customers, and the Transmission Provider.
30.6 Transmission Arrangements for Network Resources Not Physically 
Interconnected With The Transmission Provider
    The Network Customer shall be responsible for any arrangements 
necessary to deliver capacity and energy from a Network Resource not 
physically interconnected with the Transmission Provider's Transmission 
System. The Transmission Provider will undertake reasonable efforts to 
assist the Network Customer in obtaining such arrangements, including 
without limitation, providing any information or data required by such 
other entity pursuant to Good Utility Practice.
30.7 Limitation on Designation of Network Resources
    The Network Customer must demonstrate that it owns or has committed 
to purchase generation pursuant to an executed contract in order to 
designate a generating resource as a Network Resource. Alternatively, 
the Network Customer may establish that execution of a contract is 
contingent upon the availability of transmission service under Part III 
of the Tariff.
30.8 Use of Interface Capacity by the Network Customer
    There is no limitation upon a Network Customer's use of the 
Transmission Provider's Transmission System at any particular interface 
to integrate the Network Customer's Network Resources (or substitute 
economy purchases) with its Network Loads. However, a Network 
Customer's use of the Transmission Provider's total interface capacity 
with other transmission systems may not exceed the Network Customer's 
Load.
30.9 Network Customer Owned Transmission Facilities
    The Network Customer that owns existing transmission facilities 
that are

[[Page 12524]]

integrated with the Transmission Provider's Transmission System may be 
eligible to receive consideration either through a billing credit or 
some other mechanism. In order to receive such consideration the 
Network Customer must demonstrate that its transmission facilities are 
integrated into the plans or operations of the Transmission Provider, 
to serve its power and transmission customers. For facilities added by 
the Network Customer subsequent to the [the effective date of a Final 
Rule in RM05-25-000], the Network Customer shall receive credit for 
such transmission facilities added if such facilities are integrated 
into the operations of the Transmission Provider's facilities; provided 
however, the Network Customer's transmission facilities shall be 
presumed to be integrated if such transmission facilities, if owned by 
the Transmission Provider, would be eligible for inclusion in the 
Transmission Provider's annual transmission revenue requirement as 
specified in Attachment H. Calculation of any credit under this 
subsection shall be addressed in either the Network Customer's Service 
Agreement or any other agreement between the Parties.

31 Designation of Network Load

31.1 Network Load
    The Network Customer must designate the individual Network Loads on 
whose behalf the Transmission Provider will provide Network Integration 
Transmission Service. The Network Loads shall be specified in the 
Service Agreement.
31.2 New Network Loads Connected With the Transmission Provider
    The Network Customer shall provide the Transmission Provider with 
as much advance notice as reasonably practicable of the designation of 
new Network Load that will be added to its Transmission System. A 
designation of new Network Load must be made through a modification of 
service pursuant to a new Application. The Transmission Provider will 
use due diligence to install any transmission facilities required to 
interconnect a new Network Load designated by the Network Customer. The 
costs of new facilities required to interconnect a new Network Load 
shall be determined in accordance with the procedures provided in 
Section 32.4 and shall be charged to the Network Customer in accordance 
with Commission policies.
31.3 Network Load Not Physically Interconnected With the Transmission 
Provider
    This section applies to both initial designation pursuant to 
Section 31.1 and the subsequent addition of new Network Load not 
physically interconnected with the Transmission Provider. To the extent 
that the Network Customer desires to obtain transmission service for a 
load outside the Transmission Provider's Transmission System, the 
Network Customer shall have the option of (1) electing to include the 
entire load as Network Load for all purposes under Part III of the 
Tariff and designating Network Resources in connection with such 
additional Network Load, or (2) excluding that entire load from its 
Network Load and purchasing Point-To-Point Transmission Service under 
Part II of the Tariff. To the extent that the Network Customer gives 
notice of its intent to add a new Network Load as part of its Network 
Load pursuant to this section the request must be made through a 
modification of service pursuant to a new Application.
31.4 New Interconnection Points
    To the extent the Network Customer desires to add a new Delivery 
Point or interconnection point between the Transmission Provider's 
Transmission System and a Network Load, the Network Customer shall 
provide the Transmission Provider with as much advance notice as 
reasonably practicable.
31.5 Changes in Service Requests
    Under no circumstances shall the Network Customer's decision to 
cancel or delay a requested change in Network Integration Transmission 
Service (e.g. the addition of a new Network Resource or designation of 
a new Network Load) in any way relieve the Network Customer of its 
obligation to pay the costs of transmission facilities constructed by 
the Transmission Provider and charged to the Network Customer as 
reflected in the Service Agreement. However, the Transmission Provider 
must treat any requested change in Network Integration Transmission 
Service in a non-discriminatory manner.
31.6 Annual Load and Resource Information Updates
    The Network Customer shall provide the Transmission Provider with 
annual updates of Network Load and Network Resource forecasts 
consistent with those included in its Application for Network 
Integration Transmission Service under Part III of the Tariff 
including, but not limited to, any information provided under section 
29.2(ix) pursuant to the Transmission Provider's planning process in 
Attachment K. The Network Customer also shall provide the Transmission 
Provider with timely written notice of material changes in any other 
information provided in its Application relating to the Network 
Customer's Network Load, Network Resources, its transmission system or 
other aspects of its facilities or operations affecting the 
Transmission Provider's ability to provide reliable service.

32 Additional Study Procedures for Network Integration Transmission 
Service Requests

32.1 Notice of Need for System Impact Study
    After receiving a request for service, the Transmission Provider 
shall determine on a non-discriminatory basis whether a System Impact 
Study is needed. A description of the Transmission Provider's 
methodology for completing a System Impact Study is provided in 
Attachment D. If the Transmission Provider determines that a System 
Impact Study is necessary to accommodate the requested service, it 
shall so inform the Eligible Customer, as soon as practicable. In such 
cases, the Transmission Provider shall within thirty (30) days of 
receipt of a Completed Application, tender a System Impact Study 
Agreement pursuant to which the Eligible Customer shall agree to 
reimburse the Transmission Provider for performing the required System 
Impact Study. For a service request to remain a Completed Application, 
the Eligible Customer shall execute the System Impact Study Agreement 
and return it to the Transmission Provider within fifteen (15) days. If 
the Eligible Customer elects not to execute the System Impact Study 
Agreement, its Application shall be deemed withdrawn and its deposit 
shall be returned with interest.
32.2 System Impact Study Agreement and Cost Reimbursement
    (i) The System Impact Study Agreement will clearly specify the 
Transmission Provider's estimate of the actual cost, and time for 
completion of the System Impact Study. The charge shall not exceed the 
actual cost of the study. In performing the System Impact Study, the 
Transmission Provider shall rely, to the extent reasonably practicable, 
on existing transmission planning studies. The Eligible Customer will 
not be assessed a charge for such existing studies; however, the 
Eligible

[[Page 12525]]

Customer will be responsible for charges associated with any 
modifications to existing planning studies that are reasonably 
necessary to evaluate the impact of the Eligible Customer's request for 
service on the Transmission System.
    (ii) If in response to multiple Eligible Customers requesting 
service in relation to the same competitive solicitation, a single 
System Impact Study is sufficient for the Transmission Provider to 
accommodate the service requests, the costs of that study shall be pro-
rated among the Eligible Customers.
    (iii) For System Impact Studies that the Transmission Provider 
conducts on its own behalf, the Transmission Provider shall record the 
cost of the System Impact Studies pursuant to Section 8.
32.3 System Impact Study Procedures
    Upon receipt of an executed System Impact Study Agreement, the 
Transmission Provider will use due diligence to complete the required 
System Impact Study within a sixty (60) day period. The System Impact 
Study shall identify any system constraints and redispatch options, 
additional Direct Assignment Facilities or Network Upgrades required to 
provide the requested service. In the event that the Transmission 
Provider is unable to complete the required System Impact Study within 
such time period, it shall so notify the Eligible Customer and provide 
an estimated completion date along with an explanation of the reasons 
why additional time is required to complete the required studies. A 
copy of the completed System Impact Study and related work papers shall 
be made available to the Eligible Customer as soon as the System Impact 
Study is complete. The Transmission Provider will use the same due 
diligence in completing the System Impact Study for an Eligible 
Customer as it uses when completing studies for itself. The 
Transmission Provider shall notify the Eligible Customer immediately 
upon completion of the System Impact Study if the Transmission System 
will be adequate to accommodate all or part of a request for service or 
that no costs are likely to be incurred for new transmission facilities 
or upgrades. In order for a request to remain a Completed Application, 
within fifteen (15) days of completion of the System Impact Study the 
Eligible Customer must execute a Service Agreement or request the 
filing of an unexecuted Service Agreement, or the Application shall be 
deemed terminated and withdrawn.
32.4 Facilities Study Procedures
    If a System Impact Study indicates that additions or upgrades to 
the Transmission System are needed to supply the Eligible Customer's 
service request, the Transmission Provider, within thirty (30) days of 
the completion of the System Impact Study, shall tender to the Eligible 
Customer a Facilities Study Agreement pursuant to which the Eligible 
Customer shall agree to reimburse the Transmission Provider for 
performing the required Facilities Study. For a service request to 
remain a Completed Application, the Eligible Customer shall execute the 
Facilities Study Agreement and return it to the Transmission Provider 
within fifteen (15) days. If the Eligible Customer elects not to 
execute the Facilities Study Agreement, its Application shall be deemed 
withdrawn and its deposit shall be returned with interest. Upon receipt 
of an executed Facilities Study Agreement, the Transmission Provider 
will use due diligence to complete the required Facilities Study within 
a sixty (60) day period. If the Transmission Provider is unable to 
complete the Facilities Study in the allotted time period, the 
Transmission Provider shall notify the Eligible Customer and provide an 
estimate of the time needed to reach a final determination along with 
an explanation of the reasons that additional time is required to 
complete the study. When completed, the Facilities Study will include a 
good faith estimate of (i) the cost of Direct Assignment Facilities to 
be charged to the Eligible Customer, (ii) the Eligible Customer's 
appropriate share of the cost of any required Network Upgrades, and 
(iii) the time required to complete such construction and initiate the 
requested service. The Eligible Customer shall provide the Transmission 
Provider with a letter of credit or other reasonable form of security 
acceptable to the Transmission Provider equivalent to the costs of new 
facilities or upgrades consistent with commercial practices as 
established by the Uniform Commercial Code. The Eligible Customer shall 
have thirty (30) days to execute a Service Agreement or request the 
filing of an unexecuted Service Agreement and provide the required 
letter of credit or other form of security or the request no longer 
will be a Completed Application and shall be deemed terminated and 
withdrawn.
32.5 Penalties for Failure To Meet Study Deadlines
    Section 19.9 defines penalties that apply for failure to meet the 
60-day study completion due diligence deadlines for System Impact 
Studies and Facilities Studies under Part II of the Tariff. These same 
requirements and penalties apply to service under Part III of the 
Tariff.

33 Load Shedding and Curtailments

33.1 Procedures
    Prior to the Service Commencement Date, the Transmission Provider 
and the Network Customer shall establish Load Shedding and Curtailment 
procedures pursuant to the Network Operating Agreement with the 
objective of responding to contingencies on the Transmission System and 
on systems directly and indirectly interconnected with Transmission 
Provider's Transmission System. The Parties will implement such 
programs during any period when the Transmission Provider determines 
that a system contingency exists and such procedures are necessary to 
alleviate such contingency. The Transmission Provider will notify all 
affected Network Customers in a timely manner of any scheduled 
Curtailment.
33.2 Transmission Constraints
    During any period when the Transmission Provider determines that a 
transmission constraint exists on the Transmission System, and such 
constraint may impair the reliability of the Transmission Provider's 
system, the Transmission Provider will take whatever actions, 
consistent with Good Utility Practice, that are reasonably necessary to 
maintain the reliability of the Transmission Provider's system. To the 
extent the Transmission Provider determines that the reliability of the 
Transmission System can be maintained by redispatching resources, the 
Transmission Provider will initiate procedures pursuant to the Network 
Operating Agreement to redispatch all Network Resources and the 
Transmission Provider's own resources on a least-cost basis without 
regard to the ownership of such resources. Any redispatch under this 
section may not unduly discriminate between the Transmission Provider's 
use of the Transmission System on behalf of its Native Load Customers 
and any Network Customer's use of the Transmission System to serve its 
designated Network Load.
33.3 Cost Responsibility for Relieving Transmission Constraints
    Whenever the Transmission Provider implements least-cost redispatch 
procedures in response to a transmission constraint, the Transmission 
Provider and Network

[[Page 12526]]

Customers will each bear a proportionate share of the total redispatch 
cost based on their respective Load Ratio Shares.
33.4 Curtailments of Scheduled Deliveries
    If a transmission constraint on the Transmission Provider's 
Transmission System cannot be relieved through the implementation of 
least-cost redispatch procedures and the Transmission Provider 
determines that it is necessary to Curtail scheduled deliveries, the 
Parties shall Curtail such schedules in accordance with the Network 
Operating Agreement or pursuant to the Transmission Loading Relief 
procedures specified in Attachment J.
33.5 Allocation of Curtailments
    The Transmission Provider shall, on a non-discriminatory basis, 
Curtail the transaction(s) that effectively relieve the constraint. 
However, to the extent practicable and consistent with Good Utility 
Practice, any Curtailment will be shared by the Transmission Provider 
and Network Customer in proportion to their respective Load Ratio 
Shares. The Transmission Provider shall not direct the Network Customer 
to Curtail schedules to an extent greater than the Transmission 
Provider would Curtail the Transmission Provider's schedules under 
similar circumstances.
33.6 Load Shedding
    To the extent that a system contingency exists on the Transmission 
Provider's Transmission System and the Transmission Provider determines 
that it is necessary for the Transmission Provider and the Network 
Customer to shed load, the Parties shall shed load in accordance with 
previously established procedures under the Network Operating 
Agreement.
33.7 System Reliability
    Notwithstanding any other provisions of this Tariff, the 
Transmission Provider reserves the right, consistent with Good Utility 
Practice and on a not unduly discriminatory basis, to Curtail Network 
Integration Transmission Service without liability on the Transmission 
Provider's part for the purpose of making necessary adjustments to, 
changes in, or repairs on its lines, substations and facilities, and in 
cases where the continuance of Network Integration Transmission Service 
would endanger persons or property. In the event of any adverse 
condition(s) or disturbance(s) on the Transmission Provider's 
Transmission System or on any other system(s) directly or indirectly 
interconnected with the Transmission Provider's Transmission System, 
the Transmission Provider, consistent with Good Utility Practice, also 
may Curtail Network Integration Transmission Service in order to (i) 
limit the extent or damage of the adverse condition(s) or 
disturbance(s), (ii) prevent damage to generating or transmission 
facilities, or (iii) expedite restoration of service. The Transmission 
Provider will give the Network Customer as much advance notice as is 
practicable in the event of such Curtailment. Any Curtailment of 
Network Integration Transmission Service will be not unduly 
discriminatory relative to the Transmission Provider's use of the 
Transmission System on behalf of its Native Load Customers. The 
Transmission Provider shall specify the rate treatment and all related 
terms and conditions applicable in the event that the Network Customer 
fails to respond to established Load Shedding and Curtailment 
procedures.

34 Rates and Charges

    The Network Customer shall pay the Transmission Provider for any 
Direct Assignment Facilities, Ancillary Services, and applicable study 
costs, consistent with Commission policy, along with the following:
34.1 Monthly Demand Charge
    The Network Customer shall pay a monthly Demand Charge, which shall 
be determined by multiplying its Load Ratio Share times one twelfth 
(\1/12\) of the Transmission Provider's Annual Transmission Revenue 
Requirement specified in Schedule H.
34.2 Determination of Network Customer's Monthly Network Load
    The Network Customer's monthly Network Load is its hourly load 
(including its designated Network Load not physically interconnected 
with the Transmission Provider under Section 31.3) coincident with the 
Transmission Provider's Monthly Transmission System Peak.
34.3 Determination of Transmission Provider's Monthly Transmission 
System Load
    The Transmission Provider's monthly Transmission System load is the 
Transmission Provider's Monthly Transmission System Peak minus the 
coincident peak usage of all Firm Point-To-Point Transmission Service 
customers pursuant to Part II of this Tariff plus the Reserved Capacity 
of all Firm Point-To-Point Transmission Service customers.
34.4 Redispatch Charge
    The Network Customer shall pay a Load Ratio Share of any redispatch 
costs allocated between the Network Customer and the Transmission 
Provider pursuant to Section 33. To the extent that the Transmission 
Provider incurs an obligation to the Network Customer for redispatch 
costs in accordance with Section 33, such amounts shall be credited 
against the Network Customer's bill for the applicable month.
34.5 Stranded Cost Recovery
    The Transmission Provider may seek to recover stranded costs from 
the Network Customer pursuant to this Tariff in accordance with the 
terms, conditions and procedures set forth in FERC Order No. 888. 
However, the Transmission Provider must separately file any proposal to 
recover stranded costs under Section 205 of the Federal Power Act.

35 Operating Arrangements

35.1 Operation Under the Network Operating Agreement
    The Network Customer shall plan, construct, operate and maintain 
its facilities in accordance with Good Utility Practice and in 
conformance with the Network Operating Agreement.
35.2 Network Operating Agreement
    The terms and conditions under which the Network Customer shall 
operate its facilities and the technical and operational matters 
associated with the implementation of Part III of the Tariff shall be 
specified in the Network Operating Agreement. The Network Operating 
Agreement shall provide for the Parties to (i) operate and maintain 
equipment necessary for integrating the Network Customer within the 
Transmission Provider's Transmission System (including, but not limited 
to, remote terminal units, metering, communications equipment and 
relaying equipment), (ii) transfer data between the Transmission 
Provider and the Network Customer (including, but not limited to, heat 
rates and operational characteristics of Network Resources, generation 
schedules for units outside the Transmission Provider's Transmission 
System, interchange schedules, unit outputs for redispatch required 
under Section 33, voltage schedules, loss factors and other real time 
data), (iii) use software programs required for data links and 
constraint dispatching, (iv) exchange data on forecasted loads and 
resources necessary for long-term planning, and (v) address any other 
technical and

[[Page 12527]]

operational considerations required for implementation of Part III of 
the Tariff, including scheduling protocols. The Network Operating 
Agreement will recognize that the Network Customer shall either (i) 
operate as a Control Area under applicable guidelines of the Electric 
Reliability Organization (ERO) as defined in 18 CFR 39.1, (ii) satisfy 
its Control Area requirements, including all necessary Ancillary 
Services, by contracting with the Transmission Provider, or (iii) 
satisfy its Control Area requirements, including all necessary 
Ancillary Services, by contracting with another entity, consistent with 
Good Utility Practice, which satisfies the applicable reliability 
guidelines of the ERO. The Transmission Provider shall not unreasonably 
refuse to accept contractual arrangements with another entity for 
Ancillary Services. The Network Operating Agreement is included in 
Attachment G.
35.3 Network Operating Committee
    A Network Operating Committee (Committee) shall be established to 
coordinate operating criteria for the Parties' respective 
responsibilities under the Network Operating Agreement. Each Network 
Customer shall be entitled to have at least one representative on the 
Committee. The Committee shall meet from time to time as need requires, 
but no less than once each calendar year.

Schedule 1--Scheduling, System Control and Dispatch Service

    This service is required to schedule the movement of power through, 
out of, within, or into a Control Area. This service can be provided 
only by the operator of the Control Area in which the transmission 
facilities used for transmission service are located. Scheduling, 
System Control and Dispatch Service is to be provided directly by the 
Transmission Provider (if the Transmission Provider is the Control Area 
operator) or indirectly by the Transmission Provider making 
arrangements with the Control Area operator that performs this service 
for the Transmission Provider's Transmission System. The Transmission 
Customer must purchase this service from the Transmission Provider or 
the Control Area operator. The charges for Scheduling, System Control 
and Dispatch Service are to be based on the rates set forth below. To 
the extent the Control Area operator performs this service for the 
Transmission Provider, charges to the Transmission Customer are to 
reflect only a pass-through of the costs charged to the Transmission 
Provider by that Control Area operator.

Schedule 2--Reactive Supply and Voltage Control From Generation or 
Other Sources Service

    In order to maintain transmission voltages on the Transmission 
Provider's transmission facilities within acceptable limits, generation 
facilities and non-generation resources capable of providing this 
service that are under the control of the control area operator are 
operated to produce (or absorb) reactive power. Thus, Reactive Supply 
and Voltage Control from Generation or Other Sources Service must be 
provided for each transaction on the Transmission Provider's 
transmission facilities. The amount of Reactive Supply and Voltage 
Control from Generation or Other Sources Service that must be supplied 
with respect to the Transmission Customer's transaction will be 
determined based on the reactive power support necessary to maintain 
transmission voltages within limits that are generally accepted in the 
region and consistently adhered to by the Transmission Provider.
    Reactive Supply and Voltage Control from Generation or Other 
Sources Service is to be provided directly by the Transmission Provider 
(if the Transmission Provider is the Control Area operator) or 
indirectly by the Transmission Provider making arrangements with the 
Control Area operator that performs this service for the Transmission 
Provider's Transmission System. The Transmission Customer must purchase 
this service from the Transmission Provider or the Control Area 
operator. The charges for such service will be based on the rates set 
forth below. To the extent the Control Area operator performs this 
service for the Transmission Provider, charges to the Transmission 
Customer are to reflect only a pass-through of the costs charged to the 
Transmission Provider by the Control Area operator.

Schedule 3--Regulation and Frequency Response Service

    Regulation and Frequency Response Service is necessary to provide 
for the continuous balancing of resources (generation and interchange) 
with load and for maintaining scheduled Interconnection frequency at 
sixty cycles per second (60 Hz). Regulation and Frequency Response 
Service is accomplished by committing on-line generation whose output 
is raised or lowered (predominantly through the use of automatic 
generating control equipment) and by other non-generation resources 
capable of providing this service as necessary to follow the moment-by-
moment changes in load. The obligation to maintain this balance between 
resources and load lies with the Transmission Provider (or the Control 
Area operator that performs this function for the Transmission 
Provider). The Transmission Provider must offer this service when the 
transmission service is used to serve load within its Control Area. The 
Transmission Customer must either purchase this service from the 
Transmission Provider or make alternative comparable arrangements to 
satisfy its Regulation and Frequency Response Service obligation. The 
amount of and charges for Regulation and Frequency Response Service are 
set forth below. To the extent the Control Area operator performs this 
service for the Transmission Provider, charges to the Transmission 
Customer are to reflect only a pass-through of the costs charged to the 
Transmission Provider by that Control Area operator.

Schedule 4--Energy Imbalance Service

    Energy Imbalance Service is provided when a difference occurs 
between the scheduled and the actual delivery of energy to a load 
located within a Control Area over a single hour. The Transmission 
Provider must offer this service when the transmission service is used 
to serve load within its Control Area. The Transmission Customer must 
either purchase this service from the Transmission Provider or make 
alternative comparable arrangements, which may include use of non-
generation resources capable of providing this service, to satisfy its 
Energy Imbalance Service obligation. To the extent the Control Area 
operator performs this service for the Transmission Provider, charges 
to the Transmission Customer are to reflect only a pass-through of the 
costs charged to the Transmission Provider by that Control Area 
operator. The Transmission Provider may charge a Transmission Customer 
a penalty for either hourly generator imbalances under Schedule 9 or 
hourly energy imbalances under this Schedule for the same imbalance, 
but not both.
    The Transmission Provider shall establish charges for energy 
imbalance based on the deviation bands as follows: (i) Deviations 
within +/-1.5 percent (with a minimum of 2 MW) of the scheduled 
transaction to be applied hourly to any energy imbalance that occurs as 
a result of the Transmission Customer's scheduled transaction(s) will 
be netted on a monthly basis and settled financially, at the end of the 
month, at 100 percent of incremental or decremental cost; (ii) 
deviations greater than +/-1.5 percent up to 7.5 percent

[[Page 12528]]

(or greater than 2 MW up to 10 MW) of the scheduled transaction to be 
applied hourly to any energy imbalance that occurs as a result of the 
Transmission Customer's scheduled transaction(s) will be settled 
financially, at the end of each month, at 110 percent of incremental 
cost or 90 percent of decremental cost, and (iii) deviations greater 
than +/-7.5 percent (or 10 MW) of the scheduled transaction to be 
applied hourly to any energy imbalance that occurs as a result of the 
Transmission Customer's scheduled transaction(s) will be settled 
financially, at the end of each month, at 125 percent of incremental 
cost or 75 percent of decremental cost.

    For purposes of this Schedule, incremental cost and decremental 
cost represent the Transmission Provider's actual average hourly 
cost of the last 10 MW dispatched to supply the Transmission 
Provider's Native Load Customers, based on the replacement cost of 
fuel, unit heat rates, start-up costs (including any commitment and 
redispatch costs), incremental operation and maintenance costs, and 
purchased and interchange power costs and taxes, as applicable.

Schedule 5--Operating Reserve--Spinning Reserve Service

    Spinning Reserve Service is needed to serve load immediately in the 
event of a system contingency. Spinning Reserve Service may be provided 
by generating units that are on-line and loaded at less than maximum 
output and by non-generation resources capable of providing this 
service. The Transmission Provider must offer this service when the 
transmission service is used to serve load within its Control Area. The 
Transmission Customer must either purchase this service from the 
Transmission Provider or make alternative comparable arrangements to 
satisfy its Spinning Reserve Service obligation. The amount of and 
charges for Spinning Reserve Service are set forth below. To the extent 
the Control Area operator performs this service for the Transmission 
Provider, charges to the Transmission Customer are to reflect only a 
pass-through of the costs charged to the Transmission Provider by that 
Control Area operator.

Schedule 6--Operating Reserve--Supplemental Reserve Service

    Supplemental Reserve Service is needed to serve load in the event 
of a system contingency; however, it is not available immediately to 
serve load but rather within a short period of time. Supplemental 
Reserve Service may be provided by generating units that are on-line 
but unloaded, by quick-start generation or by interruptible load or 
other non-generation resources capable of providing this service. The 
Transmission Provider must offer this service when the transmission 
service is used to serve load within its Control Area. The Transmission 
Customer must either purchase this service from the Transmission 
Provider or make alternative comparable arrangements to satisfy its 
Supplemental Reserve Service obligation. The amount of and charges for 
Supplemental Reserve Service are set forth below. To the extent the 
Control Area operator performs this service for the Transmission 
Provider, charges to the Transmission Customer are to reflect only a 
pass-through of the costs charged to the Transmission Provider by that 
Control Area operator.

Schedule 7--Long-Term Firm and Short-Term Firm Point-To-Point 
Transmission Service

    The Transmission Customer shall compensate the Transmission 
Provider each month for Reserved Capacity at the sum of the applicable 
charges set forth below:
    (1) Yearly delivery: one-twelfth of the demand charge of $----/KW 
of Reserved Capacity per year.
    (2) Monthly delivery: $----/KW of Reserved Capacity per month.
    (3) Weekly delivery: $----/KW of Reserved Capacity per week.
    (4) Daily delivery: $----/KW of Reserved Capacity per day.
    The total demand charge in any week, pursuant to a reservation for 
Daily delivery, shall not exceed the rate specified in section (3) 
above times the highest amount in kilowatts of Reserved Capacity in any 
day during such week.
    (5) Discounts: Three principal requirements apply to discounts for 
transmission service as follows (1) any offer of a discount made by the 
Transmission Provider must be announced to all Eligible Customers 
solely by posting on the OASIS, (2) any customer-initiated requests for 
discounts (including requests for use by one's wholesale merchant or an 
affiliate's use) must occur solely by posting on the OASIS, and (3) 
once a discount is negotiated, details must be immediately posted on 
the OASIS. For any discount agreed upon for service on a path, from 
point(s) of receipt to point(s) of delivery, the Transmission Provider 
must offer the same discounted transmission service rate for the same 
time period to all Eligible Customers on all unconstrained transmission 
paths that go to the same point(s) of delivery on the Transmission 
System.

Schedule 8--Non-Firm Point-To-Point Transmission Service

    The Transmission Customer shall compensate the Transmission 
Provider for Non-Firm Point-To-Point Transmission Service up to the sum 
of the applicable charges set forth below:
    (1) Monthly delivery: $----/KW of Reserved Capacity per month.
    (2) Weekly delivery: $----/KW of Reserved Capacity per week.
    (3) Daily delivery: $----/KW of Reserved Capacity per day.
    The total demand charge in any week, pursuant to a reservation for 
Daily delivery, shall not exceed the rate specified in section (2) 
above times the highest amount in kilowatts of Reserved Capacity in any 
day during such week.
    (4) Hourly delivery: The basic charge shall be that agreed upon by 
the Parties at the time this service is reserved and in no event shall 
exceed $----/MWH. The total demand charge in any day, pursuant to a 
reservation for Hourly delivery, shall not exceed the rate specified in 
section (3) above times the highest amount in kilowatts of Reserved 
Capacity in any hour during such day. In addition, the total demand 
charge in any week, pursuant to a reservation for Hourly or Daily 
delivery, shall not exceed the rate specified in section (2) above 
times the highest amount in kilowatts of Reserved Capacity in any hour 
during such week.
    (5) Discounts: Three principal requirements apply to discounts for 
transmission service as follows (1) any offer of a discount made by the 
Transmission Provider must be announced to all Eligible Customers 
solely by posting on the OASIS, (2) any customer-initiated requests for 
discounts (including requests for use by one's wholesale merchant or an 
affiliate's use) must occur solely by posting on the OASIS, and (3) 
once a discount is negotiated, details must be immediately posted on 
the OASIS. For any discount agreed upon for service on a path, from 
point(s) of receipt to point(s) of delivery, the Transmission Provider 
must offer the same discounted transmission service rate for the same 
time period to all Eligible Customers on all unconstrained transmission 
paths that go to the same point(s) of delivery on the Transmission 
System.

Schedule 9--Generator Imbalance Service

    Generator Imbalance Service is provided when a difference occurs 
between the output of a generator located in the Transmission 
Provider's Control Area and a delivery schedule from that generator to 
(1) another

[[Page 12529]]

Control Area or (2) a load within the Transmission Provider's Control 
Area over a single hour. The Transmission Provider must offer this 
service when Transmission Service is used to deliver energy from a 
generator located within its Control Area. The Transmission Customer 
must either purchase this service from the Transmission Provider or 
make alternative comparable arrangements, which may include use of non-
generation resources capable of providing this service, to satisfy its 
Generator Imbalance Service obligation. To the extent the Control Area 
operator performs this service for the Transmission Provider, charges 
to the Transmission Customer are to reflect only a pass-through of the 
costs charged to the Transmission Provider by that Control Area 
Operator. The Transmission Provider may charge a Transmission Customer 
a penalty for either hourly generator imbalances under this Schedule or 
hourly energy imbalances under Schedule 4 for the same imbalance, but 
not both.
    The Transmission Provider shall establish charges for generator 
imbalance based on the deviation bands as follows: (i) Deviations 
within +/-1.5 percent (with a minimum of 2 MW) of the scheduled 
transaction to be applied hourly to any generator imbalance that occurs 
as a result of the Transmission Customer's scheduled transaction(s) 
will be netted on a monthly basis and settled financially, at the end 
of each month, at 100 percent of incremental or decremental cost, (ii) 
deviations greater than +/-1.5 percent up to 7.5 percent (or greater 
than 2 MW up to 10 MW) of the scheduled transaction to be applied 
hourly to any generator imbalance that occurs as a result of the 
Transmission Customer's scheduled transaction(s) will be settled 
financially, at the end of each month, at 110 percent of incremental 
cost or 90 percent of decremental cost, and (iii) deviations greater 
than +/-7.5 percent (or 10 MW) of the scheduled transaction to be 
applied hourly to any generator imbalance that occurs as a result of 
the Transmission Customer's scheduled transaction(s) will be settled at 
125 percent of incremental cost or 75 percent of decremental cost, 
except that an intermittent resource will be exempt from this deviation 
band and will pay the deviation band charges for all deviations greater 
than the larger of 1.5 percent or 2 MW. An intermittent resource, for 
the limited purpose of this Schedule is an electric generator that is 
not dispatchable and cannot store its fuel source and therefore cannot 
respond to changes in system demand or respond to transmission security 
constraints.
    For purposes of this Schedule, incremental cost and decremental 
cost represent the Transmission Provider's actual average hourly cost 
of the last 10 MW dispatched to supply the Transmission Provider's 
Native Load Customers, based on the replacement cost of fuel, unit heat 
rates, start-up costs (including any commitment and redispatch costs), 
incremental operation and maintenance costs, and purchased and 
interchange power costs and taxes, as applicable.

Attachment A--Form Of Service Agreement For Firm Point-To-Point 
Transmission Service

    1.0 This Service Agreement, dated as of --------, is entered 
into, by and between -------- (the Transmission Provider), and ----
---- (``Transmission Customer'').
    2.0 The Transmission Customer has been determined by the 
Transmission Provider to have a Completed Application for Firm 
Point-To-Point Transmission Service under the Tariff.
    3.0 The Transmission Customer has provided to the Transmission 
Provider an Application deposit in accordance with the provisions of 
Section 17.3 of the Tariff.
    4.0 Service under this agreement shall commence on the later of 
(l) the requested service commencement date, or (2) the date on 
which construction of any Direct Assignment Facilities and/or 
Network Upgrades are completed, or (3) such other date as it is 
permitted to become effective by the Commission. Service under this 
agreement shall terminate on such date as mutually agreed upon by 
the parties.
    5.0 The Transmission Provider agrees to provide and the 
Transmission Customer agrees to take and pay for Firm Point-To-Point 
Transmission Service in accordance with the provisions of Part II of 
the Tariff and this Service Agreement.
    6.0 Any notice or request made to or by either Party regarding 
this Service Agreement shall be made to the representative of the 
other Party as indicated below.
    Transmission Provider:

-----------------------------------------------------------------------

-----------------------------------------------------------------------

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    Transmission Customer:

-----------------------------------------------------------------------

-----------------------------------------------------------------------

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    7.0 The Tariff is incorporated herein and made a part hereof.
    IN WITNESS WHEREOF, the Parties have caused this Service 
Agreement to be executed by their respective authorized officials.
    Transmission Provider:

    By:

-----------------------------------------------------------------------

Name

-----------------------------------------------------------------------

Title

-----------------------------------------------------------------------

Date

    Transmission Customer:

    By:

-----------------------------------------------------------------------

Name

-----------------------------------------------------------------------

Title

-----------------------------------------------------------------------

Date

Specifications for Long-Term Firm Point-to-Point Transmission 
Service

1.0 Term of Transaction:-----------------------------------------------

Start Date:------------------------------------------------------------

Termination Date:------------------------------------------------------

2.0 Description of capacity and energy to be transmitted by 
Transmission Provider including the electric Control Area in which 
the transaction originates.

-----------------------------------------------------------------------

3.0 Point(s) of Receipt:-----------------------------------------------

Delivering Party:------------------------------------------------------

4.0 Point(s) of Delivery:----------------------------------------------

Receiving Party:-------------------------------------------------------

5.0 Maximum amount of capacity and energy to be transmitted (Reserved 
Capacity):-------------------------------------------------------------

6.0 Designation of party(ies) subject to reciprocal service obligation:

-----------------------------------------------------------------------

-----------------------------------------------------------------------

-----------------------------------------------------------------------

7.0 Name(s) of any Intervening Systems providing transmission service:-

-----------------------------------------------------------------------

8.0 Service under this Agreement may be subject to some combination 
of the charges detailed below. (The appropriate charges for 
individual transactions will be determined in accordance with the 
terms and conditions of the Tariff.)

8.1 Transmission Charge:-----------------------------------------------

-----------------------------------------------------------------------

8.2 System Impact and/or Facilities Study Charge(s):

-----------------------------------------------------------------------

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8.3 Direct Assignment Facilities Charge:-------------------------------

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8.4 Ancillary Services Charges:----------------------------------------

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Attachment A-1--Form of Service Agreement for the Resale, Reassignment 
or Transfer of Long-Term Firm Point-to-Point Transmission Service

    1.0 This Service Agreement, dated as of --------, is entered 
into, by and between -------- (the Transmission Provider), and ----
---- (the Assignee).
    2.0 The Assignee has been determined by the Transmission 
Provider to be an Eligible Customer under the Tariff pursuant to 
which

[[Page 12530]]

the transmission service rights to be transferred were originally 
obtained.
    3.0 The terms and conditions for the transaction entered into 
under this Service Agreement shall be subject to the terms and 
conditions of Part II of the Transmission Provider's Tariff, except 
for those terms and conditions negotiated by the Reseller, as 
identified below, of the reassigned transmission capacity (pursuant 
to Section 23.1 of this Tariff) and the Assignee and appropriately 
specified in this Service Agreement. Such negotiated terms and 
conditions include: contract effective and termination dates, the 
amount of reassigned capacity or energy, point(s) of receipt and 
delivery. Changes by the Assignee to the Reseller's Points of 
Receipt and Points of Delivery will be subject to the provisions of 
Section 23.2 of this Tariff.
    4.0 The Transmission Provider shall credit or charge the 
Reseller, as appropriate, for any difference between the price 
reflected in the Assignee's Service Agreement and the Reseller's 
Service Agreement with the Transmission Provider.
    5.0 Any notice or request made to or by either Party regarding 
this Service Agreement shall be made to the representative of the 
other Party as indicated below.
    Transmission Provider:

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    Assignee:

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    6.0 The Tariff is incorporated herein and made a part hereof.
    IN WITNESS WHEREOF, the Parties have caused this Service 
Agreement to be executed by their respective authorized officials.
    Transmission Provider:

    By:

-----------------------------------------------------------------------

Name

-----------------------------------------------------------------------

Title

-----------------------------------------------------------------------

Date

    Assignee:
    By:

-----------------------------------------------------------------------

Name

-----------------------------------------------------------------------

Title

-----------------------------------------------------------------------

Date

Specifications for the Resale, Reassignment or Transfer of Long-
Term Firm Point-to-Point Transmission Service

1.0 Term of Transaction:-----------------------------------------------

Start Date:------------------------------------------------------------

Termination Date:------------------------------------------------------

2.0 Description of capacity and energy to be transmitted by 
Transmission Provider including the electric Control Area in which the 
transaction originates.------------------------------------------------

-----------------------------------------------------------------------

3.0 Point(s) of Receipt:-----------------------------------------------

Delivering Party:------------------------------------------------------

4.0 Point(s) of Delivery:----------------------------------------------

Receiving Party:-------------------------------------------------------

5.0 Maximum amount of reassigned capacity:-----------------------------

6.0 Designation of party(ies) subject to reciprocal service obligation:

-----------------------------------------------------------------------

-----------------------------------------------------------------------

-----------------------------------------------------------------------

7.0 Name(s) of any Intervening Systems providing transmission service:-

-----------------------------------------------------------------------

8.0 Service under this Agreement may be subject to some combination 
of the charges detailed below. (The appropriate charges for 
individual transactions will be determined in accordance with the 
terms and conditions of the Tariff.)

8.1 Transmission Charge:-----------------------------------------------

-----------------------------------------------------------------------

8.2 System Impact and/or Facilities Study Charge(s):

-----------------------------------------------------------------------

-----------------------------------------------------------------------

8.3 Direct Assignment Facilities Charge:-------------------------------

-----------------------------------------------------------------------

8.4 Ancillary Services Charges:----------------------------------------

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9.0 Name of Reseller of the reassigned transmission capacity:
-----------------------------------------------------------------------

Attachment B--Form of Service Agreement for Non-Firm Point-to-Point 
Transmission Service

    1.0 This Service Agreement, dated as of --------, is entered 
into, by and between -------- (the Transmission Provider), and ----
---- (Transmission Customer).
    2.0 The Transmission Customer has been determined by the 
Transmission Provider to be a Transmission Customer under Part II of 
the Tariff and has filed a Completed Application for Non-Firm Point-
To-Point Transmission Service in accordance with Section 18.2 of the 
Tariff.
    3.0 Service under this Agreement shall be provided by the 
Transmission Provider upon request by an authorized representative 
of the Transmission Customer.
    4.0 The Transmission Customer agrees to supply information the 
Transmission Provider deems reasonably necessary in accordance with 
Good Utility Practice in order for it to provide the requested 
service.
    5.0 The Transmission Provider agrees to provide and the 
Transmission Customer agrees to take and pay for Non-Firm Point-To-
Point Transmission Service in accordance with the provisions of Part 
II of the Tariff and this Service Agreement.
    6.0 Any notice or request made to or by either Party regarding 
this Service Agreement shall be made to the representative of the 
other Party as indicated below.
    Transmission Provider:

-----------------------------------------------------------------------

-----------------------------------------------------------------------

-----------------------------------------------------------------------

    Transmission Customer:

-----------------------------------------------------------------------

-----------------------------------------------------------------------

-----------------------------------------------------------------------

    7.0 The Tariff is incorporated herein and made a part hereof.
    IN WITNESS WHEREOF, the Parties have caused this Service 
Agreement to be executed by their respective authorized officials.
    Transmission Provider:

    By:

-----------------------------------------------------------------------

Name

-----------------------------------------------------------------------

Title

-----------------------------------------------------------------------

Date

    Transmission Customer:

    By:

-----------------------------------------------------------------------

Name

-----------------------------------------------------------------------

Title

-----------------------------------------------------------------------

Date

Attachment C--Methodology To Assess Available Transfer Capability

    The Transmission Provider must include, at a minimum, the 
following information concerning its ATC calculation methodology:
    (1) A detailed description of the specific mathematical 
algorithm used to calculate firm and non-firm ATC (and AFC, if 
applicable) for its scheduling horizon (same day and real-time), 
operating horizon (day ahead and pre-schedule) and planning horizon 
(beyond the operating horizon);
    (2) A process flow diagram that illustrates the various steps 
through which ATC/AFC is calculated; and
    (3) A detailed explanation of how each of the ATC components is 
calculated for both the operating and planning horizons.
    (a) For TTC, a Transmission Provider shall: (i) explain its 
definition of TTC; (ii) explain its TTC calculation methodology; 
(iii) list the databases used in its TTC assessments; and (iv) 
explain the assumptions used in its TTC assessments regarding load 
levels, generation dispatch, and modeling of planned and contingency 
outages.
    (b) For ETC, a transmission provider shall explain: (i) its 
definition of ETC; (ii) the calculation methodology used to 
determine the transmission capacity to be set aside for native load 
(including network load), and non-OATT customers (including, if 
applicable, an explanation of assumptions on the selection of 
generators that are modeled in service); (iii) how point-to-point 
transmission service requests are incorporated; (iv) how rollover 
rights are accounted for; and (v) its processes for ensuring that 
non-firm capacity is released

[[Page 12531]]

properly (e.g., when real time schedules replace the associated 
transmission service requests in its real-time calculations).
    (c) If a Transmission Provider uses an AFC methodology to 
calculate ATC, it shall:
    (i) explain its definition of AFC; (ii) explain its AFC 
calculation methodology; (iii) explain its process for converting 
AFC into ATC for OASIS posting; (iv) list the databases used in its 
AFC assessments; and (v) explain the assumptions used in its AFC 
assessments regarding load levels, generation dispatch, and modeling 
of planned and contingency outages.
    (d) For TRM, a Transmission Provider shall explain: (i) its 
definition of TRM; (ii) its TRM calculation methodology (e.g., its 
assumptions on load forecast errors, forecast errors in system 
topology or distribution factors and loop flow sources); (iii) the 
databases used in its TRM assessments; (iv) the conditions under 
which the transmission provider uses TRM. A Transmission Provider 
that does not set aside transfer capability for TRM must so state.
    (e) For CBM, the Transmission Provider shall state include a 
specific and self-contained narrative explanation of its CBM 
practice, including: (i) an identification of the entity who 
performs the resource adequacy analysis for CBM determination; (ii) 
the methodology used to perform generation reliability assessments 
(e.g., probabilistic or deterministic); (iii) an explanation of 
whether the assessment method reflects a specific regional practice; 
(iv) the assumptions used in this assessment; and (v) the basis for 
the selection of paths on which CBM is set aside.
    (f) In addition, for CBM, a Transmission Provider shall: (i) 
explain its definition of CBM; (ii) list the databases used in its 
CBM calculations; and (iii) demonstrate that there is no double-
counting of contingency outages when performing CBM, TTC, and TRM 
calculations.
    (g) The Transmission Provider shall explain its procedures for 
allowing the use of CBM during emergencies (with an explanation of 
what constitutes an emergency, the entities that are permitted to 
use CBM during emergencies and the procedures which must be followed 
by the transmission providers' merchant function and other load-
serving entities when they need to access CBM). If the Transmission 
Provider's practice is not to set aside transfer capability for CBM, 
it shall so state.

Attachment D--Methodology for Completing a System Impact Study

    To be filed by the Transmission Provider

Attachment E--Index of Point-To-Point Transmission Service Customers

Customer
Date of Service Agreement

Attachment F--Service Agreement for Network Integration Transmission 
Service

To be filed by the Transmission Provider

Attachment G--Network Operating Agreement

To be filed by the Transmission Provider

Attachment H--Annual Transmission Revenue Requirement for Network 
Integration Transmission Service

    1. The Annual Transmission Revenue Requirement for purposes of 
the Network Integration Transmission Service shall be --------.
    2. The amount in (1) shall be effective until amended by the 
Transmission Provider or modified by the Commission.

Attachment I--Index of Network Integration Transmission Service 
Customers

Customer
Date of Service Agreement

Attachment J--Procedures for Addressing Parallel Flows

To be filed by the Transmission Provider

Attachment K--Transmission Planning Process

    The Transmission Provider shall establish a coordinated, open 
and transparent planning process with its Network and Firm Point-to-
Point Transmission Customers and other interested parties, including 
the coordination of such planning with interconnected systems within 
its region, to ensure that the Transmission System is planned to 
meet the needs of both the Transmission Provider and its Network and 
Firm Point-to-Point Transmission Customers on a comparable and 
nondiscriminatory basis. The Transmission Provider's coordinated, 
open and transparent planning process shall be provided as an 
attachment to the Transmission Provider's Tariff.
    The Transmission Provider's planning process shall satisfy the 
following nine principles, as defined in the Final Rule in Docket 
No. RM05-25-000: coordination, openness, transparency, information 
exchange, comparability, dispute resolution, regional participation, 
economic planning studies, and cost allocation for new projects. The 
planning process shall also provide a mechanism for the recovery and 
allocation of planning costs consistent with the Final Rule in 
Docket No. RM05-25-000.
    The Transmission Provider's planning process must include 
sufficient detail to enable Transmission Customers to understand:
    (i) The process for consulting with customers and neighboring 
transmission providers;
    (ii) The notice procedures and anticipated frequency of 
meetings;
    (iii) The methodology, criteria, and processes used to develop 
transmission plans;
    (iv) The method of disclosure of criteria, assumptions and data 
underlying transmission system plans;
    (v) The obligations of and methods for customers to submit data 
to the transmission provider;
    (vi) The dispute resolution process;
    (vii) The transmission provider's study procedures for economic 
upgrades to address congestion or the integration of new resources; 
and
    (viii) The relevant cost allocation procedures or principles.

Attachment L--Creditworthiness Procedures

    For the purpose of determining the ability of the Transmission 
Customer to meet its obligations related to service hereunder, the 
Transmission Provider may require reasonable credit review 
procedures. This review shall be made in accordance with standard 
commercial practices and must specify quantitative and qualitative 
criteria to determine the level of secured and unsecured credit.
    The Transmission Provider may require the Transmission Customer 
to provide and maintain in effect during the term of the Service 
Agreement, an unconditional and irrevocable letter of credit as 
security to meet its responsibilities and obligations under the 
Tariff, or an alternative form of security proposed by the 
Transmission Customer and acceptable to the Transmission Provider 
and consistent with commercial practices established by the Uniform 
Commercial Code that protects the Transmission Provider against the 
risk of non-payment.
    Additionally, the Transmission Provider must include, at a 
minimum, the following information concerning its creditworthiness 
procedures:
    (1) a summary of the procedure for determining the level of 
secured and unsecured credit;
    (2) a list of the acceptable types of collateral/security;
    (3) a procedure for providing customers with reasonable notice 
of changes in credit levels and collateral requirements;
    (4) a procedure for providing customers, upon request, a written 
explanation for any change in credit levels or collateral 
requirements;
    (5) a reasonable opportunity to contest determinations of credit 
levels or collateral requirements; and
    (6) a reasonable opportunity to post additional collateral, 
including curing any non-creditworthy determination.

[FR Doc. E7-3636 Filed 3-14-07; 8:45 am]

BILLING CODE 6717-01-P
