

[Federal Register: July 20, 2007 (Volume 72, Number 139)]
[Rules and Regulations]               
[Page 39903-40046]
From the Federal Register Online via GPO Access [wais.access.gpo.gov]
[DOCID:fr20jy07-12]                         
 

[[Page 39903]]

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Part II





Department of Energy





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 Federal Energy Regulatory Commission



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18 CFR Part 35



Market-Based Rates for Wholesale Sales of Electric Energy, Capacity and 
Ancillary Services by Public Utilities; Final Rule


[[Page 39904]]


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DEPARTMENT OF ENERGY

Federal Energy Regulatory Commission

18 CFR Part 35

[Docket No. RM04-7-000; Order No. 697]

 
Market-Based Rates for Wholesale Sales of Electric Energy, 
Capacity and Ancillary Services by Public Utilities

Issued June 21, 2007.
AGENCY: Federal Energy Regulatory Commission, Department of Energy.

ACTION: Final rule.

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SUMMARY: The Federal Energy Regulatory Commission (Commission) is 
amending its regulations to revise Subpart H to Part 35 of Title 18 of 
the Code of Federal Regulations governing market-based rates for public 
utilities pursuant to the Federal Power Act (FPA). The Commission is 
codifying and, in certain respects, revising its current standards for 
market-based rates for sales of electric energy, capacity, and 
ancillary services. The Commission is retaining several of the core 
elements of its current standards for granting market-based rates and 
revising them in certain respects. The Commission also adopts a number 
of reforms to streamline the administration of the market-based rate 
program.

DATES: Effective Date: This rule will become effective September 18, 
2007.

FOR FURTHER INFORMATION CONTACT: 
Debra A. Dalton (Technical Information), Office of Energy Markets and 
Reliability, Federal Energy Regulatory Commission, 888 First Street, 
NE., Washington, DC 20426, (202) 502-6253.
Elizabeth Arnold (Legal Information), Office of the General Counsel, 
Federal Energy Regulatory Commission, 888 First Street, NE., 
Washington, DC 20426, (202) 502-8818.

SUPPLEMENTARY INFORMATION: 

                            Table of Contents

                                                              Paragraph
                                                                 Nos.

I. Introduction............................................            1
II. Background.............................................            7
III. Overview of Final Rule................................           12
IV. Discussion.............................................           33
    A. Horizontal Market Power.............................           33
        1. Whether to Retain the Indicative Screens........           33
        2. Indicative Market Share Screen Threshold Levels            80
         and Pivotal Supplier Application Period...........
            a. Market Share Threshold......................           82
            b. Pivotal Supplier Application Period.........           94
        3. DPT Criteria....................................           96
        4. Other Products and Models.......................          118
        5. Native Load Deduction...........................          125
            a. Market Share Indicative Screen..............          125
            b. Pivotal Supplier Indicative Screen..........          143
            c. Clarification of Definition of Native Load..          150
            d. Other Native Load Concerns..................          153
        6. Control and Commitment..........................          156
            a. Presumption of Control......................          164
            b. Requirement for Sellers to have a Rate on             212
             File..........................................
        7. Relevant Geographic Market......................          215
            a. Default Relevant Geographic Market..........          215
             b. NERC's Balancing Authority Area and Default          247
             Geographic Area...............................
            c. Additional Guidelines for Alternative                 253
             Geographic Market and Flexibility.............
            d. Specific Issues Related to Power Pools and            279
             SPP...........................................
            e. RTO/ISO Exemption...........................          285
        8. Use of Historical Data..........................          292
        9. Reporting Format................................          302
        10. Exemption for New Generation (Formerly Section           307
         35.27(a) of the Commission's Regulations).........
            a. Elimination of Exemption in Section 35.27(a)          307
            b. Grandfathering..............................          327
            c. Creation of a Safe Harbor...................          335
        11. Nameplate Capacity.............................          339
        12. Transmission Imports...........................          346
            a. Use of Historical Conditions and OASIS                348
             Practices.....................................
            b. Use of Total Transfer Capability (TTC)......          363
            c. Accounting for Transmission Reservations....          365
            d. Allocation of Transmission Imports based on           370
             Pro Rata Shares of Seller's Uncommitted
             Generation Capacity...........................
            e. Miscellaneous Comments......................          376
            f. Required SIL Study for DPT Analysis.........          382
        13. Procedural Issues..............................          387
    B. Vertical Market Power...............................          397
        1. Transmission Market Power.......................          400
            a. OATT Requirement............................          403
            b. OATT Violations and MBR Revocation..........          411
            c. Revocation of Affiliates' MBR Authority.....          422
        2. Other Barriers to Entry.........................          428
        3. Barriers Erected or Controlled by Other Than The          452
         Seller............................................
        4. Planning and Expansion Efforts..................          454
        5. Monopsony Power.................................          459
    C. Affiliate Abuse.....................................          464
        1. General Affiliate Terms and Conditions..........          464

[[Page 39905]]


            a. Codifying Affiliate Restrictions in                   464
             Commission Regulations........................
            b. Definition of ``Captive Customers''.........          469
            c. Definition of ``Non-Regulated Power Sales             484
             Affiliate''...................................
            d. Other Definitions...........................          496
            e. Treating Merging Companies as Affiliates....          499
            f. Treating Energy/Asset Managers as Affiliates          503
            g. Cooperatives................................          518
        2. Power Sales Restrictions........................          529
        3. Market-Based Rate Affiliate Restrictions                  544
         (formerly Code of Conduct) for Affiliate
         Transactions Involving Power Sales and Brokering,
         Non-Power Goods and Services and Information
         Sharing...........................................
            a. Uniform Code of Conduct/Affiliate                     546
             Restrictions--Generally.......................
            b. Exceptions to the Independent Functioning             553
             Requirement...................................
            c. Information Sharing Restrictions............          570
            d. Definition of ``Market Information''........          590
            e. Sales of Non-Power Goods or Services........          595
            f. Service Companies or Parent Companies Acting          599
             on Behalf of and for the Benefit of a
             Franchised Public Utility.....................
    D. Mitigation..........................................          604
        1. Cost-Based Rate Methodology.....................          606
            a. Sales of One Week or Less...................          606
            b. Sales of more than one week but less than             632
             one year......................................
            c. Sales of one year or greater................          658
            d. Alternative methods of mitigation...........          660
        2. Discounting.....................................          699
        3. Protecting Mitigated Markets....................          720
            a. Must Offer..................................          720
            b. First-Tier Markets..........................          776
            c. Sales that Sink in Unmitigated Markets......          794
            d. Proposed Tariff Language....................          825
    E. Implementation Process..............................          832
        1. Category 1 and 2 Sellers........................          836
            a. Establishment of Category 1 and 2 Sellers...          836
            b. Threshold for Category 1 Sellers and Other            845
             Proposed Modifications........................
        2. Regional Review and Schedule....................          869
    F. MBR Tariff..........................................          897
        1. Tariff of General Applicability.................          901
        2. Placement of Terms and Conditions...............          925
        3. Single Corporate Tariff.........................          928
    G. Legal Authority.....................................          938
        1. Whether Market-Based Rates Can Satisfy the Just           938
         and Reasonable Standard Under the FPA.............
        Consistency of Market-based Rate Program with FPA            956
         Filing Requirements...............................
        2. Whether Existing Tariffs Must Be Found to Be              972
         Unjust and Unreasonable, and Whether the
         Commission Must Establish a Refund Effective Date.
    H. Miscellaneous.......................................          975
        1. Waivers.........................................          975
            a. Accounting Waivers..........................          979
            b. Timing......................................          988
            c. Part 34 Waivers Blanket Authorizations......          993
        2. Sellers Affiliated with a Foreign Utility.......         1000
        3. Change in Status................................         1008
            a. Fuel Supplies...............................         1011
            b. Transmission Outages........................         1019
            c. Control.....................................         1027
            d. Triggering Events...........................         1033
            e. Timing of Reporting.........................         1035
            f. Sellers Affiliated with a Foreign Utility...         1040
        4. Third-Party Providers of Ancillary Services.....         1046
            a. Internet Postings and Reporting Requirements         1052
            b. Pricing for Ancillary Services in RTOs/ISOs.         1062
        5. Reactive Power and Real Power Losses............         1072
            a. Reactive Power..............................         1073
            b. Real Power Losses...........................         1075
V. Section-by-Section Analysis of Regulations..............         1077
VI. Information Collection Statement.......................         1105
VII. Environmental Analysis................................         1124
VIII. Regulatory Flexibility Act...........................         1125
IX. Document Availability..................................         1129
X. Effective Date and Congressional Notification...........         1132
Regulatory Text
Appendix A to Subpart H: Standard Screen Format
Appendix B to Subpart H: Corporate Entities and Assets
 sample appendix
Appendix C to the Final Rule: Required Provisions of the
 Market-Based Rate Tariff

[[Page 39906]]


Appendix D to the Final Rule: Regions and Schedule for
 Regional Market power Update Process
Appendix E to the Final Rule: List of Commenters and
 Acronyms
Attachment A to the Final Rule: MOELLER, Commissioner,
 dissenting in part


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

I. Introduction

    1. On May 19, 2006, the Commission issued a Notice of Proposed 
Rulemaking (NOPR), pursuant to sections 205 and 206 of the Federal 
Power Act (FPA),\1\ in which the Commission proposed to amend its 
regulations governing market-based rate authorizations for wholesale 
sales of electric energy, capacity and ancillary services by public 
utilities. In the NOPR, the Commission proposed to modify all existing 
market-based authorizations and tariffs so they would reflect any new 
requirements ultimately adopted in the Final Rule. After considering 
the comments received in response to the NOPR, the Commission adopts in 
many respects the proposals contained in the NOPR, but with a number of 
modifications.
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    \1\ 16 U.S.C. 824d, 824e.
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    2. This Final Rule represents a major step in the Commission's 
efforts to clarify and codify its market-based rate policy by providing 
a rigorous up-front analysis of whether market-based rates should be 
granted, including protective conditions and ongoing filing 
requirements in all market-based rate authorizations, and reinforcing 
its ongoing oversight of market-based rates. The specific components of 
this rule, in conjunction with other regulatory activities, are 
designed to ensure that market-based rates charged by public utilities 
are just and reasonable. There are three major aspects of the 
Commission's market-based rate regulatory regime.
    3. First is the analysis that is the subject of this rule: whether 
a market-based rate seller or any of its affiliates has market power in 
generation or transmission and, if so, whether such market power has 
been mitigated.\2\ If the seller is granted market-based rates, the 
authorization is conditioned on: affiliate restrictions governing 
transactions and conduct between power sales affiliates where one or 
more of those affiliates has captive customers; a requirement to file 
post-transaction electric quarterly reports (EQRs) containing specific 
information about contracts and transactions; a requirement to file any 
change of status; and a requirement for all large sellers to file 
triennial updates.\3\
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    \2\ The Commission also considers whether the seller or its 
affiliates can erect other barriers to entry (e.g., key sites for 
building new power supply; key inputs to power supply) in the 
relevant market and whether there is evidence of affiliate abuse or 
reciprocal dealing.
    \3\ During the past three years, the Commission has initiated 
over 20 investigations under section 206 of the FPA because of 
concerns of possible market power. Several of those investigations 
led to the revocation or voluntary relinquishing of market-based 
rate authority and the ordering of refunds by sellers.
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    4. Second, for wholesale sellers that have market-based rate 
authority and sell into day ahead or real-time organized markets 
administered by Regional Transmission Organizations (RTOs) and 
Independent System Operators (ISOs), they do so subject to specific 
RTO/ISO market rules approved by the Commission and applicable to all 
market participants. These rules are designed to help ensure that 
market power cannot be exercised in those organized markets and include 
additional protections (e.g., mitigation measures) where appropriate to 
ensure that prices in those markets are just and reasonable. Thus, a 
seller in such markets not only must have an authorization based on an 
analysis of that individual seller's market power, but it must also 
abide by additional rules contained in the RTO/ISO tariffs.
    5. Third, the Commission, through its ongoing oversight of market-
based rate authorizations and market conditions, may take steps to 
address seller market power or modify rates. For example, based on its 
review of triennial market power updates required of market-based rate 
sellers, its review of EQR filings made by market-based rate sellers, 
and its review of required notices of change in status, the Commission 
may institute a section 206 proceeding to revoke a seller's market-
based rate authorization if it determines that the seller may have 
gained market power since its original market-based rate authorization. 
The Commission may also, based on its review of EQR filings or daily 
market price information, investigate a specific utility or anomalous 
market circumstances to determine whether there has been any conduct in 
violation of RTO/ISO market rules or Commission orders or tariffs, or 
any prohibited market manipulation, and take steps to remedy any 
violations. These steps could include, among other things, disgorgement 
of profits and refunds to customers if a seller is found to have 
violated Commission orders, tariffs or rules, or a civil penalty paid 
to the United States Treasury if a seller is found to have engaged in 
prohibited market manipulation or to have violated Commission orders, 
tariffs or rules.
    6. The Commission recognizes that several recent court decisions by 
the United States Court of Appeals for the Ninth Circuit \4\ have 
created some uncertainty for sellers transacting pursuant to our 
market-based rate program. The cases raise issues with respect to the 
circumstances under which sellers' pre-authorized market-based rate 
sales may be subject to retroactive refunds and the circumstances under 
which buyers might be able to invalidate or modify contracts based on 
the argument that the contracts were entered into at a time when 
markets were dysfunctional. The Commission's first and foremost duty is 
to protect customers from unjust and unreasonable rates; however, we 
recognize that uncertainties regarding rate stability and contract 
sanctity can have a chilling effect on investments and a seller's 
willingness to enter into long-term contracts and this, in turn, can 
harm customers in the long run. The Commission recently provided 
guidance in this regard, noting that these Ninth Circuit decisions 
addressed a unique set of facts and a market-based rate program that 
has undergone substantial improvement since 2001, and reiterating that 
an ex ante finding of the absence of market power, coupled with the EQR 
filing and effective regulatory oversight qualifies as sufficient prior 
review for market-based rate contracts to satisfy the notice and filing 
requirements of FPA section 205.\5\ Through this Final Rule, the 
Commission is clarifying and further

[[Page 39907]]

improving its market-based rate program. Moreover, the Commission will 
explore ways to continue to improve its market-based rate program and 
processes to assure appropriate customer protections but at the same 
time provide greater regulatory and market certainty for sellers in 
light of the above court opinions.
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    \4\ See State of California, ex rel. Bill Lockyer v. FERC, 383 
F.3d 1006 (9th Cir. 2004), cert. denied (S. Ct. Nos. 06-888 and 06-
1100, June 18, 2007) (Lockyer); Public Utility District No. 1 of 
Snohomish County, Washington v. FERC, 471 F.3d 1053 (9th Cir. 2006) 
(Snohomish); Public Utilities Commission of the State of California 
and California Electric Oversight Board v. FERC, 474 F.3d 587 (9th 
Cir. 2007) (California Commission).
    \5\ CAlifornians for Renewable Energy, Inc. v. Cal. Pub. Util. 
Com'n, 119 FERC ] 61,058 (2007).
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II. Background

    7. In 1988, the Commission began considering proposals for market-
based pricing of wholesale power sales. The Commission acted on market-
based rate proposals filed by various wholesale suppliers on a case-by-
case basis. Over the years, the Commission developed a four-prong 
analysis used to assess whether a seller should be granted market-based 
rate authority: (1) Whether the seller and its affiliates lack, or have 
adequately mitigated, market power in generation; (2) whether the 
seller and its affiliates lack, or have adequately mitigated, market 
power in transmission; (3) whether the seller or its affiliates can 
erect other barriers to entry; and (4) whether there is evidence 
involving the seller or its affiliates that relates to affiliate abuse 
or reciprocal dealing.
    8. The Commission initiated the instant rulemaking proceeding in 
April 2004 to consider ``the adequacy of the current analysis and 
whether and how it should be modified to assure that prices for 
electric power being sold under market-based rates are just and 
reasonable under the Federal Power Act.'' \6\ At that time, the 
Commission noted that much has changed in the industry since the four-
prong analysis was first developed and posed a number of questions that 
would be explored through a series of technical conferences.
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    \6\ Market-Based Rates for Public Utilities, 107 FERC ] 61,019 
AT P 1(2004) (initiating rulemaking proceeding).
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    9. On April 14, 2004, the Commission issued an order modifying the 
then-existing generation market power analysis and its policy governing 
market power mitigation, on an interim basis.\7\ The April 14 Order 
adopted a policy that provided sellers a number of procedural options, 
including two indicative generation market power screens (an 
uncommitted pivotal supplier analysis and an uncommitted market share 
analysis), and the option of proposing mitigation tailored to the 
particular circumstances of the seller that would eliminate the ability 
to exercise market power. The order also explained that sellers could 
choose to adopt cost-based rates. On July 8, 2004, the Commission 
addressed requests for rehearing of the April 14 Order, reaffirming the 
basic analysis, but clarifying and modifying certain instructions for 
performing the generation market power analysis. Over the next year, 
the Commission convened four technical conferences, seeking input 
regarding all four prongs of the analysis.
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    \7\ AEP Power Marketing, Inc., 107 FERC ] 61,018 (April 14 
Order), order on reh'g, 108 FERC ] 61,026 (2004) (July 8 Order).
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    10. On May 19, 2006, the Commission issued a NOPR in this 
proceeding.\8\ The Commission explained that refining and codifying 
effective standards for market-based rates would help customers by 
ensuring that they are protected from the exercise of market power and 
would also provide greater certainty to sellers seeking market-based 
rate authority.
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    \8\ 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) (NOPR).
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    11. The regulations proposed in the NOPR adopted in most respects 
the Commission's existing standards for granting market-based rates, 
and proposed to streamline certain aspects of its filing requirements 
to reduce the administrative burdens on sellers, customers and the 
Commission. The Commission received over 100 comments and reply 
comments in response to the NOPR. A list of commenters is attached as 
Appendix E.

III. Overview of Final Rule

    12. In this Final Rule, the Commission revises and codifies in the 
Commission's regulations the standards for market-based rates for 
wholesale sales of electric energy, capacity and ancillary services. 
The Commission also adopts a number of reforms to streamline the 
administration of the market-based rate program. As set forth below, 
the Final Rule adopts in many respects the proposals contained in the 
NOPR, but with a number of modifications.

Horizontal Market Power

    13. In this Final Rule, the Commission adopts, with certain 
modifications, two indicative market power screens (the uncommitted 
market share screen (with a 20 percent threshold) and the uncommitted 
pivotal supplier screen), each of which will serve as a cross check on 
the other to determine whether sellers may have market power and should 
be further examined. Sellers that fail either screen will be rebuttably 
presumed to have market power. However, such sellers will have full 
opportunity to present evidence (through the submission of a Delivered 
Price Test (DPT) analysis) demonstrating that, despite a screen 
failure, they do not have market power, and the Commission will 
continue to weigh both available economic capacity and economic 
capacity when analyzing market shares and Hirschman-Herfindahl Indices 
(HHIs).
    14. With regard to control over generation capacity, the Commission 
finds that the determination of control is appropriately based on a 
review of the totality of circumstances on a fact-specific basis. No 
single factor or factors necessarily results in control. The Commission 
will require a seller to make an affirmative statement as to whether a 
contractual arrangement (energy management agreement, tolling 
agreement, specific contractual terms, etc.) transfers control and to 
identify the party or parties it believes controls the generation 
facility. Regarding a presumption of control, the Commission will 
continue its practice of attributing control to the owner absent a 
contractual agreement transferring such control, and we provide 
guidance as to how we will consider jointly-owned facilities.
    15. The Commission adopts its current approach with regard to the 
default relevant geographic market, with some modifications. In 
particular, the Commission will continue to use a seller's control area 
(balancing authority area) \9\ or the RTO/ISO market, as applicable, as 
the default relevant geographic market. However, where the Commission 
has made a specific finding that there is a submarket within an RTO, 
that submarket becomes the default relevant geographic market for 
sellers located within the submarket for purposes of the market-based 
rate analysis. The Commission also provides guidance as to the factors 
the Commission will consider in evaluating whether, in a particular 
case, to adopt an alternative geographic market instead of relying on 
the default geographic market.
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    \9\ As discussed below in the Horizontal Market Power section, 
the Commission adopts the use of balancing authority area instead of 
control area.
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    16. The Commission modifies the native load proxy for the market 
share screens from the minimum peak day in the season to the average 
peak native load, averaged across all days in the season, and clarifies 
that native load can only include load attributable to native load 
customers based on the definition of native load commitment in Sec.  
33.3(d)(4)(i) of the Commission's regulations. In addition, sellers are

[[Page 39908]]

given the option of using seasonal capacity instead of nameplate 
capacity.
    17. The Commission retains the snapshot in time approach based on 
historical data for both the indicative screens and the DPT analysis 
and disallows projections to that data. A standard reporting format is 
adopted for sellers to follow when summarizing their analysis.
    18. The Commission modifies the treatment of newly constructed 
generation and adopts an approach that requires all sellers to perform 
a horizontal analysis for the grant of market-based rate authority.
    19. With regard to simultaneous transmission import limit studies 
(SILs), the Commission adopts the requirement that the SIL study be 
used as a basis for transmission access for both the indicative screens 
and the DPT analysis. Further, the Commission clarifies that the SIL 
study as shown in Appendix E of the April 14 Order is the only study 
that meets our requirements. The Commission provides guidance regarding 
how to perform the SIL study, including accounting for specific OASIS 
practices.
    20. Finally, the Commission adopts procedures under which 
intervenors in section 205 proceedings may obtain expedited access to 
Critical Energy Infrastructure Information (CEII) or other information 
for which privileged treatment is sought.

Vertical Market Power

    21. With regard to vertical market power and, in particular, 
transmission market power, the Commission continues the current policy 
under which an open access transmission tariff (OATT) is deemed to 
mitigate a seller's transmission market power. However, in recognition 
of the fact that OATT violations may nonetheless occur, the Commission 
states that a finding of a nexus between the specific facts relating to 
the OATT violation and the entity's market-based rate authority may 
subject the seller to revocation of its market-based rate authority or 
other remedies the Commission may deem appropriate, such as 
disgorgement of profits or civil penalties. In addition, the Commission 
creates 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.
    22. With regard to other barriers to entry, the Commission adopts 
the NOPR proposal to consider a seller's ability to erect other 
barriers to entry as part of the vertical market power analysis, but 
modifies the requirements when addressing other barriers to entry. The 
Commission also provides clarification regarding the information that a 
seller must provide with respect to other barriers to entry (including 
which inputs to electric power production the Commission will consider 
as other barriers to entry). The Commission adopts a rebuttable 
presumption that ownership or control of, or affiliation with an entity 
that owns or controls, intrastate natural gas transportation, 
intrastate natural gas storage or distribution facilities; sites for 
generation capacity development; and sources of coal supplies and the 
transportation of coal supplies such as barges and rail cars do not 
allow a seller to raise entry barriers, but intervenors are allowed to 
demonstrate otherwise. The Final Rule also requires a seller to provide 
a description of its ownership or control of, or affiliation with an 
entity that owns or controls, intrastate natural gas transportation, 
intrastate natural gas storage or distribution facilities; sites for 
generation capacity development; and sources of coal supplies and the 
transportation of coal supplies such as barges and rail cars. The 
Commission will require sellers to provide this description and to make 
an affirmative statement that they have not erected barriers to entry 
into the relevant market and will not erect barriers to entry into the 
relevant market. The Final Rule clarifies that the obligation in this 
regard applies both to the seller and its affiliates, but is limited to 
the geographic market(s) in which the seller is located.

Affiliate Abuse

    23. With regard to affiliate abuse, the Commission adopts the NOPR 
proposal to discontinue considering affiliate abuse as a separate 
``prong'' of the market-based rate analysis and instead to codify 
affiliate restrictions in the Commission's regulations and address 
affiliate abuse by requiring that the provisions provided in the 
affiliate restrictions be satisfied on an ongoing basis as a condition 
of obtaining and retaining market-based rate authority. As codified in 
this Final Rule, the affiliate restrictions include a provision 
prohibiting power sales between a franchised public utility with 
captive customers and any market-regulated power sales affiliates\10\ 
without first receiving Commission authorization for the transaction 
under section 205 of the FPA. The Commission also codifies as part of 
the affiliate restrictions the requirements that previously have been 
known as the market-based rate ``code of conduct'' (governing the 
separation of functions, the sharing of market information, sales of 
non-power goods or services, and power brokering), as clarified and 
modified in this Final Rule. The Commission modifies certain of these 
provisions, including separation of functions and information sharing, 
consistent with certain requirements and exceptions contained in the 
Commission's standards of conduct.\11\ In the Final Rule the Commission 
defines ``captive customers'' as ``any wholesale or retail electric 
energy customers served under cost-based regulation'' and provides 
clarification that the definition of ``captive customers'' does not 
include those customers who have retail choice, i.e., the ability to 
select a retail supplier based on the rates, terms and conditions of 
service offered. In addition, among other clarifications, the 
Commission clarifies and modifies the definition of ``non-regulated 
power sales affiliate,'' and changes the term to ``market-regulated 
power sales affiliate.''
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    \10\ In the NOPR, the Commission proposed to define the term 
``non-regulated power sales affiliate.'' As discussed below, this 
Final Rule uses the term ``market-regulated power sales affiliate'' 
instead.
    \11\ 18 CFR part 358.
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    24. The Commission also provides clarification as to what types of 
affiliate transactions are permissible and the criteria used to make 
those decisions, and how the Commission will treat merging partners. In 
addition, the Commission codifies in the regulations a prohibition on 
the use of third-party entities, including energy/asset managers, to 
circumvent the affiliate restrictions, but does not adopt the NOPR 
proposal to treat energy/asset managers as affiliates. The Commission 
also provides clarification regarding the Commission's market-based 
rate policies as they relate to cooperatives.

Mitigation

    25. With regard to mitigation, in the Final Rule the Commission 
retains the incremental cost plus 10 percent methodology as the default 
mitigation for sales of one week or less; the default mitigation rate 
for mid-term sales (sales of more than one week but less than one year) 
priced at an embedded cost ``up to'' rate reflecting the costs of the 
unit(s) expected to provide the service; and the existing policy for 
sales of one year or more (long-term) sales.\12\ The

[[Page 39909]]

Commission will continue to allow sellers to propose alternative cost-
based methods of mitigation tailored to their particular circumstances. 
The Final Rule also states that the Commission will make its stacking 
methodology available for the public.\13\ In addition, the Commission 
will continue the practice of allowing discounting and will permit 
selective discounting by mitigated sellers provided that the sellers do 
not use such discounting to unduly discriminate or give undue 
preference.
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    \12\ We note here that we expect mitigated sellers adopting the 
default cost-based rates or proposing new cost-based rates will 
propose a cost-based rate tariff of general applicability for sales 
of less than one year, and sales of power for one year or longer 
will be filed with the Commission on a stand-alone basis.
    \13\ This is addressed in the Mitigation section discussion 
concerning the cost-based rate methodology for sales of more than 
one week but less than one year.
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    26. The Commission concludes that use of the Western Systems Power 
Pool (WSPP) Agreement may be unjust, unreasonable or unduly 
discriminatory or preferential for certain sellers. Therefore, in an 
order being issued concurrently with this Final Rule, the Commission is 
instituting a proceeding under section 206 of the FPA to investigate 
whether, for sellers found to have market power or presumed to have 
market power in a particular market, the WSPP Agreement rate for 
coordination energy sales is just and reasonable in such market.
    27. The Commission does not impose an across-the-board ``must 
offer'' requirement for mitigated sellers. While wholesale customer 
commenters have raised concerns relating to their ability to access 
needed power, the Commission concludes that there is insufficient 
record evidence to support instituting a generic ``must offer'' 
requirement.
    28. The Commission limits mitigation to the market in which the 
seller has been found to possess, or chosen not to rebut the 
presumption of, market power and does not place limitations on a 
mitigated seller's ability to sell at market-based rates in areas in 
which the seller has not been found to have market power.
    29. Finally, regarding mitigation, the Final Rule allows mitigated 
sellers to make market-based rate sales at the metered boundary between 
a mitigated balancing authority area and a balancing authority area in 
which the seller has market-based rate authority under the conditions 
set forth herein, including a record retention requirement, and 
provides a tariff provision to allow for such sales.

Implementation Process

    30. The Commission adopts the NOPR proposal to create a category of 
sellers (Category 1 sellers) that are exempt from the requirement to 
automatically submit updated market power analyses, with certain 
clarifications and modifications. In addition, the Commission adopts 
the NOPR proposal to implement a regional approach to updated market 
power analyses, but reduces the number of regions from nine to six.
    31. As for a standardized tariff, the Commission does not adopt the 
NOPR proposal to adopt a market-based rate tariff of general 
applicability that all market-based rate sellers will be required to 
file as a condition of market-based rate authority and to require each 
corporate family to have only one tariff, with all affiliates with 
market-based rate authority separately identified in the tariff. 
Instead, the Commission adopts specific market-based rate tariff 
provisions that the Commission will require to be part of a seller's 
market-based rate tariff. However, the Commission will allow a seller 
to include seller specific terms and conditions in its market-based 
rate tariff, but the Commission will not review any of these 
provisions, as they are presumed to be just and reasonable based on the 
Commission's finding that the seller and its affiliates lack or have 
adequately mitigated market power in the relevant market.

Miscellaneous Issues

    32. The Commission also provides clarifications in the Final Rule 
with regard to accounting waivers, Part 34 blanket authorizations, 
sellers affiliated with foreign entities, and the change in status 
reporting requirement. Further, the Commission abandons the posting 
requirements for third party sellers of ancillary services at market-
based rates as redundant of other reporting requirements.

IV. Discussion

A. Horizontal Market Power

1. Whether To Retain the Indicative Screens
    33. As discussed in detail below, the Commission is adopting in 
this Final Rule two indicative horizontal market power screens, each of 
which will serve as a cross-check on the other to determine whether 
sellers may have market power and should be further examined. Although 
some sellers disagree with the use of two screens or find flaws in 
them, we conclude that this conservative approach will allow the 
Commission to more readily identify potential market power. Sellers 
that fail either screen will be rebuttably presumed to have market 
power. However, such sellers will have full opportunity to present 
evidence (through the submission of a DPT analysis) demonstrating that, 
despite a screen failure, they do not have market power. No screen is 
perfect, but we believe this approach appropriately balances the need 
to protect against market power with the desire not to place 
unnecessary filing burdens on utilities.
    34. The first screen is the wholesale market share screen, which 
measures for each of the four seasons whether a seller has a dominant 
position in the market based on the number of megawatts of uncommitted 
capacity owned or controlled by the seller as compared to the 
uncommitted capacity of the entire relevant market.\14\
---------------------------------------------------------------------------

    \14\ April 14 Order, 107 FERC ] 61,018 at P 100.
---------------------------------------------------------------------------

    35. The second screen is the pivotal supplier screen, which 
evaluates the potential of a seller to exercise market power based on 
uncommitted capacity at the time of the balancing authority area's 
annual peak demand. This screen focuses on the seller's ability to 
exercise market power unilaterally. It examines whether the market 
demand can be met absent the seller during peak times. A seller is 
pivotal if demand cannot be met without some contribution of supply by 
the seller or its affiliates.\15\
---------------------------------------------------------------------------

    \15\ Id. at P 72.
---------------------------------------------------------------------------

    36. Use of the two screens together enables the Commission to 
measure market power at both peak and off-peak times, and to examine 
the seller's ability to exercise market power unilaterally and in 
coordinated interaction with other sellers. Use of the two screens, 
therefore, provides a more complete picture of a seller's ability to 
exercise market power.\16\
---------------------------------------------------------------------------

    \16\ Id.
---------------------------------------------------------------------------

    37. As discussed more fully in the following sections, with regard 
to determining the total supply in the relevant market, the horizontal 
market power analysis centers on and examines the balancing authority 
area where the seller's generation is physically located. Total supply 
is determined by adding the total amount of uncommitted capacity 
located in the relevant market (including capacity owned by the seller 
and competing suppliers) with that of uncommitted supplies that can be 
imported (limited by simultaneous transmission import capability) into 
the relevant market from the first-tier markets.
    38. Uncommitted capacity is determined by adding the total 
nameplate or seasonal capacity \17\ of

[[Page 39910]]

generation owned or controlled through contract and firm purchases, 
less operating reserves, native load commitments and long-term firm 
sales.\18\ Uncommitted capacity from a seller's remote generation 
(generation located in an adjoining balancing authority area) should be 
included in the seller's total uncommitted capacity amounts. Any 
simultaneous transmission import capability should first be allocated 
to the seller's uncommitted remote generation. Any remaining 
simultaneous transmission import capability would then be allocated to 
any uncommitted competing supplies.
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    \17\ As discussed more fully below, in this Final Rule, the 
Commission gives sellers the option of using seasonal capacity 
instead of nameplate capacity.
    \18\ Sellers may deduct generation associated with their long-
term firm requirements sales, unless the Commission disallows such 
deductions based on extraordinary circumstances.
---------------------------------------------------------------------------

    39. Capacity reductions as a result of operating reserve 
requirements should be no higher than State and Regional Reliability 
Council operating requirements for reliability (i.e., operating 
reserves). Any proposed amounts that are higher than such requirements 
must be fully supported and will be considered on a case-by-case basis. 
Moreover, if an intervenor provides conclusive evidence that a seller 
did not in actual practice comply with the NERC or regional reliability 
council operating reserve requirements, then we will take this into 
account in determining the amount of the operating reserve deduction. 
However, we emphasize that we expect each utility to meet its NERC and 
regional reliability council reserve requirements, and that absent a 
clear showing to the contrary by an intervenor, the required operating 
reserve requirement is what we will use as the deduction in the market-
based rate calculation.\19\
---------------------------------------------------------------------------

    \19\ April 14 Order, 107 FERC ] 61,018 at P96.
---------------------------------------------------------------------------

    40. The Commission does not expect that sellers will have planned 
generation outages scheduled for the annual peak load day. However, on 
a case-by-case basis, the Commission will consider credible evidence 
that planned generation outages for the peak load day of the year 
should be included based on the particular circumstances of the 
seller.\20\
---------------------------------------------------------------------------

    \20\ As noted below, the market share screen deducts generation 
capacity used for planned outages (that were done in accordance with 
good utility practice) in all four seasons in order to reflect the 
typical operation of generation units.
---------------------------------------------------------------------------

    41. With regard to the pivotal supplier analysis, after computing 
the total uncommitted supply available to serve the relevant market, 
the next step in this analysis involves identifying the wholesale 
market. The proxy for the wholesale load is the annual peak load 
(needle peak) less the proxy for native load obligation (i.e., the 
average of the daily native load peaks during the month in which the 
annual peak load day occurs). Peak load is the largest electric power 
requirement (based on net energy for load) during a specific period of 
time, usually integrated over one clock hour and expressed in 
megawatts, for the native load and firm wholesale requirements sales.
    42. To calculate the net uncommitted supply available to compete at 
wholesale, the pivotal supplier analysis deducts the wholesale load 
from the total uncommitted supply. If the seller's uncommitted capacity 
is less than the net uncommitted supply, the seller satisfies the 
pivotal supplier portion of the generation market power analysis and 
passes the screen. If the seller's uncommitted capacity is equal to or 
greater than the net uncommitted supply, then the seller fails the 
pivotal supplier analysis which creates a rebuttable presumption of 
market power.
    43. With regard to the wholesale market share analysis, which 
measures for each of the four seasons whether a seller has a dominant 
position in the market based on the number of megawatts of uncommitted 
capacity owned or controlled by the seller as compared to the 
uncommitted capacity of the entire relevant market, uncommitted 
capacity amounts are used, as described above, with the following 
variation. Planned outages (that were done in accordance with good 
utility practice) for each season will be considered. Planned outage 
amounts should be consistent with those as reported in FERC Form No. 
714. To determine the amount of planned outages for a given season, the 
total number of MW-days of outages is divided by the total number of 
days in the season. For example, if 500 MW of generation that is out 
for six days during the winter period the calculation of planned 
outages would be: (500 MW x 6)/91 or 33 MW.
    44. The market share analysis adopts an initial threshold of 20 
percent. That is, a seller who has less than a 20 percent market share 
in the relevant market for all seasons will be considered to satisfy 
the market share analysis.\21\ A seller with a market share of 20 
percent or more in the relevant market for any season will have a 
rebuttable presumption of market power but can present historical 
evidence to show that the seller satisfies our generation market power 
concerns.
---------------------------------------------------------------------------

    \21\ The 20 percent threshold is consistent with Sec.  4.134 of 
the U.S. Department of Justice 1984 Merger Guidelines issued June 
14, 1984, reprinted in Trade Reg. Rep. P13,103 (CCH 1988): ``The 
Department [of Justice] is likely to challenge any merger satisfying 
the other conditions in which the acquired firm has a market share 
of 20 percent or more.''
---------------------------------------------------------------------------

Commission Proposal
    45. In the NOPR, the Commission proposed to retain the indicative 
screens (pivotal supplier and market share) to assess horizontal market 
power that were initially adopted in April 2004.\22\ Because the 
indicative screens are intended only to identify the sellers that 
require further review, the Commission proposed to retain the 20 
percent threshold for the wholesale market share indicative screen, 
stating that the 20 percent market share threshold strikes the right 
balance in seeking to avoid both ``false negatives'' and ``false 
positives.'' The Commission also proposed to continue to measure 
pivotal suppliers at the time of the annual peak load in the pivotal 
supplier indicative screen, which is the most likely point in time that 
a seller will be a pivotal supplier. For this reason, the Commission 
did not propose to expand the pivotal supplier analysis to other time 
periods.
---------------------------------------------------------------------------

    \22\ See April 14 Order, 107 FERC  61,018.
---------------------------------------------------------------------------

Comments
    46. Numerous commenters question whether the Commission should 
retain the current indicative screens in whole or in part. For example, 
Southern, Duke and EEI advocate abandoning the market share indicative 
screen altogether. They argue that the market share indicative screen 
is ``fatally flawed'' because it does not take into account wholesale 
demand in the relevant market \23\ which makes it difficult for 
traditional utilities outside of RTOs/ISOs to pass.\24\ E.ON. US. and 
PNM/Tucson separately argue that one must consider the level of demand 
that is seeking supply and, more particularly, what ability sellers 
have to exercise market power over those buyers.\25\ In this regard, 
E.ON. US. and

[[Page 39911]]

PNM/Tucson argue that to the extent the market share screen does not 
consider wholesale demand, it is not a useful indicator, and in fact is 
almost universally a false indicator of the ability of a seller to 
exercise market power over demand. Also, EEI argues that because of 
design flaws inherent in the market share screen as well as the 
negative impact that the use of this test has had since 2004 on the 
development of competitive wholesale markets (through the inappropriate 
exclusion of the majority of non-RTO utilities from participating in 
that market), the market share screen should be eliminated for all 
market power screening and analysis purposes.\26\
---------------------------------------------------------------------------

    \23\ Southern at 11, Duke at 20, EEI at 6-7.
    \24\ Duke at 17, EEI at 8-9.
    \25\ E.ON. US. at 16-17 and PNM/Tucson at 5-6. According to 
E.ON. US. and PNM/Tucson, the past decade has seen strong 
development in the West of open access to transmission and the 
ownership of generating assets, solely or jointly, by formerly 
``captive'' wholesale customers. As a result, any analysis that has 
as its foundation division of the market into suppliers and 
presumptively captive customers is at odds with present reality, in 
which wholesale customers have a host of suppliers seeking their 
business. E.ON. US. and PNM/Tucson state that an illustration of how 
open access in the West has enhanced the ability of load serving 
entities to secure competitive resources on an efficient scale 
across control areas is provided by a recent Southwest Public Power 
Resources Group request for proposals for 255 MW in 2007, growing to 
962 MW by 2014 in four control areas--Arizona Public Service, Salt 
River Project, Western Area Power Administration-Desert Southwest 
Region and Tucson Electric. (The Southwest Public Power Resources 
Group represents thirty-nine public power entities in Arizona, 
California, and Nevada.) See Southwestern Public Utilities Issue 
Long-Term RFP, ELECTRIC POWER DAILY, July 14, 2006, at 3.
    \26\ EEI at 10.
---------------------------------------------------------------------------

    47. EEI contends that the Commission should use only the pivotal 
supplier screen for indicative screening purposes and the DPT pivotal 
supplier and market concentration analyses for the purposes of 
rebutting the presumption of generation market power that would result 
from the failure of the indicative pivotal supplier screen. EEI argues 
that if the Commission continues to use the market share screen as an 
initial screen, the Commission should not include a market share test 
as a component of any subsequent DPT analysis of market power.
    48. E.ON U.S. and PNM/Tucson generally agree, stating that market 
share is an unreliable measure of market power in competitive energy 
markets and that the courts have long recognized that market share is 
not a reliable indicator of market power in regulated markets.\27\ In 
particular, E.ON U.S. and PNM/Tucson argue that even a marginal failure 
of the market share screen results in a rebuttable presumption of 
market power that has tremendous consequences by forcing sellers to 
proceed to costly and time-consuming DPT analysis or agree to 
mitigation. As a result, the ``false positives'' arising from the 
market share screen dampen the vigor of competitive wholesale market 
participation by unnecessarily curtailing the market-based authority of 
entities that, in fact, lack market power (to the extent such entities 
choose not to pursue a costly and uncertain effort to rebut the 
presumption of market power created by the screen failure).\28\
---------------------------------------------------------------------------

    \27\ Citing Cost Mgmt. Servs., Inc. v. Wash. Natural Gas Co., 99 
F.3d 937, 950-51 (9th Cir. 1996) (Cost Management); Rebel Oil Co., 
Inc. v. Atl. Richfield Co., 51 F.3d 1421, 1439 (9th Cir. 1995) 
(Rebel); S. Pac. Communications Co. v. AT&T Co., 740 F.2d 980, 1000 
(D.C. Cir. 1984) (Southern Pacific Communications); MCI 
Communications Corp. v. AT&T Co., 708 F.2d 1081, 1107 (7th Cir. 
1983) (MCI Communications); Mid-Tex. Communications Sys., Inc. v. 
AT&T Co., 615 F.2d 1372, 1386-89 (5th Cir. 1980) (Mid-Tex 
Communications); Almeda Mall, Inc. v. Houston Lighting & Power Co., 
615 F.2d 343, 354 (5th Cir. 1980) (Almeda).
    \28\ E.ON U.S. at 16; PNM/Tucson at 5-6.
---------------------------------------------------------------------------

    49. Duke and Southern suggest that a wholesale contestable load 
analysis (also described as a ``competitive alternatives'' analysis) 
\29\ should be added to the indicative screens, which would consider 
the amount of excess market supply available to serve the amount of 
wholesale demand seeking supply.\30\ Generally, if available non-
applicant supply is at least twice the contestable load, advocates of 
the contestable load analysis believe that is sufficient to make a 
finding that the market is competitive.\31\ Other commenters agree that 
the market share indicative screen can diminish competition because 
sellers that are subjects of an FPA section 206 investigation tend to 
choose mitigation rather than challenge the presumption of market 
power.\32\
---------------------------------------------------------------------------

    \29\ Dr. Pace at 12.
    \30\ Duke at 21, Southern at 16-17.
    \31\ Dr. Pace at 16.
    \32\ E.ON U.S. at 15-16; PNM/Tucson at 5-6, EEI at 10.
---------------------------------------------------------------------------

    50. Duke argues that the Commission has yet to establish a need for 
using the market share indicative screen in addition to the pivotal 
supplier indicative screen in assessing the potential for the exercise 
of generation market power. In this regard, Duke argues that the 
Commission itself acknowledged in the April 14 Order (establishing the 
new indicative market power screens) that if a supplier passes the 
pivotal supplier indicative screen, it would not be able to exercise 
generation market power. Thus, Duke concludes that the use of any other 
indicative screens would appear to be redundant and an unwarranted 
burden on market-based rate sellers.\33\ Further, Duke submits that 
neither of the rationales originally cited by the Commission in support 
of the market share screen--its ability to identify ``coordinating 
behavior,'' or its ability to detect the exercise of market power in 
off-peak periods--has been validated. In this regard, Duke submits that 
the potential for ``coordinating behavior'' should consider overall 
market concentration levels as measured by HHIs and in any event, such 
behavior is already subject to oversight and substantial penalties 
under the antitrust laws and the Commission's recently adopted rule 
prohibiting market manipulation. Further, Duke claims that the nearly 
universal failure rate of load-serving utilities under the market share 
indicative screen in their control areas underscores its limited value 
as an indicator of off-peak market power.\34\
---------------------------------------------------------------------------

    \33\ Duke reply comments at 15 and n. 21.
    \34\ Duke reply comments at 15 and n. 22.
---------------------------------------------------------------------------

    51. Duke states that a review of filings by vertically integrated 
utilities that are not RTO participants shows that the vast majority 
have failed the market share screen in their control areas, and most 
have subsequently been forced to adopt some form of cost-based 
mitigation for wholesale sales in that market. Yet Duke is unaware of 
any credible evidence suggesting that any form of generation market 
power has been exercised by these utilities. Instead, Duke states that 
the Commission has revoked market-based rate authority and imposed 
mitigation on the basis of indicative screen results that suggest the 
potential for market power.\35\ APPA/TAPS counter that the Commission 
should not limit its response to market power only to instances of its 
actual exercise; they note that the Commission considers whether a 
seller and its affiliates have market power or have mitigated it, not 
whether it has been exercised.\36\
---------------------------------------------------------------------------

    \35\ Duke at 16.
    \36\ APPA/TAPS reply comments at 6-7, citing Duke at 16.
---------------------------------------------------------------------------

    52. Another commenter suggests substituting the HHI for the market 
share indicative screen or supplementing the indicative screens with 
the HHI, reasoning that the market must be evaluated, not just the 
individual market share.\37\
---------------------------------------------------------------------------

    \37\ Drs. Broehm & Fox-Penner at 2-4.
---------------------------------------------------------------------------

    53. Southern states that the Commission should rely upon any 
indicative screens only in conjunction with an optional ``expedited 
track'' safe harbor review. Under Southern's proposal, the indicative 
screens would be voluntary and those submitting to and passing the 
screens would be permitted to retain or obtain market-based rate 
authority, subject to a proceeding under section 206 of the FPA, under 
which the party seeking to challenge the rate must submit substantial 
evidence justifying revocation. If a seller fails the screen(s), or if 
it elects to submit a DPT rather than voluntarily submit the indicative 
screens, then a robust market power assessment should be used to 
determine whether (or the extent to which) the

[[Page 39912]]

seller should be permitted to sell power at market-based rates.
    54. In Southern's view, failure of the indicative screens should 
not give rise to a presumption of market power.\38\ Southern argues 
that mere failure to pass a screen, without more robust market power 
assessments, is an insufficient basis upon which to base a presumption 
of market power. Southern argues this is because, in the case of the 
pivotal supplier screen, the Commission itself admits that it does not 
give a full picture and that the DPT provides better information. With 
regard to the market share screen, Southern argues that the market 
share screen has even more basic problems as an indicator of market 
power. Southern states that, because of the market share analysis' 
serious flaws, the great majority of integrated franchised public 
utilities inevitably will fail the market share screen. Thus, with 
respect to integrated franchised public utilities, the market share 
screen serves no real purpose other than to state the obvious: 
Integrated franchised public utilities build and maintain adequate 
resources to serve their native loads and inevitably will have market 
shares greater than 20 percent in their home control areas under the 
Commission's computational procedures. Southern states that, since the 
DPT reduces the level of false positives and is a more definitive means 
for determining the existence of market power, the Commission should 
use the DPT as the default test.\39\ PPL agrees with Southern's 
proposal that the indicative screens be made voluntary.\40\
---------------------------------------------------------------------------

    \38\ Southern argues that, in the context of the indicative 
screens, the prejudice associated with integrated franchised public 
utility status is severe and instead of providing a fair or 
meaningful measure of market power, the market share screen operates 
to create a priori evidentiary presumption of guilt, the screen is 
improper, creates due process concerns, and should not be adopted 
for purposes of the final rule.
    \39\ Southern at 8, 11-13.
    \40\ PPL reply comments at 8.
---------------------------------------------------------------------------

    55. Southern states that if the market share screen is retained, it 
should be adjusted for forced outages because such capacity is not 
available. Southern also notes that forced outages are tracked and 
reported to the North American Electric Reliability Corporation (NERC), 
which presents generating unit availability statistics data for 
generator unit groups.\41\
---------------------------------------------------------------------------

    \41\ Southern at 14-15.
---------------------------------------------------------------------------

    56. NRECA disagrees with Southern's proposal, stating that forced 
outage deductions have little effect when applied to all sellers.\42\ 
It also believes that sellers do not make forced outage deductions in 
long-term contracts; therefore, it is inappropriate to make the 
deduction for the market power tests.
---------------------------------------------------------------------------

    \42\ NRECA reply comments at 18.
---------------------------------------------------------------------------

    57. While EPSA does not agree with some of the Commission's 
proposed changes to the horizontal analysis in the NOPR (i.e., changes 
to the post-1996 exemption and the native load proxy), in general, EPSA 
supports the two indicative screens as a means for indicating that an 
entity might have market power.
    58. EPSA notes that it is time to move beyond the battle over 
crafting the perfect screens, arguing: (1) It is likely no such perfect 
screens exist, as evidenced by the fact that stakeholders and the 
Commission have gone through several iterations to get to today's 
screens; and (2) in the end, the screens are only indicative measures. 
EPSA notes that failure of one or both of the screens does not brandish 
an entity with market power, but merely raises a flag that further 
analysis is necessary in order to assess an entity's ability to 
exercise market power. The current state of wholesale electricity 
markets, EPSA argues, requires indicative screens that are neither 
definitive nor an aperture letting everything pass, but rather a sieve 
that catches potential problems for further examination. EPSA agrees 
with retention of both of the current indicative screens and the ``next 
steps'' set forth for those entities that fail one or both of those 
screens.
    59. Several other commenters also support retention of the 
indicative screens. Some of these commenters state that, because 
section 205 of the FPA requires rates to be just and reasonable, a 
market share indicative screen is appropriate to ensure that outcome. 
NRECA adds that ``[b]ecause of past or present State regulation, many 
traditional public utilities have acquired dominant market shares of 
generation capacity in their own control areas--sufficient to enable 
them to exercise market power absent regulation of their behavior. 
NRECA submits that regardless of the cause the incumbent public 
utilities will remain the dominant firms in their own control areas 
absent significant new market entry in the form of new generation 
construction in the control area by independent firms, or significant 
transmission construction to permit entry by generation outside the 
control area. Morgan Stanley also favors retaining the market share 
indicative screen, noting that failure of the market share indicative 
screen does not mean the process is unfair, and asserting that 
exclusive reliance on the pivotal supplier indicative screen may 
compromise market power detection.\43\
---------------------------------------------------------------------------

    \43\ Morgan Stanley reply comments at 10-11.
---------------------------------------------------------------------------

    60. With regard to the suggestion that the Commission adopt a 
contestable load analysis, several commenters criticize the contestable 
load analysis, stating that it changes the focus of the market power 
analysis from the seller to the market. They counter that the 
contestable load analysis is unsound, with APPA/TAPS citing Federal 
Trade Commission (FTC) comments in this proceeding that such an 
analysis is flawed.\44\ NRECA states that commenters have not provided 
sufficient justification for using a contestable load analysis.
---------------------------------------------------------------------------

    \44\ APPA/TAPS reply comments at 11, NRECA reply comments at 13-
14. The FTC filed comments in this proceeding in January 2006 on the 
contestable load test. FTC states that ``the historical contestable 
load proposal fails to include a number of potentially important 
considerations in its framework for assessing horizontal market 
power, and the elements that it does include are not considered in 
an economically sound manner. In sum, the proposal does not 
represent an analytical advance over existing techniques to evaluate 
horizontal market power, and it falls far short of the economically 
sound framework for market power analysis presented in the Merger 
Guidelines.'' The FTC defines the following specific problems with 
the contestable load analysis: the price is not considered in the 
assessment of available supply, contractual and legal restrictions 
on supply are ignored, and the contestable load analysis ignores 
transmission discrimination and transmission constraints, which 
delineate the market.
---------------------------------------------------------------------------

    61. With regard to Southern's suggestion that the indicative 
screens be made voluntary and function as a safe harbor, such that 
screen failure would simply mean that further review of the seller 
would be appropriate, but not merit a section 206 investigation, NRECA 
states that Southern's argument is contrary to law. NRECA argues that, 
as the proponent of a tariff allowing it to charge market-based rates, 
the public utility has the burden of proof to demonstrate that its 
wholesale rates will be disciplined by competition. NRECA submits that 
failing the indicative screens indicates that the seller has not yet 
provided `` `empirical proof' '' that competition will drive down 
prices to just and reasonable levels as the FPA requires.\45\
---------------------------------------------------------------------------

    \45\ NRECA reply comments at 20-21.
---------------------------------------------------------------------------

Commission Determination
    62. We adopt the proposal in the NOPR to retain both of the 
indicative screens. The intent of the indicative screens is to identify 
the sellers that raise no horizontal market power concerns and can 
otherwise be considered for market-based rate authority. At the same 
time, sellers that do not pass the indicative screens are allowed to 
provide additional analysis

[[Page 39913]]

for Commission consideration. Because the indicative screens are 
intended to screen out only those sellers that raise no horizontal 
market power concerns, as opposed to other sellers that raise concerns 
but may not necessarily possess horizontal market power, we find it 
appropriate to use conservative criteria and to rely on more than one 
screen. A conservative approach at the indicative screen stage of the 
proceeding is warranted because, if a seller passes both of the 
indicative screens, there is a rebuttable presumption that it does not 
possess horizontal market power.
    63. The rebuttable presumption of horizontal market power that 
attaches to sellers failing one of the indicative screens is just 
that--a rebuttable presumption. It is not a definitive finding by the 
Commission; sellers are provided with several procedural options 
including the right to challenge the market power presumption by 
submitting a DPT analysis, or, alternatively, sellers can accept the 
presumption of market power and adopt some form of cost-based 
mitigation.\46\ Accordingly, we will adopt the proposal to continue to 
use the two indicative screens and find that failure of either 
indicative screen creates a rebuttable presumption of market power. We 
reiterate our finding that ``[f]ailure to pass either of the indicative 
screens * * * will constitute a prima facie showing that the rates 
charged by the seller pursuant to its market-based rate authority may 
have become unjust and unreasonable and that continuation of the 
seller's market-based rate authority may no longer be just and 
reasonable.'' \47\
---------------------------------------------------------------------------

    \46\ In the April 14 Order, the Commission stated that proposals 
for alternative mitigation in these circumstances could include 
cost-based rates or other mitigation that the Commission may deem 
appropriate. For example, a seller could propose to transfer 
operational control of enough generation to a third party such that 
the applicant would satisfy our generation market power concerns. 
April 14 Order, 107 FERC ] 61,018 at n. 142.
    \47\ April 14 Order, 107 FERC ] 61,018 at P 209.
---------------------------------------------------------------------------

    64. This approach, contrary to the claims of several commenters, 
will help to further competitive markets by allowing sellers without 
market power to sell power at market-based rates, and it will similarly 
give customers security that sellers that fail the screens are required 
to submit to further scrutiny and/or mitigation.
    65. The pivotal supplier and market share indicative screens 
measure different aspects of market power. As the Commission stated in 
the April 14 Order, the uncommitted pivotal supplier indicative screen 
measures the ability of a firm to dominate the market at peak periods. 
The uncommitted market share analysis provides a measure as to whether 
a supplier may have a dominant position in the market, which is another 
indicator of potential unilateral market power and the ability of a 
seller to effect coordinated interaction with other sellers. The market 
share screen is also useful in measuring market power because it 
measures a seller's size relative to others in the market, in 
particular, the seller's share of generating capacity uncommitted after 
accounting for its obligations to serve native load. The market share 
screen provides a snapshot of these market shares in each season of the 
year. Taken together, the indicative screens can measure a seller's 
market power at both peak and off-peak times.\48\ Both market share and 
pivotal supplier indicative screens are appropriate first steps for the 
Commission to use in determining if it needs a more robust analysis to 
determine whether the seller has market power. We conclude that having 
two screens as backstops to one another will better assist us in 
determining the existence of potential market power. Accordingly, we 
reject the suggestion of several commenters to abandon the market share 
indicative screen. We will retain both the pivotal supplier and market 
share indicative screens as described in the NOPR, as well as apply the 
rebuttable presumption of market power for those sellers that fail 
either indicative screen.\49\
---------------------------------------------------------------------------

    \48\ April 14 Order, 107 FERC ] 61,018 at P 72.
    \49\ As we noted in the July 8 Order, a number of those 
commenters that proposed eliminating the market share screen had 
supported it as a viable alternative in the past. July 8 Order, 108 
FERC ] 61,026 at P 87.
---------------------------------------------------------------------------

    66. In addition, the Commission will not adopt suggestions to alter 
the indicative screens in order to incorporate a contestable load 
analysis, as proposed by EEI and others. As noted by the FTC, APPA/
TAPS, and NRECA, the contestable load analysis is flawed because, among 
other things, it does not consider control of generation through 
contracts. The Commission explained in the April 14 Order that the 
roles of the indicative screens are meant to be complementary. The 
pivotal supplier indicative screen indicates whether demand can be met 
without some contribution of supply by the seller at peak times, while 
the market share indicative screen indicates whether the seller has a 
dominant position in the market and may therefore have the ability to 
exercise horizontal market power, both unilaterally and in coordination 
with other sellers.\50\ The contestable load analysis is essentially a 
variant on the pivotal supplier screen with differences in the 
calculation of wholesale load and the test thresholds, because, like 
the pivotal supplier screen, it addresses whether suppliers other than 
the seller can meet the demand in the relevant market. Therefore 
incorporating such an analysis would not improve our ability to 
establish a presumption of whether a seller has market power. The 
contestable load analysis therefore would add little useful 
information, and without the market share indicative screen, the 
Commission would have insufficient information because there would be 
no analysis of a seller's size relative to the other sellers in the 
market, and no information on the seller's market power during off-peak 
periods.
---------------------------------------------------------------------------

    \50\ April 14 Order, 107 FERC ] 61,018 at P 72.
---------------------------------------------------------------------------

    67. In addition, the contestable load analysis fails to consider 
the relative price of the competing supplies. Commenters have argued 
that if available non-applicant supply is at least twice the 
contestable load, the market is competitive. However, this analysis 
fails to consider whether the available non-applicant supply is 
competitively priced and, thus, in the market. This weakness in the 
contestable load analysis is addressed in the DPT analysis which 
considers only supply that is competitively priced.
    68. We also reject arguments by E.ON U.S. and PNM/Tucson that the 
wholesale market share screen should be replaced because, they argue, 
it does not consider the size of the wholesale supply in the relevant 
market relative to the wholesale demand in that market. E.ON. U.S. and 
PNM/Tucson are requesting an analysis very similar to the contestable 
load analysis, whose defining characteristic is measuring the wholesale 
supply market relative to wholesale demand, which, as stated above, is 
essentially the same as the pivotal supplier screen, and would 
therefore add little useful information to the screening process.
    69. We reject Duke's claim that because neither of the rationales 
originally cited by the Commission in support of the market share 
indicative screen--its ability to identify ``coordinating behavior,'' 
or its ability to detect the exercise of market power in off-peak 
periods--has been validated, the wholesale market share indicative 
screen is unnecessary. Specifically, the Commission believes that the 
ability of market participants to exercise market power through 
``coordinating behavior'' is a legitimate concern under the FPA, in 
addition to the fact that it has long been recognized by the antitrust

[[Page 39914]]

authorities.\51\ The Commission also believes it is possible to 
exercise market power in off-peak periods because during such times the 
amount of supply in the market may be greatly reduced (e.g., because of 
planned outages for plant maintenance), meaning that a seller that is 
not dominant at peak times might be at off-peak.
---------------------------------------------------------------------------

    \51\ See 1992 FTC/DOJ 1992 Horizontal Merger Guidelines sec. 
2.1.
---------------------------------------------------------------------------

    70. Moreover, we agree with APPA/TAPS that market-based rate 
assessments are used to determine the ability to exercise, not the 
exercise of, market power. The Commission need not wait passively until 
market power is exercised. Rather, it is incumbent on the Commission to 
set policies that will ensure that rates remain just and reasonable 
under section 205 of the FPA. Requiring sellers to submit screens that 
analyze the sellers' potential to exercise market power is consistent 
with such a policy.
    71. We are unpersuaded by E.ON U.S.'s and PNM/Tucson's argument 
that ``false positives'' arising from the market share screen dampen 
the vigor of competitive wholesale market participation by 
unnecessarily curtailing the market-based rate authority of entities 
that, according to E. ON. U.S. and PNM/Tucson, lack market power. We 
recognize that a conservative screen may result in some false 
positives, but must weigh that against the cost of the false negatives 
that would occur if we adopted a less conservative screen or eliminated 
the market share indicative screen.
    72. E.ON U.S. and PNM/Tucson, to support their point, cite several 
court cases in which market shares were alleged not to be reliable 
indicators of market power in regulated markets. However, the cases 
cited are not relevant to the issue of whether the Commission should 
retain the wholesale market share screen. The purpose of our indicative 
screens is to distinguish sellers that may raise horizontal market 
power concerns and those that do not; the market share screen is not 
the end of our horizontal market power analysis. In contrast, the cases 
cited by E.ON U.S. and PNM/Tucson \52\ involve allegations of unlawful 
restraint of trade in violation of the Sherman Act,\53\ a Federal 
antitrust statute prohibiting trade monopolies. The focus in such cases 
(whether a company has violated the Sherman Act) and the standard for 
making such a determination is different than the focus of the 
Commission at the indicative screen stage of the horizontal market 
power analysis (identifying sellers that require further horizontal 
market analysis without making a definitive finding regarding market 
power).
---------------------------------------------------------------------------

    \52\ Cost Management, 99 F.3d 937; Rebel Oil, 51 F.3d 1421; S. 
Pac. Communications, 740 F.2d 780; MCI Communications, 708 F.2d 
1081; Mid-Tex Communications, 615 F.2d 1372; and Almeda, 615 F.2d 
343.
    \53\ 15 U.S.C. 2, which states: ``Every person who shall 
monopolize, or attempt to monopolize, or combine or conspire with 
any other person or persons, to monopolize any part of the trade or 
commerce among the several States, or with foreign nations, shall be 
deemed guilty of a felony, and, on conviction thereof, shall be 
punished by fine not exceeding $100,000,000 if a corporation, or, if 
any other person, $1,000,000, or by imprisonment not exceeding 10 
years, or by both said punishments, in the discretion of the 
court.''
---------------------------------------------------------------------------

    73. On both theoretical and practical grounds, we reject the 
argument by EEI and others that the market share indicative screen can 
diminish competition because some sellers that are the subject of a 
section 206 investigation choose mitigation rather than challenge the 
presumption of market power. First, mitigating a seller with market 
power ensures that the other sellers in the market cannot benefit from 
an artificially high market price due to the seller with market power 
exercising market power. Second, in our experience, sellers that choose 
mitigation rather than challenge the presumption of market power have 
market shares that are likely to indicate a dominant position in a 
geographic market.\54\ In addition, many sellers have successfully 
rebutted the presumption of market power after failing one of the 
indicative screens.\55\
---------------------------------------------------------------------------

    \54\ See, e.g., Aquila, Inc., 112 FERC ] 61,307 (2005); Carolina 
Power & Light Co., 113 FERC ] 61,130 (2005); The Empire District 
Electric Co., 116 FERC ] 61,150 (2006); MidAmerican Energy Co., 117 
FERC ] 61,178 (2006); Xcel Energy Services Inc., 117 FERC ] 61,180 
(2006).
    \55\ See, e.g., Kansas City Power and Light Co., 113 FERC ] 
61,074 (2005); PPL Montana, LLC, 115 FERC ] 61,204 (2006); 
PacifiCorp, 115 FERC ] 61,349 (2006); Tucson Electric Power Co., 116 
FERC ] 61,051 (2006); Acadia Power Partners, LLC, 113 FERC ] 61,073 
(2005).
---------------------------------------------------------------------------

    74. Further, we will not adopt the suggestion to substitute the HHI 
for the market share indicative screen or to supplement the indicative 
screens with the HHI. The indicative screens are used to separate 
sellers who are presumed to have market power from those that, absent 
extraordinary and transitory circumstances, clearly do not. We will not 
substitute the market share screen with an HHI screen because, as we 
have stated above, the seller's market share conveys useful information 
about its ability to exercise market power, so eliminating the market 
share screen in favor of the HHI could increase the risk of false 
negatives.\56\ In addition, a high HHI can be the result of high market 
shares of sellers in the market other than the seller, and the focus of 
our analysis is on the seller's ability to exercise market power, so 
the HHI would provide little additional information to allow us to 
identify those sellers who clearly do not have market power. Finally, 
the HHI primarily provides information on the ability of sellers to 
exercise market power through coordinated behavior, while the market 
share screen primarily provides information on a particular seller's 
ability unilaterally to exercise market power. We will not supplement 
the indicative screens with the HHI screen because the indicative 
screens are sufficiently conservative to identify those sellers that 
have a rebuttable presumption of market power, without having to add an 
additional layer of review at the initial stage.
---------------------------------------------------------------------------

    \56\ For example, in a market with one seller with a 35 percent 
market share and 13 sellers each with 5 percent market shares, the 
HHI would be 1,550 (1,225 + 13(25)), which would not fail the 2,500 
HHI threshold or even the proposed lower 1,800 HHI threshold. In 
such a market, a firm with a 35 percent market share could have the 
ability to exercise market power, which would not be picked up by an 
HHI screen.
---------------------------------------------------------------------------

    75. We clarify that sellers and intervenors may present alternative 
evidence such as a DPT study or historical sales and transmission data 
to support or rebut the results of the indicative screens. For example, 
intervenors could present evidence based on historical wholesale sales 
data or challenge the assumption that competing suppliers inside a 
balancing authority area have access to the market (such a challenge 
could take into account both the actual historical transmission usage 
at the time of the study as well as the amount of available 
transmission capacity at that time).\57\ A seller may present evidence 
in support of a contention that, notwithstanding the results of the 
indicative screens, it does not possess market power.\58\ However, 
sellers should not expect that the Commission will postpone initiating 
a section 206 investigation to protect customers while it examines this 
supplemental information if screen failures are indicated.\59\ 
Nevertheless, the Commission may factor in this alternative evidence 
before deciding whether to initiate a section 206 investigation if the 
alternative evidence is appropriately supported, comprehensive and 
unambiguous, and

[[Page 39915]]

conducive to prompt review by the Commission.
---------------------------------------------------------------------------

    \57\ Id. at P 37.
    \58\ Id. at n. 11.
    \59\ See, e.g., LG&E Energy Mtkg. Inc., 111 FERC ] 61,153 at P 
21, 22 (2005); Tampa Electric Co., 110 FERC ] 61,206 at P 24, 25 
(2005); Entergy Services, Inc., 109 FERC ] 61,282 at P 36 (2004).
---------------------------------------------------------------------------

    76. We will not adopt Southern's suggestion that the indicative 
screens be made voluntary. We will continue to require that sellers 
submit the indicative screens or concede the presumption of market 
power before they file a DPT. However, as discussed above, a seller may 
submit with its indicative screens a DPT as alternative evidence. As 
stated above, submission of a DPT analysis as alternative evidence at 
the same time a seller submits the indicative screens may result in the 
Commission instituting a section 206 proceeding to protect customers, 
based on failure of an indicative screen, while the Commission 
considers the merits of the DPT analysis.
    77. We do not agree with Southern's view that failure of the 
indicative screen(s) does not provide a sufficient basis to establish a 
rebuttable presumption of market power. The indicative screens are 
intended to identify the sellers that raise no horizontal market power 
concerns and can otherwise be considered for market-based rate 
authority. Sellers failing one or both of the indicative screens, on 
the other hand, are identified as sellers that potentially possess 
horizontal market power and for which a more robust analysis is 
required. The uncommitted pivotal supplier screen focuses on the 
ability to exercise market power unilaterally. Failure of this screen 
indicates that some or all of the seller's generation must run to meet 
peak load. The uncommitted market share analysis indicates whether a 
supplier has a dominant position in the market. Failure of the 
uncommitted market share screen may indicate the seller has unilateral 
market power and may also indicate the presence of the ability to 
facilitate coordinated interaction with other sellers. It is on this 
basis that we find that a rebuttable presumption of market power is 
warranted when a seller fails one or both of the indicative screens. 
However, we agree with Southern that the DPT is a more definitive means 
for determining the existence of market power. As a result, we allow 
sellers that have failed one or both of the indicative screens to rebut 
the presumption of market power by performing the DPT. Further, because 
failure of one or both of the indicative screens only creates a 
rebuttable presumption of market power and sellers have a Commission-
endorsed analysis that they can use to rebut that presumption (the 
DPT), we find without merit Southern's view that the indicative screens 
create a priori evidentiary presumption of guilt, are improper, and 
create due process concerns.
    78. With regard to Southern's suggestion that we use the DPT as the 
default test, we find that if we were to do so our ability to protect 
customers while the analysis is evaluated could be compromised. The DPT 
is a more involved and complex analysis. The Commission has also at 
times set a DPT analysis for evidentiary hearing which greatly extends 
the time between when the DPT is submitted to the Commission and when a 
final decision is rendered. The rates customers are subject to during 
the time period before the issuance of a Commission order addressing a 
seller's DPT would not be subject to refund and, accordingly, the 
customers would be unprotected if the seller ultimately is found to 
have market power. However, under our current policy, and as adopted 
herein, if a seller wishes to file a DPT rather than the indicative 
screens it may do so. In doing so, the seller concedes that it fails 
the indicative screens, which concession establishes a rebuttable 
presumption of market power, and the Commission will issue an order 
initiating a section 206 proceeding to investigate whether the seller 
has market power and establishing a refund effective date for the 
protection of customers while the Commission evaluates the filed DPT. 
In the case of a seller that concedes the failure of one or both of the 
screens and submits the DPT in the same filing, the Commission is able 
to establish a refund effective date at an earlier time than if the 
seller were able to skip the screen stage entirely and file a DPT 
without conceding a screen failure.
    79. We will reject Southern's request that forced outages be 
deducted from capacity. As we stated in the July 8 Order, ``forced 
outages are non-recurring events that do not reflect normal operating 
conditions.'' \60\ Allowing deduction of forced outages will generally 
not change indicative screen results, because all sellers will be able 
to deduct forced outages, offsetting each other. In the unlikely event 
that forced outage numbers were not completely offsetting, allowing 
forced outages in the indicative screens would benefit owners of 
relatively unreliable fleets at the expense of owners of relatively 
reliable fleets.
---------------------------------------------------------------------------

    \60\ July 8 Order, 108 FERC ] 61,026 at P 68.
---------------------------------------------------------------------------

2. Indicative Market Share Screen Threshold Levels and Pivotal Supplier 
Application Period
Commission Proposal
    80. In the NOPR, the Commission proposed to retain the 20 percent 
threshold for the wholesale market share screen (i.e., with a market 
share of less than 20 percent, the seller would pass the screen). The 
Commission stated that since the screens are indicative, not 
definitive, a relatively conservative threshold for passing them was 
appropriate. Indeed, pursuant to the horizontal market power analysis, 
the Commission will not make a definitive finding that a seller has 
market power unless and until the more robust analysis, the DPT, is 
considered.
    81. The Commission proposed to continue the use of annual peak load 
in the pivotal supplier analysis and not to expand the pivotal supplier 
analysis to include monthly assessments. It stated that the pivotal 
supplier analysis examines the seller's market power during the annual 
peak, and that the hours near that point in time are the most likely 
times that a seller will be a pivotal supplier.
a. Market Share Threshold
Comments
    82. A number of commenters argue that 20 percent is too low a 
threshold for the market share indicative screen. Some point out that, 
given native load requirements, it is very difficult for investor-owned 
utilities outside of RTOs/ISOs to fall below the 20 percent threshold 
for the market share indicative screen.\61\ Duke also notes that the 20 
percent criterion is incompatible with regional planning requirements 
because, according to Duke, the amount of capacity needed to satisfy 
regional planning reserve margins ``would place the utility at 
substantial risk of exceeding the 20 percent threshold.'' \62\
---------------------------------------------------------------------------

    \61\ See, e.g., Southern at 8-9, Duke at 15-16, EEI at 8-9.
    \62\ Duke at 17.
---------------------------------------------------------------------------

    83. E.ON U.S. argues that, because the courts have not considered a 
20 percent market share to indicate a market power concern, associating 
a market share indicative screen failure with a presumption of market 
power is inappropriate.\63\ Additionally, Progress

[[Page 39916]]

Energy argues that it is inappropriate to associate failure of the 
market share screen with a presumption of market power when U.S. 
Department of Justice (DOJ) merger guidelines state that only firms 
with 35 percent or more market share have market power.\64\
---------------------------------------------------------------------------

    \63\ See E.ON U.S. at 14-15, n.18, citing PepsiCo, Inc. v. Coca-
Cola Co., 315 F.3d 101, 109 (2d Cir. 2003) (``Absent additional 
evidence, such as an ability to control prices or exclude 
competition, a 64 percent market share is insufficient to infer 
monopoly power.''); AD/SAT v. Associated Press, 181 F.3d 216, 229 
(2d Cir. 1999) (concluding that 33 percent market share is 
insufficient to show a dangerous probability of monopoly power); 
United Air Lines, Inc. v. Austin Travel Corp., 867 F.2d 737, 742 (2d 
Cir. 1989) (finding that 31 percent market share does not constitute 
a national monopoly).
    \64\ Progress Energy at 7, citing EEI at 6-10.
---------------------------------------------------------------------------

    84. PPL states that it agrees that the 20 percent threshold should 
be replaced by a 35 percent threshold in the market share screen and 
argues that such an increase will avoid the false-positive failure rate 
of the indicative screens, and the cost, time and repercussions in the 
financial markets of the extended pendency of a market-based rate 
renewal proceeding while a DPT is conducted and considered.\65\
---------------------------------------------------------------------------

    \65\ PPL reply comments at 7.
---------------------------------------------------------------------------

    85. In reply, APPA/TAPS state that there is no reason to raise the 
market share indicative screen threshold above 20 percent simply 
because investor-owned utilities have trouble passing the market share 
indicative screen.\66\ NRECA and TDU Systems note that the factors that 
EEI believes make it difficult to pass the indicative screens--a large 
amount of reserves and little available transfer capability--are 
precisely the factors to consider when evaluating whether a market is 
competitive.\67\
---------------------------------------------------------------------------

    \66\ APPA/TAPS reply comments at 12.
    \67\ NRECA reply comments at 16, TDU Systems reply comments at 
10, citing EEI at 8.
---------------------------------------------------------------------------

    86. Rather than raising the threshold level, TDU Systems propose to 
lower the threshold to 15 percent for the market share indicative 
screen, claiming that 20 percent was never justified by the Commission 
or shown to be the right balance.\68\ Citing Commission and judicial 
precedent, TDU Systems also note that the grant of market-based rate 
authority cannot be made without the discipline of market forces.\69\
---------------------------------------------------------------------------

    \68\ TDU Systems at 7.
    \69\ TDU Systems at 5.
---------------------------------------------------------------------------

    87. These commenters cite a recent decision of the U.S. Court of 
Appeals for the Ninth Circuit \70\ to buttress their positions, arguing 
that even market shares lower than 20 percent can lead to market 
manipulation.
---------------------------------------------------------------------------

    \70\ Pub. Utils. Comm'n of Calif. v. FERC, 462 F.3d 1027, at 
1039 (9th Cir. 2006) (CPUC) (``As became clear in hindsight, even 
those who controlled a relatively small percentage of the market [in 
the California market during 2000 and 2001] had sufficient market 
power to skew markets artificially.'').
---------------------------------------------------------------------------

    88. In reply to these arguments, Duke states that certain 
commenters' reliance on this is mistaken because that decision 
addressed market manipulation, not market power.\71\ Duke asserts that 
virtually any supplier, regardless of its market share, has some 
ability to manipulate market outcomes by engaging in anomalous bidding 
practices.
---------------------------------------------------------------------------

    \71\ Duke reply comments at 18, citing CPUC.
---------------------------------------------------------------------------

Commission Determination
    89. The Commission will retain the 20 percent market share 
threshold for the indicative market share screen. EEI and others argue 
that the Commission should use a 35 percent threshold as a presumption 
of market power because the DOJ merger guidelines state that only firms 
with 35 percent or more market share have market power. As the 
Commission stated in the July 8 Order, however, in a market comprised 
of five equal-sized firms with 20 percent market shares, the HHI is 
2,000, which is above the DOJ/FTC HHI threshold of 1,800 for a highly 
concentrated market, and in markets for commodities with low demand 
price-responsiveness like electricity, market power is more likely to 
be present at lower market shares than in markets with high demand 
elasticity.\72\ Therefore, we will retain a conservative 20 percent 
threshold for this indicative screen.
---------------------------------------------------------------------------

    \72\ July 8 Order, 108 FERC ] 61,026 at P 96.
---------------------------------------------------------------------------

    90. When arguing that a 20 percent threshold for the market share 
screen is too low, E.ON. U.S. and PNM/Tucson ignore that the indicative 
screens are based on uncommitted capacity, not total capacity. When 
calculating uncommitted capacity for the market share screen, a seller 
deducts from its total capacity the capacity dedicated to long-term 
sales contracts, operating reserves,\73\ planned outages, and native 
load \74\ as measured by the appropriate native load proxy. As a 
result, a substantial amount of seller capacity may not be counted in 
measures of market share. Therefore, it is inappropriate to compare 
market shares based on uncommitted capacity to the market shares in the 
cases that E.ON. U.S. and PNM/Tucson cite.
---------------------------------------------------------------------------

    \73\ April 14 Order 107 FERC ] 61,018 at P 94.
    \74\ Id. at P 100.
---------------------------------------------------------------------------

    91. We further note that other commenters have argued that the 20 
percent threshold is too high. We disagree. The 20 percent threshold is 
meant to strike a balance between having a conservative but realistic 
screen and imposing undue regulatory burdens. The Commission's 
experience in the context of market-based rate proceedings demonstrates 
this point. In the three years since the April 14 Order, the Commission 
has revoked the market-based rate authority of two sellers, thirteen 
sellers relinquished their market-based rate authority, and six 
companies satisfied the Commission's concerns for the grant of market-
based rate authority at the DPT phase. In addition, intervenors have 
the opportunity to present other evidence such as historical data in 
order to rebut the presumption that sellers lack market power.\75\ 
Moreover, no commenter advocating a 15 percent threshold for the market 
share has shown why it is superior to the current 20 percent threshold. 
Therefore, we find that the 20 percent market share threshold strikes 
the right balance in seeking to avoid both ``false negatives'' and 
``false positives'' and we will not reduce the wholesale market share 
screen to 15 percent, as suggested by TDU Systems.
---------------------------------------------------------------------------

    \75\ Id. at P 97.
---------------------------------------------------------------------------

    92. The Commission does not accept Duke's assertion that the market 
share indicative screen is incompatible with regional planning 
requirements. The April 14 Order allows operating reserves necessary 
for reliability, as determined by State or regional reliability 
councils,\76\ to be deducted from total capacity attributed to the 
seller.
---------------------------------------------------------------------------

    \76\ April 14 Order, 107 FERC ] 61,018 at P 96.
---------------------------------------------------------------------------

    93. We also reject the argument that the 20 percent threshold is 
too low because of native load obligations of investor-owned utilities 
outside of RTOs. First, the calculation of 20 percent is the same 
regardless of whether a seller is located in an RTO or not. Second, as 
discussed herein, we allow for a native load deduction in the wholesale 
market share screen and are increasing the deduction to address 
concerns raised by investor-owned utilities and others. Given the 
increased native load deduction, our market share screen adequately 
incorporates investor-owned utilities' native load obligations while 
necessarily maintaining the conservative nature of the screens.
b. Pivotal Supplier Application Period
Comments
    94. Some commenters recommend that the pivotal supplier indicative 
screen should be applied monthly, rather than just in a seller's peak 
month. They reason that sellers, though not pivotal in the highest 
demand period, might be pivotal at different times of the year or in 
off-peak periods, such as in the spring or fall when power plants are 
on planned outages.\77\
---------------------------------------------------------------------------

    \77\ See, e.g. APPA/TAPS at 66-67, NRECA at 19-20.
---------------------------------------------------------------------------

Commission Determination
    95. The Commission will not require the pivotal supplier indicative 
screen to be applied monthly, as some commenters suggest, because we 
believe

[[Page 39917]]

it is unnecessary and overly burdensome to do so. Even though 
conditions of tight supply may occur at other times of the year or in 
abnormal operating conditions, the combination of the pivotal supplier 
analysis and the wholesale market share screen is sufficient, because 
suppliers with market power at such times are also likely to fail at 
least one of these screens. Moreover, if intervenors believe that a 
seller is pivotal during non-peak periods, they are permitted to file 
evidence to that effect. Accordingly, using only the peak month in the 
pivotal supplier indicative screen is appropriate. We note that if a 
seller fails the indicative screens and submits a DPT, it is required 
to provide a pivotal supplier analysis for each season and for both 
peak and non-peak hours.
3. DPT Criteria
Commission Proposal
    96. With regard to the DPT analysis, the Commission proposed to 
retain the current thresholds (20 percent for the market share analysis 
and 2,500 for the HHI analysis), as well as the current practice of 
weighing all the relevant factors presented in determining whether a 
seller does or does not have horizontal market power. The Commission 
proposed to continue to do so on a case-by-case basis, weighing such 
factors as available economic capacity, economic capacity, market 
share, HHIs, and historical sales and transmission data.\78\
---------------------------------------------------------------------------

    \78\ Economic capacity means the amount of generating capacity 
owned or controlled by a potential supplier with variable costs low 
enough that energy from such capacity could be economically 
delivered to the destination market. Available economic capacity 
means the amount of generating capacity meeting the definition of 
economic capacity less the amount of generating capacity needed to 
serve the potential supplier's native load commitments. See 
generally April 14 Order, 107 FERC ] 61,018 at Appendix F.
---------------------------------------------------------------------------

Comments
    97. Several commenters suggest changes to the DPT criteria. One 
suggested change is to emphasize \79\ or rely exclusively \80\ on the 
available economic capacity measure, in order to properly account for 
native load. For example, one commenter argues that the economic 
capacity prong of the DPT analysis is not a useful indicator of the 
presence or absence of market power when applied to vertically 
integrated utilities in their home control areas because that analysis 
completely disregards native load obligations, making this prong 
virtually unpassable by such utilities. This commenter also notes that 
even using the available economic capacity measure, a seller with a 
market share above 35 percent would fail the DPT ``even though there is 
no real market power problem because the in-area wholesale customers 
have access to ample supplies of competitively priced power.'' \81\ In 
this regard, he argues that the DPT should be changed to take into 
account ``competitive alternatives available for wholesale customers.'' 
\82\
---------------------------------------------------------------------------

    \79\ Dr. Pace at 9.
    \80\ Southern at 20-21, EEI at 15.
    \81\ Dr. Pace at 11-12.
    \82\ Dr. Pace at 12-13.
---------------------------------------------------------------------------

    98. Several other commenters disagree with the 2,500 HHI threshold 
for the DPT. Some reason that a 2,500 HHI threshold is not well 
justified and that an 1,800 HHI threshold is more appropriate because 
this is the criterion used in a highly concentrated market. They argue 
that if a 2,500 HHI threshold is used, it should be used with a 15 
percent market share because these are the criteria of the oil-pipeline 
test from which the HHI 2,500 criterion is obtained.\83\ State AGs and 
Advocates note that the Commission has never systematically attempted 
to correlate the results of the pivotal supplier indicative screen, the 
market share indicative screen, or the DPT (including HHI results) 
proposed in the NOPR with actual independently derived data and 
measures as to the existence of market power in any wholesale 
electricity market in the U.S.\84\ Without having done this type of 
systematic and quantitative evaluation of the proposed market power 
tests based on some type of independent verification, State AGs and 
Advocates contend that the Commission cannot be confident that the 
three proposed tests are reasonably accurate and, therefore, useful 
tests to determine the existence of market power in any electricity 
market. For example, State AGs and Advocates ask how the Commission 
knows if an HHI corresponds to the point at which market power begins, 
and whether it varies by factors such as input price, generation mix 
and different market structures through the country.\85\
---------------------------------------------------------------------------

    \83\ APPA/TAPS at 78-79, TDU Systems at 18, Montana Counsel at 
15 (referring to APPA/TAPS comments).
    \84\ State AGs and Advocates state that by ``independently'' 
derived measures of market power they mean measures derived using 
different methodologies (and more accurate methodologies) than the 
Commission proposed in the NOPR.
    \85\ States AGs and Advocates at 36-37.
---------------------------------------------------------------------------

    99. Furthermore, State AGs and Advocates claim that the DPT is not 
an adequate tool for assessing market power ``in any context.'' First, 
they state that the DPT will not discern bidding strategies of 
different suppliers. In addition, they assert that a DPT does not 
consider the differences between fundamentally different types of 
market structures: short-term energy only markets, short-term capacity 
markets, ancillary service markets, and long-term contract markets for 
energy and capacity.\86\
---------------------------------------------------------------------------

    \86\ State AGs and Advocates reply comments at 6-7.
---------------------------------------------------------------------------

    100. A number of commenters believe that the HHI threshold 
sufficient for passage of the DPT should remain at 2,500.\87\ PPL 
states that lowering the HHI threshold to 1,800 will cause more false 
positives and direct capital away from the generation sector.
---------------------------------------------------------------------------

    \87\ MidAmerican reply comments at 2, citing EEI comments; PPL 
reply comments at 8; EEI reply comments at 23.
---------------------------------------------------------------------------

    101. EEI and Progress Energy recommend that only the pivotal 
supplier and HHI analyses of the DPT should be retained, particularly 
if the market share analysis under the indicative screens is retained. 
They argue that the pivotal supplier and HHI analyses are more than 
sufficient to determine whether the potential for market power 
exists.\88\
---------------------------------------------------------------------------

    \88\ EEI at 10-12, Progress at 8.
---------------------------------------------------------------------------

    102. A few commenters are skeptical about the need for a DPT. 
Southern states that ``granting market-based rates should not require 
the same analysis as for a merger,'' and that the Commission should 
reconsider using the DPT.\89\ In this regard, Southern argues that 
unlike mergers, which are difficult and costly to undo, the Commission 
has the ability to continuously police the exercise of market power. 
Further, Southern states that the Energy Policy Act of 2005 provides 
for stiff civil and criminal penalties. Southern adds that the 
Commission recently issued new rules against market manipulation to 
thwart exercises of market power.
---------------------------------------------------------------------------

    \89\ Southern at 19-20.
---------------------------------------------------------------------------

    103. AARP expresses concern about the lack of competition in 
wholesale electric markets. It argues that market-based rate reviews 
are intended to determine whether the seller's market-based rates will 
be just and reasonable, not whether a seller passes the various tests. 
AARP argues that real-world evidence that may not fit neatly within the 
specified market-based rate criteria must be considered before the 
Commission can conclude that a seller lacks market power. AARP states 
that, as the NOPR recognizes (PP 63-64), both historical and forward-
looking evidence should be considered.
Commission Determination
    104. The Commission will continue to use the DPT for companies that 
fail the

[[Page 39918]]

market power indicative screens. The DPT is a well-established test 
that has been used routinely by the Commission to analyze market power 
in the merger context. The fact that it is used in section 203 cases 
does not demonstrate that it is inappropriate for market-based rate 
cases. Rather, it provides a well-established tool for assessing market 
power that is known and widely used in the electric industry. Moreover, 
in both contexts, the DPT allows for the calculation of market shares 
and market concentration values under a wide range of season and load 
conditions.
    105. Sellers failing one or more of the initial screens will have a 
rebuttable presumption of market power. If such a seller chooses not to 
proceed directly to mitigation, it must present a more thorough 
analysis using the DPT. The DPT is also used to analyze the effect on 
competition for transfers of jurisdictional facilities in section 203 
proceedings,\90\ using the framework described in Appendix A of the 
Merger Policy Statement and revised in Order No. 642.\91\
---------------------------------------------------------------------------

    \90\ 16 U.S.C. 824b (2000).
    \91\ Inquiry Concerning the Commission's Merger Policy Under the 
Federal Power Act: Policy Statement, Order No. 592, 61 FR 68,595 
(1996), FERC Stats. & Regs., Regulations Preambles July 1996-
December 2000 ] 31,044 (1996), reconsideration denied, Order No. 
592-A, 62 FR 33,341 (1997), 79 FERC ] 61,321 (1997) (Merger Policy 
Statement); see also Revised Filing Requirements Under Part 33 of 
the Commission's Regulations, Order No. 642, 65 FR 70,983 (2000), 
FERC Stats. & Regs., Regulations Preambles July 1996-December 2000 ] 
31,111 (2000), order on reh'g, Order No. 642-A, 66 FR 16,121 (2001), 
94 FERC ] 61,289 (2001).
---------------------------------------------------------------------------

    106. The DPT defines the relevant market by identifying potential 
suppliers based on market prices, input costs, and transmission 
availability, and calculates each supplier's economic capacity and 
available economic capacity for each season/load condition.\92\ The 
results of the DPT can be used for pivotal supplier, market share and 
market concentration analyses.
---------------------------------------------------------------------------

    \92\ Super-peak, peak, and off-peak, for Winter, Shoulder and 
Summer periods and an additional highest super-peak for the Summer.
---------------------------------------------------------------------------

    107. Using the economic capacity for each supplier, sellers should 
provide pivotal supplier, market share and market concentration 
analyses. Examining these three factors with the more robust output 
from the DPT will allow sellers to present a more complete view of the 
competitive conditions and their positions in the relevant markets.
    108. Under the DPT, to determine whether a seller is a pivotal 
supplier in each of the season/load conditions, sellers should compare 
the load in the destination market to the amount of competing supply 
(the sum of the economic capacities of the competing suppliers). The 
seller will be considered pivotal if the sum of the competing 
suppliers' economic capacity is less than the load level (plus a 
reserve requirement that is no higher than State and Regional 
Reliability Council operating requirements for reliability) for the 
relevant period. The analysis should also be performed using available 
economic capacity to account for sellers' and competing suppliers' 
native load commitments. In that case, native load in the relevant 
market would be subtracted from the load in each season/load period. 
The native load subtracted should be the average of the native load 
daily peaks for each season/load condition.
    109. Each supplier's market share is calculated based on economic 
capacity. The market shares for each season/load condition reflect the 
costs of the sellers' and competing suppliers' generation, thus giving 
a more complete picture of the sellers' ability to exercise market 
power in a given market. For example, in off-peak periods, the 
competitive price may be very low because the demand can be met using 
low-cost capacity. In that case, a high-cost peaking plant that would 
not be a viable competitor in the market would not be considered in the 
market share calculations, because it would not be counted as economic 
capacity in the DPT. Sellers must also present an analysis using 
available economic capacity and explain which measure more accurately 
captures conditions in the relevant market.
    110. Under the DPT, sellers must also calculate the market 
concentration using the HHI based on market shares.\93\ HHIs have been 
used in the context of assessing the impact of a merger or acquisition 
on competition. However, as noted by the U.S. Department of Justice in 
the context of designing an analysis for granting market-based pricing 
for oil pipelines, concentration measures can also be informative in 
assessing whether a supplier has market power in the relevant market. 
``The Department and the Commission staff have previously advocated an 
HHI threshold of 2,500, and it would be reasonable for the Commission 
to consider concentration in the relevant market below this level as 
sufficient to create a rebuttable presumption that a pipeline does not 
possess market power.'' \94\
---------------------------------------------------------------------------

    \93\ The HHI is the sum of the squared market shares. For 
example, in a market with five equal size firms, each would have a 
20 percent market share. For that market, HHI = (20) \2\ + (20) \2\ 
+ (20) \2\ + (20) \2\ + (20) \2\ = 400 + 400 + 400 + 400 + 400 = 
2,000.
    \94\ See Comments of the United States Department of Justice in 
response to Notice of Inquiry Regarding Market-Based Ratemaking for 
Oil Pipelines, Docket No. RM94-1-000 (January 18, 1994).
---------------------------------------------------------------------------

    111. A showing of an HHI less than 2,500 in the relevant market for 
all season/load conditions for sellers that have also shown that they 
are not pivotal and do not possess a 20 percent or greater market share 
in any of the season/load conditions would constitute a showing of a 
lack of market power, absent compelling contrary evidence from 
intervenors. Concentration statistics can indicate the likelihood of 
coordinated interaction in a market. All else being equal, the higher 
the HHI, the more firms can extract excess profits from the market. 
Likewise a low HHI can indicate a lower likelihood of coordinated 
interaction among suppliers and could be used to support a claim of a 
lack of market power by a seller that is pivotal or does have a 20 
percent or greater market share in some or all season/load conditions. 
For example, a seller with a market share of 20 percent or greater 
could argue that that it would be unlikely to possess market power in 
an unconcentrated market (HHI less than 1,000). As with our initial 
screens, sellers and intervenors may present evidence such as 
historical wholesale sales. Those data could be used to calculate 
market shares and market concentration and could be used to refute or 
support the results of the DPT. The Commission encourages the most 
complete analysis of competitive conditions in the market as the data 
allow.
    112. We will continue to weigh both available economic capacity and 
economic capacity when analyzing market shares and HHIs. Based on our 
substantial experience in applying the DPT over the past decade, we 
have found that both analyses are useful indicators of suppliers' 
potential to exercise market power, and we are unwilling to rely solely 
on one measure or the other.\95\ For example, in markets where 
utilities retain significant native load obligations, an analysis of 
available economic capacity may more accurately assess an individual 
seller's competitiveness, as well as the overall competitiveness of a 
market, because available economic capacity recognizes the native load 
obligations of the sellers. On the other hand, in markets where the

[[Page 39919]]

sellers have been predominantly relieved of their native load 
obligations, an analysis of economic capacity may more accurately 
reflect market conditions and a seller's relative size in the market.
---------------------------------------------------------------------------

    \95\ See, e.g., Tampa Electric Company, 117 FERC ] 61,311 
(2006); PacifiCorp, 115 FERC ] 61,349 (2005); Tucson Electric Power 
Company, 116 FERC ] 61,051(2006); Duke Power, a Division of Duke 
Energy Corporation, 111 FERC ] 61,506 (2005); and Kansas City Power 
and Light Company, 113 FERC ] 61,074 (2005).
---------------------------------------------------------------------------

    113. Likewise, we find the HHI market concentration measure to be 
useful in assessing the market power of individual sellers, and it 
complements the market share and pivotal supplier measures in the DPT 
stage of the analysis. Furthermore, no commenter has presented a 
compelling argument for why the Commission should lower or raise the 
HHI threshold in the DPT. Accordingly, we will retain 2,500 as the 
appropriate threshold for passing this part of the DPT for the reasons 
we stated in the April 14 Order.\96\ We will not adopt the suggestion 
to lower the market share threshold to 15 percent from 20 percent, for 
the reasons set forth above, in the NOPR and July 8 Order.\97\ 
Commenters have presented no compelling reason to do so, and in our 
experience since the April 14 Order, we have not seen cases where the 
HHI was over 2,500 and the seller's market share was between 15 and 20 
percent, which would be the type of situation about which APPA/TAPS and 
others are concerned. Accordingly, such a reform would not likely 
result in additional findings of market power.
---------------------------------------------------------------------------

    \96\ April 14 Order, 107 FERC ] 61,018 at P 111 (explaining that 
at less than 2,500 HHI in the relevant market for all season/load 
conditions there is little likelihood of coordinated interaction 
among suppliers in a market).
    \97\ July 8 Order at P 95-97 and NOPR at P 41.
---------------------------------------------------------------------------

    114. State AGs and Advocates claim that the DPT is not an adequate 
tool for assessing market power because it will not discern bidding 
strategies of different suppliers. However, State AGs and Advocates 
miss the point of the analysis: by determining whether a seller has 
capacity that can compete in the market under various season and load 
conditions, the DPT provides an accurate picture of market conditions. 
Examining market conditions allows the Commission to determine whether 
a seller has market power. The DPT does this by examining short-term 
energy markets and, in particular, sellers' available generation 
capacity. In addition, absent entry barriers, and a specific finding of 
market power, the Commission has said that long-term markets are 
competitive. With regard to ancillary services, as discussed herein, 
the Commission requires market power analyses for those services to 
support a request for market-based rate authority. Assessing competing 
suppliers' bidding strategies, ex ante, would not illuminate the state 
of the market and the ability of sellers to alter prices within it.
    115. We also reject Southern's argument that the DPT analysis is 
unnecessary because of the Commission's enhanced civil penalty 
authority and continuing policing of sellers with market-based rate 
authorization. While those are critical components of our program to 
ensure just and reasonable market-based rates, they are not a 
substitute for an analysis of the potential market power of sellers 
seeking market-based rate authority. In addition, Southern's argument 
that rules against market manipulation will thwart all exercises of 
market power is speculative.
    116. We will not change the DPT to take into account competitive 
alternatives available for wholesale customers as proposed by a 
commenter. We stated above our reasons for rejecting use of a 
contestable load analysis in the indicative screens, and we reject it 
for the DPT for the same reasons.
    117. AARP and State AGs and Advocates argue that the Commission 
should consider evidence from actual market data in determining whether 
market power exists rather than rely on the results of the DPT to 
determine whether a seller has market power. We agree that actual 
market data is an important part of a determination of whether a seller 
may have market power. In this regard, we look at actual market data, 
both in the initial analysis and in ongoing monitoring of the EQR data. 
As the Commission stated in the April 14 Order, ``[a]s with our initial 
screens, applicants and intervenors may present evidence such as 
historical wholesale sales. Those data could be used to calculate 
market shares and market concentration and could be used to refute or 
support the results of the Delivered Price Test.'' \98\ In addition, as 
part of our ongoing monitoring activities, we examine the EQR data in 
an effort to identify whether market prices may indicate an exercise of 
market power.
---------------------------------------------------------------------------

    \98\ April 14 Order, 107 FERC ] 61,018 at P 112.
---------------------------------------------------------------------------

4. Other Products and Models
Comments
    118. ELCON expresses concern over the entire horizontal market 
power analysis process: indicative screens, followed by DPT or 
mitigation for those that fail the indicative screens. ELCON notes that 
the evolution of these practices generally occurred in a series of 
highly contested proceedings, and did not benefit from the broader and 
more balanced review afforded by a generic rulemaking. ELCON states 
that its concern is that the practices unduly shift the burden of proof 
to potential victims of market power abuse. This concern would only be 
academic, ELCON continues, if the market structures were truly 
competitive and there were strong structural protections against the 
exercise of market power. But the hybrid nature of most regional 
markets, combined with inadequate infrastructure, creates an 
environment that discourages trust in market outcomes.\99\
---------------------------------------------------------------------------

    \99\ ELCON at 4-5.
---------------------------------------------------------------------------

    119. Some commenters urge the Commission to allow different product 
definitions, e.g., short-term power and long-term power, in the 
calculation of the indicative screens and the DPT. For example, NRECA 
argues that the Final Rule must require sellers to identify the 
relevant product markets, including the distinct products for which 
they seek market-based rate authority, and demonstrate that they lack 
market power in those product markets.\100\ The Montana Counsel argues 
that the Commission's screens and DPT analysis models measure market 
power during certain test days for current time periods,\101\ and that 
capacity that is available to make short-term energy sales may not be 
available for long-term, firm power sales. Thus, the Montana Counsel 
asserts that the Commission may not rely exclusively on short-term or 
spot markets to measure whether there are competitive long-term 
markets.
---------------------------------------------------------------------------

    \100\ NRECA at 16-18.
    \101\ Montana Counsel at 5-8.
---------------------------------------------------------------------------

    120. Other commenters remain divided over whether long-term power 
markets should be included in the market power analysis. PPL urges that 
long-term markets should not be considered in a market power analysis 
because of infeasibility and also because it violates the Commission's 
precedent that there is no long-term market power unless there exist 
barriers to entry.\102\ In contrast, NRECA and TDU Systems state that 
long-term markets need to be analyzed in the market power analysis 
because monopolies will probably persist into the future for many 
consumers \103\ and these consumers need protection. TDU Systems 
suggest using an installed capacity indicative screen for long-term 
markets.\104\
---------------------------------------------------------------------------

    \102\ PPL reply comments at 2-3 and n.6, citing Exelon Corp., 
112 FERC ] 61,011 at P 136 (2005).
    \103\ NRECA reply comments at 11, TDU Systems reply comments at 
5-7.
    \104\ TDU Systems reply comments at 9.
---------------------------------------------------------------------------

    121. State AGs and Advocates and NASUCA suggest that the Commission 
adopt behavioral modeling, such as

[[Page 39920]]

game theory, rather than structural analysis, because the latter cannot 
capture market power behavior.\105\ NASUCA suggests that the Commission 
hold a technical conference to consider behavioral modeling. Duke 
disagrees with NASUCA's and others' calls for behavioral models, 
contending that they are theoretically complex and data-intensive and 
do not meet the prerequisite of being simple, easily understood and 
readily verifiable by the Commission.
---------------------------------------------------------------------------

    \105\ State AGs and Advocates at 29-30, NASUCA at 14-15.
---------------------------------------------------------------------------

Commission Determination
    122. We will not generically alter the indicative screens or the 
DPT to allow different product analyses for short-term or long-term 
power as some commenters suggest. As the Commission has stated in the 
past, absent entry barriers, long-term capacity markets are inherently 
competitive because new market entrants can build alternative 
generating supply. There is no reason to generically require that the 
horizontal analysis consider those products that are affected by entry 
barriers. Instead, we will consider intervenors' arguments in this 
regard on a case-by-case basis.
    123. We reject ELCON's contentions regarding the development of our 
horizontal market power analysis. While the screens and DPT criteria 
did arise out of specific cases, there have been numerous opportunities 
in this rulemaking for interested parties to express any concerns and 
propose alternatives, including technical conferences and numerous 
rounds of written comments. We believe that this rulemaking has given 
all interested parties ample opportunity to voice any and all options 
for revising the screens and DPT criteria and proposing alternatives, 
and has given us the opportunity to evaluate whether these tools remain 
appropriate. We conclude that they do.
    124. Finally, we will not adopt the suggestion by some commenters 
that behavioral modeling be used in addition to, or in place of, the 
indicative screens and the DPT. Although game theory has been used in 
laboratory experiments and in theoretical studies where the number of 
players and choices available to players are limited, we do not 
consider it a practical approach for the volume of analyses we must 
perform, particularly since a vast amount of choices are available and 
many of those are unobservable. The data gathering and analysis burden 
imposed on sellers and the Commission would be overly burdensome and 
impractical.
5. Native Load Deduction
a. Market Share Indicative Screen
Commission Proposal
    125. To reduce the number of ``false positives'' in the wholesale 
market share indicative screen, the Commission proposed in the NOPR to 
adjust the native load proxy for this screen. The Commission proposed 
to change the allowance for the native load deduction under the market 
share indicative screen from the minimum native load peak demand for 
the season to the average native load peak demand for the season. This 
change makes the deduction for the market share indicative screen 
consistent with the deduction allowed under the pivotal supplier 
indicative screen.
Comments
    126. TDU Systems argue that the Commission provides no empirical 
evidence supporting this change--i.e., no evidence of an excessive 
number of false positives produced by the Commission's current policy. 
TDU Systems also state that the Commission does not explain why it 
believes its current proxy ``results in too much uncommitted capacity 
attributable to the seller.'' \106\ In particular, TDU Systems state 
that the Commission does not explain what factors it used to determine 
the appropriate level of uncommitted capacity to which it compared the 
current proxy.
---------------------------------------------------------------------------

    \106\ TDU Systems at 13.
---------------------------------------------------------------------------

    127. APPA/TAPS agree, adding that the Commission proposal appears 
to be a results-driven effort to eliminate the need for some public 
utilities to submit a DPT.\107\ APPA/TAPS argue that the Commission's 
``false positives'' justification loses sight of the stakes involved in 
the market-based rate determination. They state that the price of a 
false positive associated with the initial screens will be the seller's 
submission of the DPT. APPA/TAPS argue that that price pales in 
comparison to the unreasonably high prices and market power exercise 
that can result from a false negative. According to APPA/TAPS, it is 
thus entirely appropriate for the Commission to take a closer look when 
a utility fails the initial screens, even when the Commission 
ultimately allows market-based rate authorization.\108\
---------------------------------------------------------------------------

    \107\ APPA/TAPS at 68, citing Acadia Power Partners LLC, 111 
F.E.R.C. ] 61,239 (2005), and Kansas City Power & Light Co., 111 
FERC ] 61,395 (2005), where the applying utilities failed the market 
share screen, but passed the pivotal supplier screen. In both cases, 
the company opted to submit a DPT, and after consideration, the 
Commission allowed the utilities to retain their market-based rate 
authority. Acadia Power Partners, LLC, 113 FERC ] 61,073 (2005); 
Kansas City Power & Light Co., 113 FERC ] 61,074 (2005).
    \108\ APPA/TAPS at 68-70.
---------------------------------------------------------------------------

    128. In addition, APPA/TAPS state that, as well as lacking 
evidentiary basis, the proposed adjustment is not based on sound 
economic principles. APPA/TAPS argue that when the Commission 
originally adopted the native load proxy for the market share screen, 
it said the screen should reflect ``all of the capacity that is 
available to compete in wholesale markets at some point during the 
season.'' \109\ APPA/TAPS state that now the Commission proposes to 
eliminate even more of the capacity that is available to compete at 
some point in the season by increasing the proxy to the average native 
load peak demand for the season.
---------------------------------------------------------------------------

    \109\ APPA/TAPS at 69, citing April 14 Order, 107 FERC ] 61,018 
at P 92.
---------------------------------------------------------------------------

    129. APPA/TAPS further argue that adoption of the Commission's 
proposal would mean that the market-based rate screens would make no 
assessment of off-peak periods, even though the Commission has said 
that the market share screen is intended to measure market power during 
off-peak times.\110\ They state that ``screens should examine market 
power for the on-peak and off-peak periods of the different seasons.'' 
\111\
---------------------------------------------------------------------------

    \110\ April 14 Order, 107 FERC ] 61,018 at P 72.
    \111\ APPA/TAPS at 70, citing Kirsch SMA Affidavit at 8-9.
---------------------------------------------------------------------------

    130. Finally, APPA/TAPS argue that consistency across the two 
screens defeats the purpose of having more than one screen. The market 
share screen is intended to reflect capacity that could compete, 
including during off-peak periods. By contrast, the pivotal supplier 
screen is specifically intended to measure market power risks at system 
peak.
    131. APPA/TAPS offer that if the Commission nonetheless believes 
some consistency is desired it can achieve it by using a native load 
proxy for the market share screen based upon the average minimum loads. 
Such a proxy would be consistent with the Commission's original intent 
of a screen that identifies ``all of the capacity that is available to 
compete in wholesale markets at some point during the season.'' \112\
---------------------------------------------------------------------------

    \112\ April 14 Order, 107 FERC ] 61,018 at P 92.
---------------------------------------------------------------------------

    132. Other commenters generally support the Commission's proposal 
to use seasonal average native load as the native load proxy for the 
market share indicative screen. Many state that the proposed native 
load proxy is a more accurate representation of native load 
obligations.\113\ Several commenters

[[Page 39921]]

suggest excluding weekends and holidays from the proxy native load 
calculation because these periods are not representative of normal load 
hours.\114\
---------------------------------------------------------------------------

    \113\ See, e.g., Ameren at 3, FirstEnergy at 4-5.
    \114\ See, e.g., EEI at 17, PG&E at 6-7, Allegheny at 7-8, and 
Pinnacle at 34, both citing Pinnacle West Capital Corp., 109 FERC ] 
61,295 (2004). Several commenters disagree with the suggestion that 
weekends and holidays should be excluded from the native load proxy, 
stating that it is unsupported and, moreover, excluding these hours 
means that native load proxy ceases to be average. TDU Systems reply 
comments at 8-9, NRECA reply comments at 16-17.
---------------------------------------------------------------------------

    133. EEI argues that even with this proposed change, the generation 
capacity required by a utility to serve its native load is still being 
understated.\115\ It states that utilities are required to meet the 
peak demands of their native load customers plus maintain a reserve 
margin for reliability purposes. This requirement directly determines 
the amount of generation capacity that a supplier can commit to the 
wholesale opportunity sales market. As such, EEI argues that the change 
proposed in the NOPR is a step in the right direction in terms of more 
accurately recognizing the amount of generation capacity required by a 
utility to meet native load requirements, but still understates the 
actual requirements.
---------------------------------------------------------------------------

    \115\ EEI at 24-25; see also Puget reply comments at 2.
---------------------------------------------------------------------------

    134. EEI contends that from a generation planning perspective, no 
one with any expertise in that area doubts the native load proxy 
described in the April 14 Order underestimates the amount of capacity 
that a supplier needs to meet native load requirements and therein both 
overstates the amount of capacity that the supplier has to compete in 
the wholesale market as well as the supplier's market share. As a 
result of this overestimation of the capacity that a supplier would 
have to compete in the wholesale market, EEI contends that non-RTO 
vertically integrated utilities have failed the market share screen 
using the current native load proxy when many simply do not have market 
power.\116\ EEI concludes that such a high number of ``e positives'' 
for market power that have occurred using the current proxy clearly 
supports the Commission's proposal to move the native load proxy to the 
average peak load in the season.
---------------------------------------------------------------------------

    \116\ EEI reply comments at 24.
---------------------------------------------------------------------------

Commission Determination
    135. We adopt the NOPR proposal to change the native load proxy 
under the market share indicative screen from the minimum native load 
peak demand for the season to the average of the daily native load peak 
demands for the season, making the native load proxy for the market 
share indicative screen consistent with the native load proxy under the 
pivotal supplier indicative screen.
    136. In this regard, we find that the market share screen should be 
calculated using as accurate a representation of market conditions for 
each season studied as possible. We find that using the current native 
load proxy using the minimum native load level for the season does not 
provide an accurate picture of the conditions throughout the season.
    137. We recognize that increasing the native load proxy will have 
the effect of reducing the market share for traditional utilities with 
significant native load obligations, and therefore may result in fewer 
failures of the wholesale market share screen for some sellers. 
However, we believe that such a result is justified. We are seeking a 
screen that provides a reasonably accurate picture of a seller's 
position given market conditions across seasons, so that we can 
eliminate those sellers who clearly do not have market power and focus 
our analysis on those who might. We believe that a native load proxy 
based on the average of peak load conditions is more representative, 
and thus more accurate, than a proxy based on extreme (i.e., minimum) 
peak load conditions. We also believe that basing the native load proxy 
on the average of the peaks will make the screens more accurate in 
eliminating sellers without market power while focusing on ones that 
may have market power.
    138. For sellers that contend that the proposed native load proxy 
will result in too many false positives, we note that under the 
existing native load proxy, fewer than 25 companies have been the 
subject of section 206 investigations since the April 14 Order. For 
entities that fear this change in native load proxy will lead to too 
many ``false negatives,'' (companies with market power passing under 
the indicative screens), we note that intervenors can always challenge 
the presumption of no market power. Moreover, no intervenor in this 
proceeding has pointed to specific companies that have passed the 
screens but still have market power.
    139. We reject APPA/TAPS' argument that changing the native load 
proxy would result in the market-based rate screens making no 
assessment of off-peak periods. In fact, the native load proxy we 
approve here is based on the average of the native load daily peaks 
which also include low load days. The use of the average peak demand 
for the native load proxy provides for an assessment of all periods, 
peak and off-peak seasons, because such a proxy considers peak native 
load of each day in each season. Combined with the pivotal supplier 
screen that captures the annual peak conditions, we find that the two 
screens adequately capture market conditions over the year.
    140. We also reject APPA/TAPS' argument that consistency across the 
two screens defeats the purpose of having more than one screen. The 
screens in and of themselves are inherently different methodologies in 
that the pivotal supplier screen considers whether the seller's 
generation must run to meet peak load, whereas the market share screen 
looks at the seller's size relative to other sellers in the market. We 
are looking for an assessment of the uncommitted seasonal capacity 
available to sellers to compete in wholesale markets and, as stated 
above, find that the average of the daily peak loads in a season more 
accurately reflects seller's commitments.
    141. APPA/TAPS suggest that if we do raise the native load 
deduction, we only raise it to the average minimum for the season, 
rather than the average native load peak demand for the season. The 
intent of the wholesale market share screen is to assess market 
conditions during the season, not only during off-peak hours. APPA/TAPS 
is misplaced in its assertion that our original intent was for the 
market share screen to focus solely on off-peak conditions. In the 
April 14 Order we stated that ``by using the two screens together, the 
Commission is able to measure market power both at peak and off-peak 
times.'' \117\ Our statement simply recognizes that a seller with a 
dominant position in the market could have market power in the off-peak 
as well as the peak. Clearly the pivotal supplier analysis is designed 
to assess market power at peak times, but that does not imply that the 
wholesale market share screen is designed only to assess market power 
in the off-peak period.
---------------------------------------------------------------------------

    \117\ April 14 Order at P 72.
---------------------------------------------------------------------------

    142. Finally, we will not exclude weekends and holidays from the 
market share native load proxy. Since we adopt herein the use of an 
average peak demand for the native load proxy for the market share 
screen, the exclusion of weekends and holidays would inappropriately 
skew the results. Use of an average load addresses the issue of the 
variability between unusually high or low load days, is more objective, 
and easily applied. If weekends and holidays are excluded, only 
approximately 70 percent of total load hours would be accounted for. 
The

[[Page 39922]]

average native load measure that includes weekends and holidays, and 
which we adopt, is truly an average of all load conditions.
b. Pivotal Supplier Indicative Screen
Commission Proposal
    143. In the NOPR, the Commission proposed to retain the pivotal 
supplier screen's native load proxy at its current level of the average 
of the daily native load peaks during the month in which the annual 
peak day load occurs.\118\
---------------------------------------------------------------------------

    \118\ NOPR at P 44.
---------------------------------------------------------------------------

Comments
    144. Southern states that the pivotal supplier screen is 
conceptually sound; however, the manner of its current implementation 
reflects a significant flaw. In particular, Southern claims that the 
wholesale load (market size) is determined by the difference between 
the control area's needle peak demand and the average of the daily 
peaks in that peak month. Southern argues that it is not at all clear 
how or why this mathematical exercise (which in its opinion reflects an 
``apples and oranges'' comparison) provides any meaningful measure of 
competitive wholesale demand during any relevant period.
    145. For example, Southern continues, under some circumstances, all 
or a large portion of the wholesale load determined in this fashion 
could be the seller's own native load. Subtracting the average daily 
peaks in the peak month from a single needle peak to derive a ``proxy'' 
for competitive wholesale demand necessarily assumes that all of this 
difference is unsatisfied wholesale market demand that is subject to 
competition. Southern argues that this is not a valid assumption and 
the Commission has provided no reason to believe that it is. Southern 
therefore urges the Commission to abandon this aspect of the interim 
pivotal supplier analysis and instead use an estimate of actual 
wholesale load, rather than deriving it indirectly through an 
arithmetic exercise. For example, the seller's native load peak could 
be subtracted from the control area peak load on an ``apples to 
apples'' basis (for example, needle peaks, seasonal peaks, or average 
daily peaks) to derive, in Southern's view, a much better wholesale 
load proxy.\119\ Southern asserts that such a reform would be 
relatively easy to implement and would yield much more meaningful 
results.\120\
---------------------------------------------------------------------------

    \119\ Southern notes that this suggested calculation would still 
overstate the amount of wholesale load open to competition because 
some portion of that wholesale load would undoubtedly be covered 
with existing supply arrangements. It states that if it were 
required to net out the amount of wholesale load covered by those 
existing supply arrangements, a similar amount should be subtracted 
from the market resources deemed to be competing to serve the net 
wholesale load.
    \120\ Southern at 18-19.
---------------------------------------------------------------------------

    146. NRECA disagrees with Southern's proposed modification to the 
pivotal supplier screen to use actual wholesale load, stating Southern 
provides no evidence that this modification would provide a more 
accurate estimate of the wholesale load than the current approach.\121\
---------------------------------------------------------------------------

    \121\ NRECA reply comments at 19-20.
---------------------------------------------------------------------------

Commission Determination
    147. We retain the average daily peak native load as the native 
load proxy used in the pivotal supplier screen, as proposed in the 
NOPR, and we reject Southern's argument that our method of computing 
the native load proxy is unreasonable. Southern argues that because the 
wholesale demand is determined by subtracting the average daily peaks 
in the peak month from a single needle peak, the Commission is relying 
on an invalid assumption with regard to the wholesale demand during any 
relevant period. However, Southern's claim that our deduction of the 
average of the daily native load peaks from the needle peak is a 
``mixing of apples and oranges'' ignores our reasoning in the April 14 
Order:

conditions in peak periods can provide significant opportunity to 
exercise market power. As capacity is utilized to meet demand there 
is less available to sell on the margin and often less competition. 
Only focusing on needle peaks that occur for a single hour and that 
are only known after the fact does not give an accurate reflection 
of the competitive dynamics of peak periods. As demand increases 
during peak periods, buyers and sellers are positioning themselves 
in the market with similar but incomplete information. Buyers are 
projecting their needs and trying to secure needed power, while 
sellers are negotiating to obtain the highest price for that power. 
With increasing demand, fewer units are available to serve 
anticipated peak needs and buyers bid to secure dwindling supply 
load increases. In addition, buyers must be prepared for the 
contingency that a unit will be forced out and they will need to 
purchase in a period of even greater scarcity.[\122\]
---------------------------------------------------------------------------

    \122\ April 14 Order, 107 FERC ] 61,018 at P 91.

    148. Further, both native load proxies provide an adequate solution 
to a complicated issue. Resources used to serve native load fluctuate 
over the course of the day and through the seasons. As the Commission 
stated in the April 14 Order, ``we recognize that not all generation is 
available all of the time to compete in wholesale markets and that some 
accounting for native load requirements is warranted here. However, 
wholesale and retail markets are not so easily separated such that a 
clear distinction can be made between generation serving native load 
and generation competing for wholesale load. Most utility generation 
units are not exclusively devoted to serving native load, or selling in 
wholesale markets.'' \123\
---------------------------------------------------------------------------

    \123\ Id. at P 67.
---------------------------------------------------------------------------

    149. For these reasons we continue to believe that the average of 
the native load peaks in the peak month is a reasonable proxy for the 
native load deductions under this screen. Moreover, we also find that 
Southern's proposed method of estimating the actual wholesale load is 
inappropriate because it would artificially reduce the seller's share 
of that load. This is because Southern's methodology only deducts the 
seller's native load peak from the control area peak (not the native 
load peaks of any other sellers in the control area), leaving the 
seller with a disproportionately small share of the remaining market.
c. Clarification of Definition of Native Load
Commission Proposal
    150. In the NOPR, the Commission expressed its belief that there 
has been some inconsistency in the way in which sellers have reflected 
native load in performing both the screens and the DPT analysis. 
Because the states are under various degrees of retail restructuring, 
the definition of native load customers has lacked precision. 
Accordingly, the Commission proposed to clarify that, for the 
horizontal market power analysis, native load can only include load 
attributable to native load customers as defined in Sec.  33.3(d)(4)(i) 
of the Commission's regulations,\124\ as it may be revised from time to 
time.
---------------------------------------------------------------------------

    \124\ 18 CFR 33.3(d)(4)(i) provides: Native load commitments are 
commitments to serve wholesale and retail power customers on whose 
behalf the potential supplier, by statute, franchise, regulatory 
requirement, or contract, has undertaken an obligation to construct 
and operate its system to meet their reliable electricity needs.
---------------------------------------------------------------------------

Comments
    151. APPA/TAPS support the native load clarification, without 
providing additional explanation. A number of other commenters 
discussed the native load clarification in the context of defining 
retail contracts or provider of last resort (POLR) load as native load. 
PPL Companies request that this clarification not be adopted unless the 
Commission provides further clarification that an entity selling power 
to a retail customer under a long-term

[[Page 39923]]

contract is able to deduct that capacity.\125\
---------------------------------------------------------------------------

    \125\ PPL Companies at 14-17.
---------------------------------------------------------------------------

Commission Determination
    152. We will adopt the NOPR proposal that, for the horizontal 
market power analysis, native load can only include load attributable 
to native load customers as defined in Sec.  33.3(d)(4)(i) of our 
regulations. We address the comments of PPL Companies' and others below 
in the ``Other Native Load Concerns'' section.
d. Other Native Load Concerns
Comments
    153. Some commenters suggest alterations to the definition of 
native load or to the circumstances when contract capacity may be 
deducted from total capacity. One commenter recommends that POLR load 
be counted as native load.\126\ Sempra argues that generators should be 
allowed to take native load deductions for power supplied to franchised 
utilities that divested their generation.\127\ It argues that allowing 
such suppliers to claim native load deductions correctly assigns these 
obligations to the entities that actually commit the generation 
resources necessary to serve native load and results in a more accurate 
assessment of the suppliers' remaining uncommitted capacity. It notes 
that such sales may be for terms of less than one year, and that under 
the Commission's policy such suppliers cannot deduct those commitments 
as long-term firm sales. Sempra further points out that franchised 
utilities do not need a one-year or greater commitment to take a native 
load deduction. It concludes that marketers and other suppliers should 
thus be allowed to account for the native load commitments they 
undertake, regardless of the term of each underlying contract.\128\
---------------------------------------------------------------------------

    \126\ Drs. Broehm and Fox-Penner at 11-12.
    \127\ Sempra reply comments at 4-5.
    \128\ PSEG Companies in their reply comments also make similar 
arguments about native load that are noted above in the ``Control 
and Commitment of Generation'' section.
---------------------------------------------------------------------------

Commission Determination
    154. We will not adopt suggestions that sellers receive native load 
deductions for all their POLR contracts or for all contracts that serve 
utilities that have divested their generation. Even in cases where 
independent power producers (IPPs) serve what used to be franchised 
public utilities' native load, IPPs do not serve it under the same 
terms as those utilities.\129\ Unlike franchised public utilities, IPPs 
may choose to exit the market once the contracts they sell power under 
have expired. However, we remind IPPs that POLR contracts with a term 
of one year or more may be deducted from total capacity under some 
circumstances. As the Commission explained in the July 8 Order, 
``applicants may deduct `load following' and `provider of last resort' 
contracts for terms of one year or more under certain conditions. 
Specifically, we will allow sellers to deduct long-term firm load 
following contracts to the extent that the seller has included in its 
total capacity a corresponding generating unit or long-term firm 
purchase contract that will be used to meet the obligation. The 
seller's contractual peak load obligation under the contract should be 
used as the capacity adjustment in the pivotal supplier analysis and 
the seasonal baseline demand levels served under the contract should be 
used as the adjustments in the market share analysis. The residual 
capacity will be considered available for sales in the wholesale spot 
markets and treated as uncommitted capacity.'' \130\ Also, in response 
to PPL Companies, we note that long-term (one year or more) firm 
contracts that cede control may always be deducted from total capacity.
---------------------------------------------------------------------------

    \129\ See 18 CFR 33.3(d)(4)(i) for the definition of native 
load.
    \130\ See July 8 Order, 108 FERC ] 61,026 at P 66.
---------------------------------------------------------------------------

    155. We will allow IPPs to deduct short term native load 
obligations if they can show that the power sold to the utility was 
used to meet native load. We agree with Sempra that allowing such 
suppliers to claim native load deductions correctly assigns these 
obligations to the entities that actually commit the generation 
resources necessary to serve native load and results in a more accurate 
assessment of the suppliers' remaining uncommitted capacity, and that 
such sales may be for terms of less than one year. Under our current 
policy such suppliers cannot deduct those commitments as long-term firm 
sales, whereas franchised utilities do not need a one-year or greater 
commitment to take a native load deduction.
6. Control and Commitment
Commission Proposal
    156. The Commission noted in the NOPR that uncommitted capacity is 
determined by adding the total capacity of generation owned or 
controlled through contract and firm purchases less, among other 
things, long-term firm requirements sales that are specifically tied to 
generation owned or controlled by the seller and that assign 
operational control of such capacity to the buyer.\131\ The Commission 
further stated that long-term firm load following contracts may be 
deducted to the extent that the seller has included in its total 
capacity a corresponding generating unit or long-term firm purchase 
that will be used to meet the obligation even if such contracts are not 
tied to a specific generating unit and do not convey operational 
control of the generation.\132\
---------------------------------------------------------------------------

    \131\ NOPR at P 46.
    \132\ Id.
---------------------------------------------------------------------------

    157. Noting that contracts can confer the same rights of control of 
generation or transmission facilities as ownership of those facilities, 
the Commission stated that if a seller has control over certain 
capacity such that the seller can affect the ability of the capacity to 
reach the relevant market, then that capacity should be attributed to 
the seller when performing the generation market power screens. The 
capacity associated with contracts that confer operational control of a 
given facility to an entity other than the owner must be assigned to 
the entity exercising control over that facility, rather than to the 
entity that is the legal owner of the facility.\133\
---------------------------------------------------------------------------

    \133\ Reporting Requirement for Changes in Status for Public 
Utilities with Market-Based Rate Authority, Order No. 652, 70 F. R. 
8253 (Feb. 18, 2005), FERC Stats. & Regs., Regulations Preambles 
2001-2005 ] 31,175 at P 47, order on reh'g, Order No. 652-A, 111 
FERC ] 61,413 (2005).
---------------------------------------------------------------------------

    158. In the NOPR, the Commission stated that in recent years some 
owners have outsourced to third parties pursuant to energy management 
agreements the day-to-day activities of running and dispatching their 
generating plants and/or selling output. The Commission noted that the 
agreement may, directly or indirectly, transfer control of the 
capacity. The Commission expressed concern that under such third-party 
agreements, there may be instances where control of capacity has 
changed hands, but this capacity has not been attributed to the correct 
seller for the purposes of the generation market power screens.\134\
---------------------------------------------------------------------------

    \134\ NOPR at P 48.
---------------------------------------------------------------------------

    159. In cases examining whether an entity is a public utility, the 
Commission has examined the totality of the circumstances in evaluating 
whether the entity effectively has control over capacity that it 
manages.\135\ Likewise, in providing guidance regarding events that 
trigger a requirement to submit a notice of change in status, the 
Commission has

[[Page 39924]]

indicated that, to determine whether control has been acquired, sellers 
should examine whether they can affect the ability of capacity to reach 
the relevant market.
---------------------------------------------------------------------------

    \135\ D.E. Shaw Plasma Power, L.L.C., 102 FERC ] 61,265 at P 33-
36 (2003) (D.E. Shaw); R.W. Beck Plant Management, Ltd., 109 FERC ] 
61,315 at P 15 (2004) (Beck).
---------------------------------------------------------------------------

    160. The Commission asked in the NOPR whether, in the interest of 
providing greater certainty and clarity regarding the determination of 
control, it should make generic findings or create generic presumptions 
regarding what constitutes control. In particular, the Commission 
sought comment on whether any of the following functions should merit a 
finding or presumption of control and, if so, on what basis: directing 
plant outages, fuel procurement, plant operations, energy and capacity 
sales, and/or credit and liquidity decisions.\136\
---------------------------------------------------------------------------

    \136\ NOPR at P 49.
---------------------------------------------------------------------------

    161. Alternatively, rather than focusing on these discrete 
functions, the Commission asked if it should establish a presumption of 
control for any entity that has some discretion over the output of the 
plant(s) that it manages. The Commission asked whether such an approach 
would promote greater certainty. The Commission also asked, if it 
adopted such a presumption, how it should address instances where 
discretion over plant output may be shared between more than one 
party.\137\
---------------------------------------------------------------------------

    \137\ Id.
---------------------------------------------------------------------------

    162. The Commission proposed to clarify that, in the event it 
adopted any such presumptions, an individual seller could rebut the 
presumption of control on the basis of its particular facts and 
circumstances. In addition, the Commission proposed to clarify that an 
entity that controls generation from which jurisdictional power sales 
are made is required to have a rate on file with the Commission. If the 
rate authority sought is market-based rate authority, then that entity 
is subject to the same conditions and requirements as any other like 
seller.\138\
---------------------------------------------------------------------------

    \138\ Id. at P 50.
---------------------------------------------------------------------------

    163. The intent of the Commission's proposals was to provide 
greater certainty and clarity as to the treatment of capacity that is 
subject to energy management agreements and outsourcing of functions so 
that the capacity is properly reported (and studied) and to make clear 
that any entity to which control is attributed must receive the 
necessary authorizations under the FPA in order to provide 
jurisdictional services.\139\
---------------------------------------------------------------------------

    \139\ Id.
---------------------------------------------------------------------------

a. Presumption of Control
    164. As an initial matter, most commenters support the Commission's 
desire to provide greater clarity and certainty regarding the 
determination of control.\140\ In this regard, many commenters express 
concerns that attributing generation capacity to sellers that do not 
necessarily control that generation may result in the seller falsely 
appearing to have market power and ultimately result in unnecessary 
mitigation. Commenters also express the need for the determination of 
control to be consistent for both the market-based rate authorizations 
and the change in status filings.
---------------------------------------------------------------------------

    \140\ See, e.g., Constellation at 18; EEI reply comments at 25; 
Financial Companies at 4; FirstEnergy at 5; Pinnacle at 4; Powerex 
at 7; SCE at 2.
---------------------------------------------------------------------------

    165. However, most commenters also oppose the Commission's proposal 
to establish generic findings or generic presumptions regarding what 
constitutes control, arguing that such findings must be made on a case-
by-case basis. Others suggest a rebuttable presumption that control 
lies with the owner unless specific facts indicate otherwise.
i. Fact Specific Determinations
Comments
    166. Various commenters argue for a fact specific determination of 
control.\141\ For example, Alliance Power Marketing, a supplier of 
energy management services, argues that a case-by-case approach 
provides increased certainty for generators and asset managers who 
relied upon Commission precedent in developing their current 
arrangements.\142\
---------------------------------------------------------------------------

    \141\ See, e.g., Constellation at 18; Duke at 24; EPSA at 38; 
PPL at 9 and reply comments at 11; APPA/TAPS at 76.
    \142\ Alliance Power Marketing reply comments at 7.
---------------------------------------------------------------------------

    167. Several commenters state that they have some sympathy with the 
Commission's desire to provide certainty and clarity in this area, 
however, they do not agree that there should be generic presumptions 
regarding the indicia of control. One commenter argues that details of 
each contract vary, depending upon parties and circumstances involved 
as well as on conditions in the market place, and therefore it must be 
reviewed and evaluated with care.\143\ This commenter suggests that an 
individual seller should be obligated to submit its contracts to the 
Commission for review, and allowed to present its case on the basis of 
its particular facts and circumstances.
---------------------------------------------------------------------------

    \143\ Drs. Broehm and Fox-Penner at 6-7.
---------------------------------------------------------------------------

    168. Similarly, APPA/TAPS believe that the Commission is correct to 
assign capacity to a seller for purposes of running the screens/DPT; 
however, they point out that generic findings or presumptions would be 
helpful only if the particulars of a contract aligned with the factual 
assumptions underlying a presumption. Otherwise, they state that a 
presumption could produce wrong results.\144\ APPA/TAPS suggest that 
any arrangement that could create opportunities for sellers to 
coordinate their behavior with other competitors should be reported and 
that as part of the seller's assigning control over long-term contracts 
for purposes of the screens/DPT, the Commission should require a seller 
to submit the relevant contracts with the market-based rate application 
or triennial update and identify the contractual provisions that 
support the seller's control determinations.\145\ APPA/TAPS suggest 
that marketing alliances or joint operating agreements can affect a 
seller's market position and should be considered in the determination 
of control.\146\
---------------------------------------------------------------------------

    \144\ APPA/TAPS at 76.
    \145\ Id. APPA/TAPS further note that confidentiality concerns 
can be addressed with appropriate protective orders.
    \146\ APPA/TAPS at 77 and 89.
---------------------------------------------------------------------------

    169. Powerex argues that clarity is particularly important as the 
new market manipulation rule makes it unlawful ``to omit to state a 
material fact necessary in order to make the statements made, in the 
light of the circumstances under which they were made, not 
misleading.'' \147\ In this regard, Powerex urges the development of a 
single principle or set of principles that need to be met to establish 
control over an asset. Powerex argues that the development of such 
principles will help take the guesswork out of compliance and provide 
greater certainty for the market, as compared to a laundry list of 
possible contract types. Powerex states that the control principle 
should focus on physical output as opposed to financial terms, since it 
is physical output that addresses the Commission's physical withholding 
concerns and relates to the agency's market screens.\148\
---------------------------------------------------------------------------

    \147\ Powerex at 7 (quoting 18 CFR 1c.2(a)(2)).
    \148\ Powerex at 8.
---------------------------------------------------------------------------

    170. EEI, EPSA, and Reliant argue that the Commission should 
continue to look at the totality of circumstances and attach the 
presumption of control when an entity can affect the ability of 
capacity to reach the market.\149\
---------------------------------------------------------------------------

    \149\ See, e.g., EEI at 19; EPSA at 37-38; Reliant at 5-6; SoCal 
Edison at 9.
---------------------------------------------------------------------------

    171. NYISO states that based on its experience in the 
administration of bid-based markets, what matters in the control of a 
plant is the ability to determine or significantly influence (a)

[[Page 39925]]

The levels of the bids from the plant, and (b) the level of output from 
the plant. Accordingly, the Commission should focus directly on these 
critical facts, rather than creating presumptions based on indirect 
indicia of an ability to control these key competitive parameters. 
NYISO claims that plant engineering or technical operations may be 
outsourced without conferring an ability to control price or output, so 
that the outsourcing is not of particular competitive significance. If, 
however, an entity could determine or significantly influence bids or 
output, then it would be reasonable for the Commission to place a 
burden on that entity to demonstrate that it is not in a position to 
benefit from a possible exercise of market power. NYISO claims that if 
more than one party is in a position to exercise control over bids or 
output, then both such parties should have the burden of rebutting this 
presumption. NASUCA concurs.\150\ Because of the fact-specific nature 
of these issues, the NYISO endorses the Commission's proposal to allow 
individual sellers to rebut the presumption on the basis of their 
particular facts and circumstances.\151\
---------------------------------------------------------------------------

    \150\ NASUCA reply comments at 15 (quoting NYISO at 6).
    \151\ NYISO at 5-6.
---------------------------------------------------------------------------

    172. Westar argues determinations of control over generating plants 
are essential elements of the negotiated risk sharing arrangement in 
virtually every energy management contract and that the Commission 
should not change its precedent absent clear evidence of market 
uncertainty or a finding that the established guidelines are 
inappropriate.\152\
---------------------------------------------------------------------------

    \152\ See, e.g., Westar at 27-28.
---------------------------------------------------------------------------

    173. Southern suggests that the approach taken in Order No. 652, 
where the Commission provided an illustrative list of contracts and 
arrangements that involve changes of control, is reasonable.\153\
---------------------------------------------------------------------------

    \153\ Southern at 23 (citing Order No. 652, FERC Stats. & Regs. 
Regulations Preambles 2001-2005 ] 31,175 at P 83.
---------------------------------------------------------------------------

Commission Determination
    174. As discussed in the sections that follow, the Commission 
concludes that the determination of control is appropriately based on a 
review of the totality of circumstances on a fact-specific basis. No 
single factor or factors necessarily results in control. The electric 
industry remains a dynamic, developing industry, and no bright-line 
standard will encompass all relevant factors and possibilities that may 
occur now or in the future. If a seller has control over certain 
capacity such that the seller can affect the ability of the capacity to 
reach the relevant market, then that capacity should be attributed to 
the seller when performing the generation market power screens.\154\
---------------------------------------------------------------------------

    \154\ NOPR at P 47-48 (citing July 8 Order, 108 FERC ] 61,026 at 
P 65.)
---------------------------------------------------------------------------

    175. Though we note the widespread support among commenters for the 
Commission's effort to provide greater clarity and certainty regarding 
the determination of control, there are differing points of view as to 
what circumstances or combination of circumstances convey control. 
These circumstances vary depending on the attributes of the contract, 
the market and the market participants. Thus, we conclude that it would 
be inappropriate to make a generic finding or generic presumption of 
control, but rather that it is appropriate to continue making our 
determinations of control on a fact-specific basis.
    176. We agree with commenters such as Powerex and Westar that the 
Commission should rely on a set of principles or guidelines to 
determine what constitutes control. This has been our historical 
approach and we find no compelling reason to modify our approach at 
this time. Accordingly, as suggested by EEI, EPSA and others, we will 
consider the totality of circumstances and attach the presumption of 
control when an entity can affect the ability of capacity to reach the 
market. Our guiding principle is that an entity controls the facilities 
when it controls the decision-making over sales of electric energy, 
including discretion as to how and when power generated by these 
facilities will be sold.\155\
---------------------------------------------------------------------------

    \155\ Order No. 652, FERC Stats. & Regs. Regulations Preambles 
2001-2005 ] 31,175 at P 18.
---------------------------------------------------------------------------

    177. With regard to suggestions that we require all relevant 
contracts to be filed for review and determination by the Commission as 
to which entity controls a particular asset (e.g., with an initial 
application, updated market power analysis, or change in status 
filing), we will not adopt this suggestion. Under section 205 of the 
FPA, the Commission may require any contracts that affect or relate to 
jurisdictional rates or services to be filed. However, the Commission 
uses a rule of reason with respect to the scope of contracts that must 
be filed and does not require as a matter of routine that all such 
contracts be submitted to the Commission for review. Our historical 
practice has been to place on the filing party the burden of 
determining which entity controls an asset. As discussed below, we will 
require a seller to make an affirmative statement as to whether a 
contractual arrangement transfers control and to identify the party or 
parties it believes controls the generation facility. Nevertheless, the 
Commission retains the right at the Commission's discretion to request 
the seller to submit a copy of the underlying agreement(s) and any 
relevant supporting documentation.
ii. Rebuttable Presumption Regarding Ownership
Comments
    178. MidAmerican argues that the Commission should adopt a 
presumption of control based on physical ownership of the generation 
(as adjusted for long-term sales or purchase power agreements). 
MidAmerican states that it is physical ownership that typically 
determines which entity controls the output of the generation and 
determines its ability to reach relevant markets. While many entities 
may have partial control over a unit's output, it is the owner that is 
most likely to affect market power.\156\
---------------------------------------------------------------------------

    \156\ MidAmerican at 4 and 6-7.
---------------------------------------------------------------------------

    179. Morgan Stanley states that as a general rule, when assessing 
market power, the Commission should specifically adopt a rebuttable 
presumption that the entity that owns \157\ the generation asset 
controls the generation capacity.\158\ This presumption would shift if 
the asset owner relinquishes to a third-party the final decision-making 
authority over whether a unit runs (i.e., if the third-

[[Page 39926]]

party can trump the asset owner's dispatch instruction, then the third-
party has control over whether the capacity reaches the market). Morgan 
Stanley states that such final decision-making authority would include 
authority to schedule outages.\159\
---------------------------------------------------------------------------

    \157\ Morgan Stanley states that consistent with Commission 
precedent, the generation owner would not include entities that have 
a ``passive'' ownership interest where, due to the nature of the 
interest, the interest holder does not have the right or ability to 
direct, manage, or control the day-to-day operations of 
jurisdictional facilities. Citing D.E. Shaw, 102 FERC ] 61,265, at 
61,823 (2003) (noting that passive owners may possess certain 
consent or veto rights over fundamental business decisions in order 
to preserve their financial investment, including, but not limited 
to, the right to grant or withhold consent regarding: (1) Material 
amendments to an LLC agreement under certain, specified 
circumstances; (2) issuance of new interests senior to the then-
existing member interests in an LLC entity; (3) adoption of a new 
LLC agreement (or other operative or constituent documents) in 
connection with mergers, consolidations, combinations, or 
conversions in certain instances; (4) appointment of a liquidator 
(but only if the managing member of the LLC does not appoint one); 
and (5) assignment of investment advisory contracts under certain 
circumstances); GridFlorida LLC, 94 FERC ] 61,363, at 62,332 (2001).
    \158\ Morgan Stanley would define final control over physical 
output as resting with the market participant that, under normal 
operating conditions, can override all other entities on the 
decision of whether to dispatch the generation unit or that can 
otherwise hold an entity accountable for a dispatch decision. It 
submits that such authority typically rests with the generation 
owner. Morgan Stanley at 4.
    \159\ See also Financial Companies at 6.
---------------------------------------------------------------------------

    180. FirstEnergy proposes that where a generation owner is a public 
utility under Part II of the FPA, the Commission should adopt a 
rebuttable presumption that such owner controls all of the generating 
capacity that it owns.\160\ FirstEnergy asserts that even where another 
entity is responsible for day-to-day operation of a generating unit, 
the generation owner generally will retain managerial discretion over 
the operation of the unit and over the sale of power from that unit 
into the market.\161\
---------------------------------------------------------------------------

    \160\ FirstEnergy similarly argues that there should be a 
rebuttable presumption that generation capacity purchased by an 
electric utility from a Qualified Facility (``QF'') as a result of a 
mandatory power purchase requirement established pursuant to the 
Public Utility Regulatory Policies Act (PURPA), 16 U.S.C. 824a-3(a), 
will be attributed to the seller rather than the purchaser. 
FirstEnergy argues that in many cases, the purchaser has little, if 
any, discretion over the dispatch of such units or the price at 
which energy is purchased.
    \161\ In its reply comments, PPL disagrees stating that, in 
assessing the entity that should be deemed to control capacity, 
whether assessing a contract to sell capacity or an asset management 
contract, the Commission should ask which party can benefit from an 
exercise of market power with regard to the supply at issue. PPL 
asserts that the flaw in FirstEnergy's proposal is that when a firm 
obligation to sell power is in effect, the seller cannot benefit 
from exercising market power with regard to the MWs sold pursuant to 
that firm obligation. Likewise, a buyer that can count on delivery 
of firm power is the ultimate decision-maker as to its resale. The 
seller will have to buy replacement power (at the prevailing market 
rate) if its expected source is not available, and therefore cannot 
benefit from withholding that amount of power. Thus such an approach 
would overstate one counter party's controlled capacity and 
understate the other's. PPL reply comments at 11-13.
---------------------------------------------------------------------------

    181. A number of commenters argue that jointly-owned plants should 
be assigned based on percentage of ownership.\162\ For example, 
Pinnacle states that, in the Southwest region, the joint ownership of 
base-load generating plants is the norm, and there is typically one 
party that has operational control over the facility. However, if the 
Commission refines the criteria for assigning generation to an entity 
based on factors such as directing plant outages, fuel procurement, and 
plant operations (or similar factors), there is concern that jointly-
owned generation may be attributed in whole to each of the owners if 
there is joint decision-making on such factors (e.g., if such decisions 
are made through a consortium of utilities forming a plant's joint 
operating committee) and result in unintentional double counting. 
Pinnacle also raises a concern that where joint plant owners appoint 
one of the joint owners to operate the plant, the entire plant will be 
attributed to the operator, rather than being attributed to each of the 
joint owners in shares. According to Pinnacle, the Final Rule should 
clarify that capacity of jointly-owned plants operated by one of the 
owners will be assigned to each joint owner based on its percentage 
interest.\163\ Pinnacle states that the current rules under the interim 
screens with regard to assigning generating capacity to an entity 
appear to be workable.\164\
---------------------------------------------------------------------------

    \162\ See, e.g., Duke at 25.
    \163\ Pinnacle at 4-5. See also MidAmerican at 6-7.
    \164\ EEI agrees that in such a situation, if both owners have 
input on how and where the capacity is sold, then the asset should 
be allocated based on ownership percentages. EEI at 20.
---------------------------------------------------------------------------

    182. Many other commenters raise concerns about double counting in 
cases of shared control.\165\ For example, with regard to shared 
facilities, FirstEnergy states that control of the plant should be 
attributed to the entity that is deemed to own the energy supplied from 
the plant. FirstEnergy offers that, if circumstances arise in which 
discretion over plant output is shared among more than one party, the 
Commission should permit the affected parties to resolve between 
themselves the entity to which capacity available in the unit will be 
attributed. FirstEnergy concludes that if the Commission adopts a 
regional approach to updated market power analyses, the Commission will 
be able to monitor those circumstances in which specified generation 
capacity is attributed to the wrong market participant.\166\
---------------------------------------------------------------------------

    \165\ See, e.g., Alliance Power Marketing reply comments at 8-9; 
Constellation at 6; MidAmerican at 6; PG&E at 8.
    \166\ FirstEnergy at 7-8.
---------------------------------------------------------------------------

Commission Determination
    183. With regard to the suggestion that we adopt a rebuttable 
presumption that the owner of the facility controls the facility, our 
historical approach has been that the owner of a facility is presumed 
to have control of the facility unless such control has been 
transferred to another party by virtue of a contractual agreement. We 
will adopt that approach. Accordingly, while we do not specifically 
adopt a rebuttable presumption that the owners control the facility, we 
will continue our practice of assigning control to the owner absent a 
contractual agreement transferring such control.
    184. We note that the Commission has developed precedent regarding 
the contractual arrangements that can transfer control. In these cases, 
the Commission has stated that control refers to arrangements, 
contractual or otherwise, that confer control of generation or 
transmission facilities just as effectively as they could through 
ownership.\167\ The capacity associated with contracts that confer 
operational control to an entity other than the owner thus must be 
assigned to the entity exercising control over that facility, rather 
than to the entity that is the legal owner of the facility, when 
performing the generation market power screens.\168\
---------------------------------------------------------------------------

    \167\ Citizens Power and Light Corp., 48 FERC ] 61,210 at 61,777 
(1989). See also Bechtel Power Corp., 60 FERC ] 61,156 (1992) 
(finding that an entity that was contractually engaged to provide 
operation and maintenance services was not an ``operator'' of 
jurisdictional facilities because the entity did not ``operate'' the 
facilities at issue but rather, in essence, was functioning merely 
as the owner's agent with respect to the operation of the 
jurisdictional facilities); D.E. Shaw, 102 FERC ] 61,265 at P 33-36 
(finding that a power marketer's ``investment adviser'' affiliate 
was a public utility where it had sole discretion to determine the 
trades to be entered into by the power marketer, as well as the 
power to execute the contracts, and therefore operated 
jurisdictional facilities rather than acted as merely an agent of 
the owner); R.W. Beck, 109 FERC ] 61,315 at P 15 (finding R.W. Beck 
Plant Management, Ltd. (Beck) was a public utility subject to the 
FPA in connection with its activities as manager of public utility 
Central Mississippi Generating Company, LLC because Beck effectively 
governed the physical operation of certain jurisdictional 
transmission and interconnection facilities and served as the 
decision-maker in determining sales of wholesale power).
    \168\ NOPR at P 47-48 (citing July 8 Order, 108 FERC ] 61,026 at 
P 65).
---------------------------------------------------------------------------

    185. With regard to FirstEnergy's suggestion that the affected 
parties make a determination regarding the entity to whom capacity 
available in the generating unit will be attributed in order to avoid 
any unwarranted double counting in the attribution of control,\169\ the 
Commission agrees that this is a constructive and appropriate approach. 
However, although we wish to avoid double counting as a general matter, 
the Commission will not rule out the possibility of double counting in 
circumstances where it is unclear what entity has control. For example, 
if different parties could control dispatch decisions under various 
circumstances, to err on the conservative side, the Commission may 
attribute generation to more than one seller for the purposes of the 
horizontal analysis.
---------------------------------------------------------------------------

    \169\ FirstEnergy at 7.
---------------------------------------------------------------------------

    186. To determine whether there are contracts transferring control 
to a seller seeking market-based rate authority, similar to the 
requirements for change in status filings,\170\ the Commission will

[[Page 39927]]

require sellers when filing an application for market-based rate 
authority or an updated market power analysis, to make an affirmative 
statement as to whether any contractual arrangements result in the 
transfer of control of any assets, including whether the seller is 
conferring control to another entity or obtaining control of another 
entity's assets. Moreover, in addition to requiring such affirmative 
statements as to whether any contractual arrangements result in the 
transfer of control of any assets,\171\ the Commission will require 
sellers, when filing an application for market-based rates, an updated 
market power analysis, or a required change in status report with 
regard to generation, to specify the party or parties they believe has 
control of the generation facility and to what extent each party holds 
control.
---------------------------------------------------------------------------

    \170\ See Calpine Energy Services, L.P., 113 FERC ] 61,158 at P 
13 (2005) (sellers making a change in status filing to report an 
energy management agreement are required to make an affirmative 
statement in their filing as to whether the agreement at issue 
transfers control of any assets and whether the agreement results in 
any material effect on the conditions that the Commission relied 
upon in the grant of their market-based rate authority).
    \171\ Such a statement should include contracts that transfer 
control to another party as well as contracts that transfer control 
to the seller.
---------------------------------------------------------------------------

    187. We understand that affected parties may hold differing views 
as to the extent to which control is held by the parties. Accordingly, 
we also will require that a seller making such an affirmative statement 
seek a ``letter of concurrence'' from other affected parties 
identifying the degree to which each party controls a facility and 
submit these letters with its filing. Absent agreement between the 
parties involved, or where the Commission has additional concerns 
despite such agreement, the Commission will request additional 
information which may include, but not be limited to, any applicable 
contract so that we can make a determination as to which seller or 
sellers have control.
    188. With regard to Pinnacle's concern regarding joint plant owners 
appointing one of the joint owners to operate the plant, we reserve 
judgment as a general matter. However, we understand that there may be 
situations where a jointly-owned generation facility is operated by one 
of the joint-owners for the benefit of and on behalf of all of the 
joint-owners. Under these circumstances, it may be reasonable to 
allocate capacity based on ownership percentages. Such a determination 
should be made on a case-specific basis.
    189. We remind sellers that in performing the horizontal market 
power analysis all capacity owned or controlled by the seller must be 
accounted for. In this regard, we expect that sellers, in performing 
such market power analyses, will clearly identify all assets for which 
they have control, or relinquished control, through contract.
iii. Energy Management Agreements
Comments
    190. Most commenters state that energy management agreements and 
the functions listed in the NOPR (directing plant outages, fuel 
procurement, plant operations, energy and capacity sales, and/or credit 
and liquidity decisions) should not be presumed to convey control. 
Financial Companies state that a generic presumption of control by 
energy managers will ``chill a seller's willingness to provide energy 
management services.'' \172\ Others suggest that the Commission should 
not adopt such a presumption and, in the alternative, should consider 
the specific aspects of an agreement. Additionally, some commenters 
request clarification on contract terms that are widely used in energy 
management agreements and may or may not convey control.
---------------------------------------------------------------------------

    \172\ Financial Companies at 9.
---------------------------------------------------------------------------

    191. Sempra and financial entities argue that the Commission should 
not adopt a presumption that energy management agreements confer 
control over generating capacity.\173\ They state that energy 
management and comparable agreements do not convey unlimited discretion 
and should not shift the presumption of control away from the entity 
that has final authority to dispatch the physical output of the plant.
---------------------------------------------------------------------------

    \173\ Sempra at 12-13; Morgan Stanley at 5-6; Financial 
Companies at 7-8 and reply comments at 3-5.
---------------------------------------------------------------------------

    192. Constellation agrees that the Commission should focus on 
whether an energy manager may make decisions about physical operation 
without final authority from a plant owner.\174\
---------------------------------------------------------------------------

    \174\ Constellation at 18.
---------------------------------------------------------------------------

    193. Westar expresses concerns that the NOPR's invitation to 
consider ultimate control to reside with any entity that has some 
discretion over the output of a plant would invite confusion and 
undercut the Commission's declared objective to provide greater 
certainty and clarity in this area.\175\ Alliance Power Marketing also 
expresses concern that a presumption that some discretion constitutes 
control will discourage innovation in the market, particularly with 
regard to option contracts and third-party arrangements.\176\
---------------------------------------------------------------------------

    \175\ Westar at 28.
    \176\ Alliance Power Marketing reply comments at 8-9.
---------------------------------------------------------------------------

    194. Alliance Power Marketing differentiates between asset/energy 
managers acting purely as agents and those that do not meet the legal 
definition of agents, suggesting that a market facilitator meeting the 
criteria of an agent should be exempt from attribution of control. The 
agent criteria identified by Alliance Power Marketing are: (1) The 
entity holds legal indicia of an agent's role; (2) the entity is 
neither a market participant nor an affiliate of a market participant; 
(3) the entity has limited, if any, financial stake in power market 
outcomes; and (4) the entity is subject to supervision or control in 
its activities on behalf of its principals.\177\ Alliance Power 
Marketing submits that agents do not control generation if they are 
acting on behalf of their clients, do not assume the risk of 
transactions, and never take title to power. Constellation notes that 
the Commission has previously recognized that an agent who is acting 
subject to the direction of the owner should be not found to have 
control of a facility.\178\
---------------------------------------------------------------------------

    \177\ Id. at 10-11.
    \178\ Constellation at 20 (citing Bechtel Power Corp., 60 FERC ] 
61,156 at 61,572 (1992)).
---------------------------------------------------------------------------

    195. Financial Companies disagree with Alliance Power Marketing's 
differentiation. They caution the Commission about imposing overly 
restrictive limitations on which entities qualify as agents or 
independent contractors and recommend that the Commission reject 
Alliance Power Marketing's proposal and suggest instead that ultimate 
decision-making authority is most relevant whether or not an agent is 
or is not a market participant.\179\
---------------------------------------------------------------------------

    \179\ Financial Companies reply comments at 3-4.
---------------------------------------------------------------------------

    196. In contrast, NASUCA submits that the Commission should presume 
that energy management agreements convey control when energy managers 
can control generation output or the price or quantity of service 
offered.\180\ Even more specifically, NASUCA recommends that the 
Commission reject formulations that would cloak market power of energy 
managers who control or affect electricity pricing, or the pricing of 
critical cost components such as fuel. Instead the Commission should 
adopt a rule that at a minimum encompasses the exercise of control over 
prices, bids, or output, including the ability to affect the cost of 
fuel and other inputs to generation.\181\
---------------------------------------------------------------------------

    \180\ NASUCA reply comments at 13 (citing NYISO at 6).
    \181\ Id. at 15.
---------------------------------------------------------------------------

Commission Determination
    197. After careful consideration of the comments, the Commission 
will not adopt a presumption of control regarding energy management 
agreements or the functions outlined in

[[Page 39928]]

the NOPR.\182\ We agree with commenters that energy management and 
comparable agreements do not necessarily convey unlimited discretion 
and control away from the entity that owns the plant. In this regard, 
as noted above, it is the totality of the circumstances that will 
determine which entity controls a specific asset.
---------------------------------------------------------------------------

    \182\ NOPR at P 49.
---------------------------------------------------------------------------

    198. Further, the Commission will not adopt a presumption of 
control in the case of shared discretion over the output and physical 
operation of a plant. The Commission is aware that varying degrees of 
discretion may be shared in some cases, and believes that the 
determination of control in these cases is best addressed on a fact-
specific basis. As noted by Sempra, there may always be an element of 
discretion associated with the implementation of instructions or 
guidelines included in energy management agreements.\183\
---------------------------------------------------------------------------

    \183\ Sempra at 13.
---------------------------------------------------------------------------

    199. With regard to Alliance Power Marketing's differentiation 
between asset/energy managers acting purely as agents and those that do 
not meet the legal definition of agents, and suggestion that ``a market 
facilitator meeting the criteria of an agent should be exempt from 
attribution of control,'' we find this differentiation in and of itself 
not determinative. Instead, consistent with our conclusion that the 
determination of control is appropriately based on a review of the 
totality of the circumstances on a fact-specific basis such that no 
single factor or factors necessarily results in control, it is the 
combination of the rights conveyed that determine control, not whether 
an entity considers itself to be an agent and not a market participant.
iv. Specific Functions and Contract Terms
Comments
    200. With regard to specific functions and specific contract terms, 
many commenters do not believe that functions such as directing plant 
outages, fuel procurement, plant operations, energy and capacity sales, 
and credit and liquidity merit a presumption of control.
    201. NYISO and FirstEnergy both suggest that the functions listed 
in the NOPR may be outsourced without conveying ultimate control. 
According to EEI, the list of functions described in the NOPR would not 
provide greater guidance.\184\ Rather, EEI believes a focus on the 
ability to withhold will be more effective than establishing 
presumptions based on the functions described in the NOPR. In 
particular, EEI argues that establishing presumptions for these 
individual functions would be difficult, because often it would be a 
combination of various functions that would result in the ability to 
affect bringing the capacity to market.\185\
---------------------------------------------------------------------------

    \184\ EEI reply comments at 25.
    \185\ EEI at 22.
---------------------------------------------------------------------------

    202. Duke believes that the Commission should avoid simplistic 
presumptions as to what constitutes control over resources for market 
power purposes and how and when specific generation should be imputed 
to market participants for purposes of the screen analysis. Duke argues 
that in a market power context, such determinations should be fact-
driven and based on a pragmatic assessment of which party has the 
ability to withhold a specific amount of capacity from the market. For 
example, the Commission should not automatically impute control over 
capacity based solely on contract language that appears to convey some 
element of discretion over unit operation to a particular party, 
notwithstanding the absence of any real world ability for that entity 
to withhold that capacity from the market. Duke states that the 
Commission should recognize that the ability to economically or 
physically withhold output from the market rests with the party that 
makes the final determination of whether generation (energy and/or 
capacity) will be offered into the market. Even a purchaser with 
dispatch rights may not have the ability to withhold supply, if the 
capacity owner has the right to schedule energy when the purchaser 
chooses not to do so. Similarly, a party with a contractual right to 
capacity (as opposed to energy), even with a call option for energy 
priced at market, does not have operational control over energy. Duke 
states that any contract in which rights to the energy ultimately 
revert to the owner/operator or for which energy is available only at a 
market price leaves control in the hands of the owner/operator. 
According to Duke, there should not be a blanket presumption that 
certain types of commercial arrangements or contractual language imply 
control in all instances.\186\
---------------------------------------------------------------------------

    \186\ Duke at 24-25.
---------------------------------------------------------------------------

    203. PG&E argues that any presumptions about control over 
generation should be based on whether a seller controls the dispatch of 
energy (i.e., can affect the ability of the capacity to reach the 
relevant market). This general presumption should cover all types of 
transactions and business arrangements, rather than trying to address 
every possible function. Such an approach will be more effective than 
establishing presumptions based on individual functions, as various 
factors may intersect or combine to provide this control. Relevant 
factors include authority over the use or provision of fuel to the 
plant.\187\
---------------------------------------------------------------------------

    \187\ PG&E at 7.
---------------------------------------------------------------------------

    204. PPL expresses concern that any arrangement in which a gas 
supplier could receive the output of a gas-fired generator as payment 
for the gas it supplies to the generator, if it is the only supplier to 
that generator, may convey control. PG&E appears to agree, stating that 
authority over the use or provision of fuel to the plant is a relevant 
factor with regard to control.\188\
---------------------------------------------------------------------------

    \188\ Id.
---------------------------------------------------------------------------

    205. EEI also appears to agree that fuel ownership may result in a 
change in control of plant output when, in the context of what triggers 
a change in status filing, it states: ``The Commission should continue 
the current policy that changes in the ownership of fuel supplies in 
and of themselves need not be reported. Only if the change in ownership 
of inputs results in a change of control of the output of the plant 
should a change in status filing be required. If a public utility 
acquires fuel supplies, there is no need to notify the Commission, 
unless the business structure, like a tolling agreement, actually 
results in discretion over the plant output.'' \189\
---------------------------------------------------------------------------

    \189\ EEI at 21.
---------------------------------------------------------------------------

    206. Sempra states that the Commission has generally treated energy 
management agreements as tolling agreements and requests that the 
Commission acknowledge the differences between the two.\190\ APPA/TAPS 
state that particularly under tolling arrangements, while the supplier 
of fuel may not be operating the plant, it controls the plants' 
production of energy for sale, thus affecting market outcomes.\191\ 
Constellation argues that plant operations and sales of output are 
functions that may convey control, but notes that the variety of case-
specific facts limits the benefit of a blanket presumption of control.
---------------------------------------------------------------------------

    \190\ Sempra at 11-12. According to Sempra, under energy 
management agreements, energy managers typically sell power 
according to instructions or guidelines provided by the owner, and 
the energy manager is compensated on a fee-basis. Sempra states that 
in the case of tolling agreements, the tolling party generally has 
complete discretion over sales of output and assumes risk of sales 
transactions with the owner typically receiving a flat compensation 
and retaining authority over when to operate the facility.
    \191\ APPA/TAPS at 90.
---------------------------------------------------------------------------

    207. Commenters also request that the Commission provide guidance 
regarding other contract types and terminology

[[Page 39929]]

such as call option contracts (with liquidated damages), contracts that 
allow variance in volume or delivery point, QF contracts, RMR 
contracts, capacity contracts, and load obligations.\192\
---------------------------------------------------------------------------

    \192\ See, e.g., EEI reply comments at 25; EPSA at 38; Financial 
Companies reply comments at 7; FirstEnergy at 6; Reliant at 5; Duke 
at 25; PG&E at 7-8; PowerEx at 9-13; PPL at 13; PPL reply comments 
at 13; PSEG at 13 and 18; Sempra reply comments at 4; SoCal Edison 
at 10; Southern Company at 23.
---------------------------------------------------------------------------

    208. Finally, EEI seeks clarification that energy only contracts 
over 100 MW for a term greater than one year that do not include rights 
to specific capacity are one type of contract that does not transfer 
control.
Commission Determination
    209. In Order No. 652, the Commission provided a non-exclusive, 
illustrative list of contractual arrangements that are subject to the 
change in status filing requirement. The list includes agreements that 
relate to ``operation (including scheduling and dispatch), maintenance, 
fuel supply, risk management, and marketing [of plant output]. These 
types of arrangements have in some cases also been referred to as 
energy management agreements, asset management agreements, tolling 
agreements, and scheduling and dispatching agreements.'' \193\ The 
Commission clarifies that the illustrative list included in Order No. 
652 provides guidance with regard to new applications for market-based 
rate authority and updated market power analyses as well as to change 
in status filings.
---------------------------------------------------------------------------

    \193\ Order No. 652, FERC Stats. & Regs. Regulations Preamles 
2001-2005 ] 31,175 at P 83.
---------------------------------------------------------------------------

    210. With respect to requests for clarification of whether certain 
contractual arrangements transfer control (such as call option 
contracts; liquidated damages contracts; contracts that allow variance 
in volume, source, or delivery point; QF contracts; RMR contracts; 
capacity contracts; and load obligations), for the reasons stated 
above, the Commission declines to address particular contractual 
terminology in isolation. The label placed on a specific contract does 
not determine whether it conveys control. Such determination 
necessarily must be made on a fact-specific basis.
    211. Similarly, with regard to EEI's request for clarification that 
energy-only contracts over 100 MW for a term greater than one year that 
do not include rights to specific capacity are one type of contract 
that does not transfer control, for the reasons stated above, the 
Commission declines to address such a specific contractual arrangement 
generically.
b. Requirement for Sellers To Have a Rate on File
Comments
    212. Alliance Power Marketing questions the Commission's proposal 
to clarify that any entity that controls generation from which 
jurisdictional sales are made is required to have a rate on file. 
Alliance Power Marketing believes that this proposal appears more akin 
to an inquiry than a Proposed Rulemaking.\194\ Pinnacle requests 
clarification as to whether a non-jurisdictional entity is required to 
have a rate on file if that entity is the operator of a facility 
jointly-owned by jurisdictional and non-jurisdictional entities.\195\
---------------------------------------------------------------------------

    \194\ Alliance Power Marketing at 16.
    \195\ Pinnacle at 5.
---------------------------------------------------------------------------

Commission Determination
    213. With regard to comments concerning the Commission's statement 
in the NOPR as to the need for an entity that controls generation from 
which jurisdictional power sales are made to have a rate on file, the 
Commission is reiterating, not modifying, the existing obligation to 
make rate filings. Under section 205 of the FPA,

every public utility shall file with the Commission * * * schedules 
showing all rates and charges for any * * * sale subject to the 
jurisdiction of the Commission, and the classifications, practices, 
and regulations affecting such rates and charges, together with all 
contracts which in any manner affect or relate to such rates, 
charges, classifications, and services.[\196\]
---------------------------------------------------------------------------

    \196\ 16 U.S.C. 824d(c).

Part II of the FPA defines a public utility as ``any person who owns or 
operates facilities subject to the jurisdiction of the Commission.'' 
\197\ Any entity not otherwise exempted from the Commission's 
regulations that owns or operates jurisdictional facilities from which 
jurisdictional power sales are made is a public utility required to 
have a rate on file with the Commission, unless the Commission has 
determined that such an entity does not in fact have ``control'' over 
the jurisdictional facilities sufficient to deem it a public utility 
(for example, if its ownership is passive, or its operation of 
facilities is as an agent subject to the control of the owner of the 
facilities). For any entity that is a public utility, if its rate 
authority is market-based, then it is subject to the conditions of 
authorization by the Commission (including the requirement to 
demonstrate lack of generation market power by the submission of market 
screens as spelled out in the horizontal market power section of this 
Final Rule). If an entity is a public utility and making jurisdictional 
sales without having a rate on file, those sales may be subject to 
refund, and the entity may be subject to a civil penalty.\198\
---------------------------------------------------------------------------

    \197\ 16 U.S.C. 824(e).
    \198\ Vermont Electric Cooperative, Inc., 108 FERC ] 61,223 
(2004), order on reh'g, 110 FERC ] 61,232 (2005).
---------------------------------------------------------------------------

    214. In response to Pinnacle, we clarify that if an entity has 
control of a jurisdictional facility and that entity is making 
jurisdictional sales, it would be a public utility subject to the 
jurisdiction of the Commission and would be required to have a rate on 
file with the Commission. However, if an entity is specifically 
exempted from the Commission's regulation pursuant to FPA section 
201(f), it would not be considered a public utility under the FPA and, 
accordingly, would not be required to have a rate on file.
7. Relevant Geographic Market
a. Default Relevant Geographic Market
Commission Proposal
    215. In the NOPR, the Commission proposed to continue to use its 
historical approach with regard to the relevant geographic market. The 
Commission stated that the default relevant geographic market is the 
control area where the generation owned or controlled by the seller is 
physically located and each of the control areas directly 
interconnected to that control area (with the exception of a generator 
interconnecting to a non-affiliate owned or controlled transmission 
system, in which case the relevant market is only the control area in 
which the seller is located). The Commission also proposed to continue 
to designate RTOs/ISOs with sufficient market structure and a single 
energy market in which a seller is located and is a member as the 
default relevant geographic market. In such circumstances the 
Commission would not require sellers to consider the first-tier markets 
to such RTOs/ISOs as being part of the default relevant geographic 
markets. In addition, the Commission noted in the NOPR that its 
experience with corporate mergers and acquisitions indicates that the 
same RTOs/ISOs that the Commission has identified as meeting the 
criteria for being considered a single market for purposes of 
performing the generation market power screens have, at times, been 
divided into smaller submarkets for study purposes

[[Page 39930]]

because frequently binding transmission constraints prevent some 
potential suppliers from selling into the destination market. 
Therefore, the Commission sought comment on its approach under the 
market-based rate program of considering the entire geographic region 
under control of the RTO/ISO, with a sufficient market structure and a 
single energy market, as the default relevant market. We asked whether 
the Commission should continue its approach of considering the entire 
geographic region as the default market for purposes of the indicative 
screens but consider RTO/ISO submarkets for purposes of the DPT.
Comments
    216. With regard to the RTO/ISO market, several commenters state 
that, based on all the protections associated with structured RTO/ISO 
markets with Commission-approved market monitoring and mitigation, the 
Commission should continue its current approach of allowing the entire 
geographic region of an RTO/ISO to be the default relevant market for 
the horizontal market power analysis.\199\ They state that retention of 
this standard will simplify preparation of market power analyses by 
sellers within qualified RTOs.
---------------------------------------------------------------------------

    \199\ Wisconsin Electric at 5-7, FirstEnergy at 8-9, PG&E at 8-
9, Xcel at 13-14, and Allegheny Energy Companies at 4-6. In 
addition, Ameren states that the Commission also should consider 
expanding the default geographic region beyond the footprint of a 
single RTO/ISO where contiguous RTOs/ISOs have a common market 
(Amerem at 4-5).
---------------------------------------------------------------------------

    217. Several commenters as well urge the Commission not to consider 
RTO or ISO submarkets. Sempra states that it recognizes that RTOs are 
at times divided into submarkets, such as for purposes relating to 
corporate merger and acquisition analyses, but it submits that the 
Commission should not consider RTO or ISO submarkets when conducting a 
market power analysis. Sempra states that the use of submarkets will 
result in uncertainty, confusion, and increased litigation as to the 
geographic boundaries of the ``right'' submarket that should be 
analyzed. According to Sempra, sellers that operate in RTO and ISO 
markets currently know with certainty the relevant geographic market 
for purposes of regulatory obligations such as reporting relevant 
changes in status, and the use of submarkets will eliminate that 
certainty and will open the door to competing definitions of 
submarkets. Sempra states that the existence of internal transmission 
constraints does not justify breaking up RTOs and ISOs into submarkets 
for purposes of the Commission's market power analysis. Sempra states 
that notably, only RTOs and ISOs with sufficient market structure and a 
single energy market can be used as default geographic markets. These 
attributes allow RTOs, ISOs, and their members to adopt mechanisms, 
including local markets or mitigation, that address potential concerns 
about local market power resulting from transmission constraints.\200\
---------------------------------------------------------------------------

    \200\ Sempra reply comments at 1-3.
---------------------------------------------------------------------------

    218. Similarly, EPSA, PG&E, PPL, ISO-NE, CAISO and NYISO support 
use of the entire RTO/ISO as the relevant geographic market where the 
RTOs/ISOs operate a single centralized market and generally where there 
are measures for monitoring and oversight.\201\
---------------------------------------------------------------------------

    \201\ EPSA at 11-12, PG&E at 8-9, and NYISO at 1-2.
---------------------------------------------------------------------------

    219. In addition, EPSA offers that changes to the size of markets 
can be addressed on a case-by-case basis by sellers or when an 
intervenor presents specific evidence supporting reduction of the 
relevant geographic market.\202\ PG&E states that in the case of a 
single control area like CAISO, there is little rationale or basis to 
determine how to subdivide a control area. Where there may be 
intermittent congestion within certain areas, the control area as a 
whole has regional planning and monitoring, avoiding the need to 
subdivide. In addition, the empirical fact that most sellers make no 
effort to justify an alternate geographic market--whether larger or 
smaller--supports the control area as the appropriate measure.\203\
---------------------------------------------------------------------------

    \202\ EPSA at 11-12.
    \203\ PG&E at 8-9.
---------------------------------------------------------------------------

    220. PPL states that if the Commission were to impose stringent 
market power tests based upon temporary transmission limitations beyond 
generators' control (e.g., infrequent intra-control area transmission 
system limitations), the Commission could make worse an already tenuous 
financial situation for existing generators in such areas and continue 
to deter new generation investment. Defining a geographic market 
smaller than a control area may lead to high failure rates of the 
screens. PPL states that associated loss of market-based rate authority 
(if that is the remedy imposed by the Commission) could precipitate 
economic retirements of those needed generators.
    221. Finally, Ameren suggests that, for purposes of the DPT, the 
relevant geographic market should be the applicable RTO/ISO footprint, 
just as it is for purposes of the indicative screens, unless the 
Commission already has found the existence of a submarket in the 
relevant portion of the RTO/ISO. In such cases, the Commission should 
give due consideration to any existing Commission-approved market 
monitoring and mitigation regime already in place within the RTO/ISO 
that provides for mitigation of the submarket. If the relevant RTO/ISO 
does not have in place a mitigation program for an identified 
submarket, the Commission may then consider appropriate submarket-
specific mitigation in connection with granting market-based rate 
authorization.
    222. On the other side of the issue, several commenters urge the 
Commission to consider internal transmission constraints and possible 
submarkets within RTOs/ISOs. The California Board proposes that the 
Commission permit RTOs to identify submarkets within their control 
area, as needed, to help determine possible local market power. The 
California Board states that if the Commission develops or approves 
criteria which sellers may use to expand their geographic market, then 
the same criteria must be applicable in RTOs to limit the size of a 
geographic market. The New Jersey Board states that intervenors should 
be allowed to present evidence that the relevant geographic market is 
smaller (or larger) than the default RTO/ISO market and states that 
evidence of binding transmission constraints is relevant when examining 
horizontal market power.\204\
---------------------------------------------------------------------------

    \204\ New Jersey Board at 3-4.
---------------------------------------------------------------------------

    223. State AGs and Advocates state that almost any large default 
geographic market will have many transmission-constrained areas (load 
pockets) within it and that the Commission must require applicants for 
market-based rate authority to do a proper analysis of the degree of 
market power that is likely to be exercised by all sellers, including 
the applicants, in all relevant load pockets or transmission-
constrained regions or subregions in which the sellers control 
generation capacity. They state that all load pockets must be 
considered as appropriate geographic markets whenever they exist.
    224. APPA/TAPS state that the presumption of the RTO footprint as 
the default geographic market must be truly rebuttable, including 
rebuttals based upon evidence that the RTO itself treats an area as a 
separate market.\205\ APPA/TAPS state that in practice, however, the 
presumption appears to be irrebuttable. They argue that if known load 
pockets such as WUMS (or, for example, the Delmarva Peninsula, 
Southwest Connecticut, or the City of

[[Page 39931]]

San Francisco, among others) do not rebut the geographic market 
presumption, the rebuttable presumption effectively becomes 
irrebuttable. APPA/TAPS recommend that in advance of each region's 
market-based rate review, RTOs should provide market participants with 
transmission studies that reveal where binding transmission constraints 
arise so that those data can be used in addressing the proper relevant 
geographic market. In addition, APPA/TAPS state that in the Sec.  203 
context, the Commission has correctly found that transmission 
constraints lead to distinct geographic markets, at least when those 
constraints are binding. They submit that no reasonable basis exists to 
distinguish between the competitive analyses used to establish relevant 
geographic markets in the section 203 and the section 205 
contexts.\206\
---------------------------------------------------------------------------

    \205\ APPA/TAPS at 56-63.
    \206\ APPA/TAPS at 61-62.
---------------------------------------------------------------------------

    225. In response to APPA/TAPS, EPSA states that in cases where the 
Commission denied a seller's argument to change its relevant geographic 
market, the Commission carefully considered the positions of parties 
advocating a different market and simply found their arguments 
insufficient to warrant a modification to the market definition.\207\ 
EPSA states that it cannot be said that a presumption is irrebuttable 
simply because the Commission has, to date, deferred to RTO/ISO 
mitigation mechanisms to this point.
---------------------------------------------------------------------------

    \207\ EPSA reply comments at 9-11, citing APPA/TAPS at 56.
---------------------------------------------------------------------------

    226. With regard to non-RTO areas, APPA/TAPS states that while the 
control area provides a reasonable starting point, the Commission's 
obligation to base its market-based rate decision on ``empirical 
proof'' requires reliance on specific facts that demonstrate whether 
the relevant geographic market should be the control area, or a smaller 
or larger area. APPA/TAPS further state that, for non-RTO areas, the 
seller should affirmatively address whether the geographic market 
should default to the control area or whether a smaller or larger area 
is appropriate, and support that result with evidence. They add that 
intervenors should also be allowed to introduce evidence regarding the 
question.\208\
---------------------------------------------------------------------------

    \208\ APPA/TAPS at 53-62.
---------------------------------------------------------------------------

    227. With regard to both RTO/ISO and non-RTO areas, several other 
commenters urge the Commission to consider changing its existing policy 
on the default geographic market. State AGs and Advocates state that 
the best policy would be to have no ``default'' market criteria, but to 
have each applicant for market-based rates determine on an analytical 
basis what market area makes the most sense for its circumstances based 
on the actual transmission constraints that it faces.\209\ NRECA states 
that using individual control areas or RTOs as the default market for 
evaluating a transmission provider's market power fails to account for 
the binding transmission constraints and load pockets that have 
developed within those markets.\210\
---------------------------------------------------------------------------

    \209\ State AGs and Advocates at 44-48.
    \210\ NRECA at 12.
---------------------------------------------------------------------------

    228. Morgan Stanley states that it supports the Commission's 
practice of relying on control areas and RTO/ISO regions when assessing 
market power as the default markets, but believes the Commission may be 
missing instances of market power by failing to also review known 
events that can create narrower or broader markets. For example, Morgan 
Stanley states that the Commission acknowledges that binding 
transmission constraints and the existence of load pockets can cause 
considerable market power issues. Therefore, Morgan Stanley asserts 
that the Commission should indeed consider whether a seller may possess 
the ability to exercise market power in a portion of an otherwise 
competitive market. To enable the Commission to do so, sellers should 
address known constraints in their description of the relevant 
geographic market in their market power filings, particularly in 
markets for which they are the control area operator.\211\
---------------------------------------------------------------------------

    \211\ Morgan Stanley at 8.
---------------------------------------------------------------------------

    229. The California Commission states that while it agrees that 
designating a relevant geographic area will reduce uncertainty to all 
market participants, designation of a static geographic market in a 
dynamic market may defeat the purpose of market certainty and may have 
unintended adverse consequences over time. For example, with the 
implementation of locational marginal pricing (LMP) in the CAISO 
control area, there will be many submarket areas known as local areas. 
This will trigger ``false negatives'' (i.e., absence of market power 
even when there is market power) in a control area analysis. A seller 
may pass both screens and receive market-based rate authority when 
tested against the broader geographic control area, such as the entire 
CAISO control area market. However, the same seller may not pass the 
screens when tested against a particular sub-area or local area. 
Accordingly, the California Commission states that the Commission 
should be flexible in designating geographic areas to determine market 
power. The Commission should designate geographic areas by considering 
current and reasonably foreseeable regional developments, as the 
Commission currently does in merger cases following DOJ/FTC merger 
guidelines.\212\ Similarly, the Commission should consider the presence 
or absence of market power due to continuous developments of major 
market events (e.g., area outages, congestion due to new market 
developments, and the development of load) that can have significant 
impact as inputs in the market power screening calculation.
---------------------------------------------------------------------------

    \212\ California Commission at 5-6.
---------------------------------------------------------------------------

    230. In contrast, EEI disagrees with those commenters that would 
require the seller in each filing to affirmatively address with 
supporting evidence whether the geographic market should default to the 
control area or RTO/ISO area. EEI states that this requirement would 
defeat the purpose of having default areas to expedite and simplify the 
market-based rate filing process, noting that it is more efficient for 
any affected party to have the right to challenge the selection of the 
default market, as exists under the proposed regulations.\213\
---------------------------------------------------------------------------

    \213\ 213 EEI reply comments at 26-27.
---------------------------------------------------------------------------

Commission Determination
    231. The Commission will adopt in this Final Rule its current 
approach with regard to the default relevant geographic market, with 
some modifications. In particular, the Commission will continue to use 
a seller's balancing authority area \214\ or the RTO/ISO market, as 
applicable, as the default relevant geographic market.\215\ However, 
where the Commission has made a specific finding that there is a 
submarket within an RTO/ISO, that submarket becomes the default 
relevant geographic market for sellers located within the submarket for 
purposes of the market-based rate analysis.
---------------------------------------------------------------------------

    \214\ As we discuss fully below, the Commission will adopt the 
use of ``balancing authority area'' instead of control area. As a 
result we use hereon the term balancing authority area. In addition, 
even though commenters use the term ``control area'' we will use the 
term ``balancing authority area'' in our response.
    \215\ In addition, the Commission will continue to require 
sellers located in and a member of an RTO/ISO to consider, as part 
of the relevant market, only the relevant RTO/ISO market and not 
first-tier markets to the RTO/ISO.
---------------------------------------------------------------------------

    232. With regard to traditional (non-RTO/ISO) markets, our default 
relevant geographic market under both indicative screens will be first, 
the balancing

[[Page 39932]]

authority area where the seller is physically located,\216\ and second, 
the markets directly interconnected to the seller's balancing authority 
area (first-tier balancing authority area markets).\217\ We also 
clarify that if a transmission-owning Federal power marketing agency 
(e.g., the Tennessee Valley Authority, Bonneville Power Administration) 
is the home or first-tier market to the seller, then that seller must 
treat that Federal power marketing agency's balancing authority area as 
a relevant geographic market and file market power analysis on it just 
as it would any other relevant market.\218\ Under the indicative 
screens, we will consider only those supplies that are located in the 
market being considered (relevant market) and those in first-tier 
markets to the relevant market. For non-RTO sellers, we adopt a 
rebuttable presumption that the seller's balancing authority area and 
each of its neighboring first-tier balancing authority areas are each 
relevant geographic markets.
---------------------------------------------------------------------------

    \216\ For applications by sellers with no physical generation 
assets (such as power marketers) that are affiliated with generation 
asset owning utilities, we will continue to evaluate the affiliate 
generation owner's market power when evaluating whether to grant 
market-based rate authority to the power marketer.
    \217\ Where a generator is interconnecting to a non-affiliate 
owned or controlled transmission system, there is only one relevant 
market (i.e., the balancing authority area in which the generator is 
located.).
    \218\ See, e.g., Portland General Electric Co., 111 FERC ] 
61,151 at P 7 (2005); Idaho Power Co., 110 FERC ] 61,219 at n.6, P 
10 (2005); Florida Power Corp., 113 FERC ] 61,131 at P 17 (2005).
---------------------------------------------------------------------------

    233. Although a number of commenters oppose the use of the 
balancing authority area as the default geographic market in 
traditional markets, they have submitted no compelling evidence that 
our historical approach is inadequate or insufficient for the typical 
situation. Indeed, using balancing authority areas allows the 
Commission and public to rely on publicly available data provided for 
balancing authority areas that are relevant to the market-based rate 
analysis discussed herein. These data are accurate and generally 
available. We will, however, continue to allow sellers and intervenors 
to present evidence on a case-by-case basis to show that some other 
geographic market should be considered as the relevant market in a 
particular case.\219\ We clarify that the seller must provide the 
Commission with a study based on the default geographic market, and we 
will allow sellers and intervenors to present additional sensitivity 
runs as part of their market power studies to show that some other 
geographic market should be considered as the relevant market in a 
particular case. This evidence would be an addition to the required 
study based on the relevant geographic market as referred to in this 
Final Rule.
---------------------------------------------------------------------------

    \219\ We note that the Commission itself may explore whether an 
alternative geographic market is warranted based on the specific 
facts and circumstances of a given case.
---------------------------------------------------------------------------

    234. We do not adopt the suggestion by APPA/TAPS that the seller 
should affirmatively address whether the geographic market should 
default to the balancing authority area. We believe that EPSA's 
argument that such a requirement would defeat the purpose of having 
default areas and add uncertainty into the market is more persuasive. 
By defining default geographic markets, we provide the industry as much 
certainty as possible while also providing affected parties the right 
to challenge the default geographic market definition and provide 
evidence in that regard.
    235. With regard to RTO/ISO markets, we agree with many commenters 
that RTOs/ISOs with a sufficient market structure and a single energy 
market with Commission-approved market monitoring and mitigation 
provide strong market protections. As a general matter, sellers located 
in and members of the RTO/ISO may consider the geographic region under 
the control of the RTO/ISO as the default relevant geographic market 
for purposes of completing their horizontal analyses, unless the 
Commission already has found the existence of a submarket.
    236. Where the Commission has made a specific finding that there is 
a submarket within an RTO/ISO, we believe that the market-based rate 
analysis (both indicative screens and DPT) should consider that 
submarket as the default relevant geographic market. This is consistent 
with how the Commission has treated such submarkets in the merger 
context. For example, in some merger orders, the Commission has found 
that PJM-East, and Northern PSEG are markets within PJM;\220\ 
Southwestern Connecticut (SWCT) and Connecticut Import interface (CT) 
are separate markets within ISO-NE;\221\ and New York City and Long 
Island are separate markets within NYISO.\222\ Accordingly, we conclude 
that sellers located in these RTO/ISO submarkets should not use the 
entire PJM, ISO-NE and NYISO footprints as their relevant geographic 
markets for purposes of the market-based rate analysis. Instead, they 
should use as the default geographic market for their market-based rate 
analysis the submarkets that the Commission already has found 
constitute separate markets in those RTOs/ISOs.
---------------------------------------------------------------------------

    \220\ Exelon Corp., 112 FERC ] 61,011, reh'g denied, 113 FERC ] 
61,299 (2005) (Exelon). We note that Exelon later terminated the 
merger.
    \221\ Wisvest-Connecticut, LLC, 96 FERC ] 61,101 (2001). The 
parties later withdrew their application under FPA section 203.
    \222\ National Grid plc, 117 FERC ] 61,080 (2006).
---------------------------------------------------------------------------

    237. We agree with APPA/TAPS that if the Commission makes a 
specific finding that the relevant geographic market is one other than 
the balancing authority area or RTO/ISO geographic region, the 
Commission's finding should define the default market going forward. 
For example, if the Commission finds that a submarket exists within an 
RTO, that submarket becomes the default geographic market for all 
sellers that own or control generation capacity within that submarket.
    238. To the extent that the Commission finds that a submarket 
exists within an RTO/ISO, intervenors or sellers can provide evidence 
to the contrary (i.e., the submarket, like our other default geographic 
markets, is rebuttable). In addition, if a seller or intervenor argues 
that the seller operates in an RTO/ISO submarket and presents 
sufficient evidence to support that conclusion, we will consider those 
arguments even if the Commission has not previously found that a 
submarket exists.
    239. As a general matter, because we recognize the arguments raised 
by commenters that defining default geographic markets (whether 
balancing authority area, RTO/ISO footprint or RTO/ISO submarket) may 
not be appropriate in all circumstances, on a case-by-case basis, we 
will allow sellers and intervenors to present additional sensitivity 
analyses \223\ as part of their market power analysis to show that some 
other geographic market should be considered as the relevant market in 
a particular case. For example, sellers or intervenors could present 
evidence that the relevant market is broader than a particular 
balancing authority area. Sellers and intervenors may also provide 
evidence that because of internal transmission limitations (e.g., load 
pockets) the relevant market (or markets) is smaller than the balancing 
authority area, RTO/ISO footprint or RTO/ISO submarket. We believe this 
is a balanced approach because it establishes a presumption that the 
Commission will in most cases rely on default geographic markets, while 
at the same time, the Commission will give sellers and intervenors the 
opportunity to argue that the facts of a particular

[[Page 39933]]

case support the use of some other geographic area as the relevant 
market.
---------------------------------------------------------------------------

    \223\ These analyses should be in addition to, not in lieu of, 
the analysis based on the default geographic market.
---------------------------------------------------------------------------

    240. We also provide, as discussed further below, guidance 
regarding the type of analysis required to rebut the default geographic 
markets including default markets for balancing authority areas, RTO/
ISO markets, and RTO/ISO submarkets.
    241. In this regard, sellers can incorporate the mitigation they 
are subject to in RTO/ISO markets or RTO/ISO submarkets with 
Commission-approved market monitoring and mitigation as part of their 
market power analysis. For example, if a market power analysis shows 
that a seller has local market power, the seller may point to RTO/ISO 
mitigation rules as evidence that this market power has been adequately 
mitigated. We believe the added protections provided in structured 
markets with market monitoring and mitigation generally result in a 
market where prices are transparent and attempts to exercise of market 
power will be sufficiently mitigated.
    242. With respect to market concentration resulting within RTO/ISO 
submarkets, we will continue to consider existing RTO mitigation. The 
Commission will consider an existing Commission-approved market 
monitoring and mitigation regime already in place within the RTO/ISO 
that provides for mitigation of the submarket. For example, New York 
City will be treated as a separate default market for market-based rate 
study purposes. However, because it has existing In-City mitigation, we 
will assess whether any concerns over market power are already 
mitigated. We agree with Ameren that if the relevant RTO/ISO does not 
have in place a mitigation program for an identified submarket, the 
Commission may then consider whether and, if so, to what extent 
appropriate submarket-specific mitigation is needed.
    243. In response to APPA/TAPS' statement that in practice the 
presumption of the RTO footprint as the default geographic market 
appears to be irrebuttable, this is simply not the case. The Commission 
carefully considers the positions and evidence submitted by parties 
advocating a different geographic market. Although we may have found 
that arguments made in a particular case were unconvincing, or that 
market power was adequately mitigated by existing mitigation,\224\ we 
did, and will continue to, provide the opportunity for sellers to rebut 
the presumption. Moreover, as discussed above, where the Commission has 
made a specific finding that there is a submarket within an RTO, that 
submarket (not the RTO footprint) becomes the default relevant 
geographic market for sellers located within the submarket for purposes 
of the market-based rate analysis.
---------------------------------------------------------------------------

    \224\ See, e.g., Mystic I, LLC, 111 FERC ] 61,378 at P 14-19 
(2005) (rejecting challenge to use of ISO-NE market as the relevant 
geographic market on the basis that local market power mitigation is 
in place: ``[W]ithout specific evidence to the contrary, we are 
satisfied that ISO-NE has Commission-approved tariff provisions in 
place to address instances where transmission constraints would 
otherwise allow generators to exercise local market power and that 
these rules and procedures will apply in the NEMA/Boston zone within 
ISO-NE.''); Wisconsin Electric Power Co., 110 FERC ] 61,340 at P 19-
20, reh'g denied, 111 FERC ] 61,361 at P 13-15 (2005) (rejecting 
challenge to use of Midwest ISO market as the relevant geographic 
market on basis that local market power mitigation measures exist: 
``The tighter thresholds in NCAs such as WUMS in the Midwest ISO, 
and the resulting tighter mitigation of bids, are local market power 
mitigation measures'' and should adequately address specific 
concerns regarding the possibility that Wisconsin Electric can 
exercise market power in the WUMS region). Accord AEP Power 
Marketing, Inc., 109 FERC ] 61,276 (2004), reh'g denied, 112 FERC ] 
61,320 at P 23-25 (2005), aff'd, Industrial Energy Users-Ohio v. 
FERC, No. 05-1435 (D.C. Cir. Feb. 16, 2007) (use of PJM footprint as 
relevant geographic market; noting existence of Commission-approved 
market monitoring and mitigation).
---------------------------------------------------------------------------

    244. In this proceeding, we have considered expanding the default 
geographic region of a single RTO/ISO where contiguous RTOs/ISOs may 
have a common market as suggested by Ameren and find that there is 
insufficient support to make a generic finding that any contiguous 
RTOs/ISOs form a single geographic market.
    245. With regard to the California Board's proposal that the 
Commission permit RTOs to identify submarkets within their balancing 
authority area, as needed to help determine possible local market 
power, we agree that this is an appropriate approach. However, we note 
that this is neither a new nor a novel approach. The Commission has 
historically considered the views of RTOs/ISOs in this regard and will 
continue to do so. We note, however, that to the extent RTOs/ISOs 
believe there is a market power issue within their RTO/ISO, they should 
notify the Commission promptly and not wait for an application by an 
entity seeking market-based rate authority or a current seller 
submitting an updated market power analysis.
    246. Finally, to avoid any possible uncertainty or confusion about 
the RTO/ISO submarket, we identify RTO/ISO submarkets that the 
Commission to date has found to constitute a separate market. The 
Commission found submarkets in the PJM market, PJM East and Northern 
PSEG.\225\ In Wisvest-Connecticut, LLC, the Commission also found two 
submarkets, SWCT and CT in ISO-NE.\226\ In National Grid plc, the 
Commission again found two submarkets, New York City and Long Island, 
in NYISO.\227\ These RTO/ISO submarkets will be the default geographic 
markets for purposes of the market-based rate analysis.
---------------------------------------------------------------------------

    \225\See Exelon, 112 FERC ] 61,011 at P 122.
    \226\ The Commission stated that ``clearly, during periods when 
transmission becomes so constrained such that no additional imports 
from outside the region are possible and generators located inside 
the region are the only suppliers that can sell inside the region, 
the region should be defined as a separate relevant geographic 
market. Such is the case with SWCT and CT in this proceeding.'' SWCT 
was defined as the area inside the Southern Connecticut Import 
interface, and CT was defined as the area inside the Connecticut 
Import interface, which is essentially contiguous with the state of 
Connecticut itself. Wisvest-Connecticut, LLC, 96 FERC ] 61,101 at 
61,401-02.
    \227\ In National Grid plc, 117 FERC ] 61,080 at P 26, the 
Commission used Sellers' HHI numbers for two of the NYISO submarkets 
(New York City and Long Island) to assess horizontal market power, 
and found screen failures in both submarkets under the economic 
capacity analysis. Id. at P 31.
---------------------------------------------------------------------------

b. NERC's Balancing Authority Area and Default Geographic Area
Commission Proposal
    247. In the NOPR, the Commission noted that the North American 
Electric Reliability Corporation (NERC) no longer uses the designation 
of control area since it approved the Reliability Functional Model 
(Functional Model). The Commission sought comment as to whether or not 
the adoption of the NERC Functional Model should change the criteria 
for specifying the default relevant geographic market, and if so, in 
what way it should be specified and how readily available the relevant 
data is.
Comments
    248. Several commenters state that since NERC no longer uses 
control area designations, and its Functional Model refers to 
``balancing authority areas,'' the Commission should modify slightly 
its approach to default geographic markets by simply replacing the term 
``control area'' with ``balancing authority area.'' They state that 
such a change will align the Commission's rules with NERC's Functional 
Model, thus helping to avoid confusion.\228\
---------------------------------------------------------------------------

    \228\ E.ON U.S. at 19, PNM/Tucson at 21, and Indianapolis P&L at 
4-5.
---------------------------------------------------------------------------

    249. NYISO states that the control area is a valid starting point 
for the analysis of market-based rates. NYISO states that under the 
most recent version of the Reliability Functional Model posted on the 
NERC Web site (version 3, April 21, 2006), the ``Balancing'' and 
``Market Operations'' functions appear to correlate to the traditional 
notion of

[[Page 39934]]

a control area operator for purposes of assessing competitive markets. 
Thus, the adoption of the Functional Model would appear to create 
issues more of terminology than substance. NYISO states that, whatever 
the terminology, the process of defining geographic markets should 
focus on the area in which grid operations generally facilitate the 
ability of generators to compete in the scheduling and dispatch of 
resources, and the ability of loads to purchase from such 
resources.\229\
---------------------------------------------------------------------------

    \229\ NYISO at 2-4.
---------------------------------------------------------------------------

Commission Determination
    250. With regard to the use of the Functional Model by NERC, we 
agree with commenters that the Commission should modify slightly its 
approach to default geographic markets by replacing the term ``control 
area'' with ``balancing authority area.''
    251. A balancing authority area means the collection of generation, 
transmission, and loads within the metered boundaries of a balancing 
authority, and the balancing authority maintains load/resource balance 
within this area.\230\ Similar to control area, a balancing authority 
area is physically defined with metered boundaries that we refer to as 
the balancing authority area. Every generator, transmission facility, 
and end-use customer must be in a balancing authority area.\231\ The 
responsibilities of a balancing authority include the following: (1) 
Match, at all times, the power output of the generators within the 
balancing authority area and capacity and energy purchased from or sold 
to entities outside the balancing authority area, with the load within 
the balancing authority area in compliance with the Reliability 
Standards; (2) maintain scheduled interchange and control the impact of 
interchange ramping rates with other balancing authority areas, in 
compliance with Reliability Standards; (3) have available sufficient 
generating capacity, and Demand Side Management to maintain Contingency 
Reserves in compliance with Reliability Standards; and (4) have 
available sufficient generating capacity, Demand Side Management, and 
frequency response to maintain Regulating Reserves and Operating 
Reserves in compliance with Reliability Standards.\232\ It is the 
interconnection and coordination between balancing authority areas that 
provides a foundation for the Commission to analyze transmission 
limitations and other transfers of energy and provides a reasonable 
measure of the relevant geographic market under typical circumstances.
---------------------------------------------------------------------------

    \230\ See ``Glossary of Terms Used in Reliability Standards,'' 
at http://www.ferc.gov/industries/electric/indus-act/reliability/standards.asp
.

    \231\ See Basic Operating Functions and Responsibilities: A 
White Paper by the Control Area Criteria Task Force.http://www.maac-rc.org/reports/documents/cactf_reliability_model_whitepaper_v2.pdf
.

    \232\ See Approved Reliability Standards. http://www.ferc.gov/industries/electric/indus-act/reliability/standards.asp
.

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

    252. The Commission adopts in this Final Rule ``balancing authority 
area,'' instead of ``control area.'' We believe that such a change will 
align the Commission's rules with NERC's Functional Model, thus helping 
to avoid confusion.
c. Additional Guidelines for Alternative Geographic Market and 
Flexibility
Commission Proposal
    253. In the NOPR, the Commission proposed to continue to provide 
flexibility by allowing sellers and intervenors to present evidence 
that the market is smaller or larger than the default market. The 
Commission explained that when assessing an expanded geographic market 
pursuant to the horizontal analysis, it looks for assurance that no 
frequently recurring physical impediments to trade exist within the 
expanded market that would prevent competing supply in the expanded 
area from reaching wholesale customers. The Commission stated that any 
proposal to use an expanded market should include a demonstration 
regarding whether there are frequently binding transmission constraints 
during historical seasonal peaks examined in the screens and at other 
competitively significant times that prevent competing supply from 
reaching the customers within the expanded market. The Commission 
proposed to require that such a demonstration be made based on 
historical data, and said it would require that a sensitivity analysis 
be performed analyzing under what circumstances transmission 
constraints would bind.
    254. The Commission explained that it also considers whether there 
is other evidence that would support the existence of an expanded 
market, such as evidence that customers can access the resources 
outside of the default geographic market on similar terms and 
conditions as those inside the default geographic market. It stated 
that such evidence could be empirical or it could point to factors that 
indicate a single market. It noted that the Commission has previously 
stated that the operation of a single central unit commitment and 
dispatch function for the proposed geographic market would be an 
indicator of a single market, but that other evidence of a single 
market could include a demonstration that: There is a single 
transmission rate; there is a common OASIS platform for scheduling 
transmission service across separate control areas; or there is a 
correlation of price movements between the areas being considered as an 
expanded geographic market or other information regarding wholesale 
transactions in the proposed single market. The Commission stated that 
evidence of active trading throughout the proposed geographic market 
would also be considered. It stated that in determining whether two or 
more control areas are a single market it would weigh, on a case-by-
case basis, all the factors presented. The Commission noted that once 
it has been established that historically there were no physical 
impediments to trade, there are several factors the Commission would 
consider, and no one factor would be dispositive. The Commission sought 
comment on this proposed guidance and, in particular, whether there are 
other factors it should consider when assessing a proposed expanded 
market and whether there are any factors that should be given more 
weight or are essential in determining the scope of the market. The 
Commission also asked whether it should apply the same criteria when 
determining whether the geographic market is smaller than the default 
geographic market.
Comments
    255. A number of commenters agree that it is appropriate to provide 
sellers flexibility in presenting evidence that the appropriate 
geographic market is broader than the default geographic market.\233\ 
Several state that greater Commission guidance is needed so that 
sellers wishing to argue for a broader market definition have clear 
objective criteria and can provide evidence that the Commission will 
find probative.
---------------------------------------------------------------------------

    \233\ Indianapolis P&L at 5-6, Puget at 9-11, Ameren at 4-5, 
Duke at 23-24, and Avista at 5-7.
---------------------------------------------------------------------------

    256. Puget submits that the examples listed in the NOPR provide 
some guidance but are still too general to be of use to a seller 
submitting a new market power study. It states that the Commission 
should: (1) Provide additional guidance on the levels of price 
convergence and trading activity across a proposed alternative market 
that will support a seller's filing; (2) be more specific regarding the 
level of transmission constraints that will preclude a finding of an 
expanded

[[Page 39935]]

market; and (3) not rely heavily, if at all, on transmission operation 
factors--such as common OASIS or common unit commitment and dispatch--
that are not necessarily indicative of a common market.\234 \
---------------------------------------------------------------------------

    \234\ Puget at 9-11.
---------------------------------------------------------------------------

    257. Southern states that the Commission's proposed focus on 
evidence pertaining to frequently binding transmission constraints for 
purposes of considering a larger geographic market seems appropriate. 
However, Southern argues that the NOPR's apparent requirement of 
additional evidence (beyond the absence of transmission constraints) to 
support a larger geographic market is unnecessary. Moreover, Southern 
submits that evidence of a single unit commitment and dispatch 
function, a single transmission rate, and a common OASIS platform is 
not likely to exist in the absence of an RTO or ISO. Accordingly, 
making such evidence a requirement for a larger geographic market would 
render illusory the opportunity for expansion for non-RTO/ISO 
sellers.\235 \
---------------------------------------------------------------------------

    \235\ Southern at 24-25.
---------------------------------------------------------------------------

    258. Avista agrees that the absence of these factors does not 
necessarily mean that a market contains impediments to trading or that 
wholesale customers are unable to secure supply from alternative 
sources. Avista supports the Commission's proposal to state what type 
of evidence demonstrates active trading throughout the proposed 
geographic market. Avista submits that a regional geographic market 
could and should be established based upon: (1) The presence of an 
actively traded liquid trading hub within the relevant defined market 
area; (2) transparent pricing information from that hub being widely 
available; and (3) the presence of extensive direct or single-wheel 
transmission access, both for sellers into the competitive hub market 
and for buyers' access to the hub market for purposes of serving 
load.\236\
---------------------------------------------------------------------------

    \236\ Avista at 5-7.
---------------------------------------------------------------------------

    259. Powerex supports the Commission's initial specification of 
evidence that may be used to support a demonstration of a broader or 
smaller geographic market. However, Powerex is concerned that the 
Commission's enumeration of relevant categories of evidence is at 
present a partial list, and is not sufficiently comprehensive to 
address the unique circumstances that are likely to be present in 
various regions. Powerex states that the Commission should clarify that 
additional types of evidence may also be used to support the propriety 
of a broader or smaller market definition.
    260. One commenter states that the appropriate definition of the 
relevant geographic market can be (and very often will be) 
conditional--that is, when there are no binding transmission 
constraints on imports into the relevant control area, the relevant 
market appropriately encompasses a broader area than the default 
geographic market; and when transmission constraints into the control 
area are binding, the control area is the appropriate geographic 
market. Accordingly, sellers should be allowed (or encouraged) to 
present analytical results for several market definitions, dependent on 
the existence or nonexistence of binding transmission constraints, to 
sharpen the focus on when market power might be a real concern.\237\
---------------------------------------------------------------------------

    \237\ Dr. Pace at 15-16.
---------------------------------------------------------------------------

    261. APPA/TAPS generally agree that the factors set forth by the 
Commission for assessing whether an alternative geographic market is 
appropriate are reasonable, but urge that the factors be non-exclusive 
and non-prescriptive. In addition to the factors the Commission 
identified in the NOPR, APPA/TAPS suggest that a seller be allowed to 
point to any joint transmission planning and coordinated construction 
processes as evidence that the relevant market should be larger than 
its own control area.\238\ APPA/TAPS state that a seller that is 
correctly advancing efforts to expand markets deserves to have that 
recognized and a seller that is not undertaking such efforts should 
live with the consequences of the resulting smaller market.
---------------------------------------------------------------------------

    \238\ APPA/TAPS at 54.
---------------------------------------------------------------------------

    262. PPL states that if the Commission is to consider the potential 
existence of geographic markets smaller or larger than a control area, 
it should carefully consider the specific circumstances surrounding the 
control area of concern, and use an objective review process. That is, 
the Commission should consider these factors through the following 
means: (1) Evaluation of the historical frequency of, and times when, 
physical transmission constraints limit the ability to transmit power 
within and between control areas, RTOs, and other defined regions 
within which electricity system supply and demand are balanced in real-
time; (2) consideration of correlations of electricity prices, and 
electricity price day-to-day changes, within and between control areas, 
RTOs, and other defined regions within which electricity supply and 
demand are balanced in real time; (3) reference to historical evidence 
of actual transactions (including swaps/exchanges, etc.) wherein power 
is delivered within, imported to, or exported from, control areas, RTOs 
and sub-regions of RTOs; and (4) consideration of operational paradigms 
for obtaining transmission services and the extent to which the system 
allows for transparent access to transmission services.\239\
---------------------------------------------------------------------------

    \239\ PPL at 2-6.
---------------------------------------------------------------------------

    263. Several commenters urge the Commission to provide flexibility 
by suggesting a trading hub for an alternative geographic market. E.ON 
U.S. and PNM/Tucson state that the Commission should take regional 
commercial patterns into account when evaluating proposals to use a 
larger or smaller market, and they support allowing a seller to present 
a market power analysis specific to a trading hub.\240\
---------------------------------------------------------------------------

    \240\ E.ON U.S. at 14-15, PNM/Tucson at 8-10.
---------------------------------------------------------------------------

    264. Indianapolis P&L asks that the Commission clarify that sellers 
can propose different geographic definitions in their screen analyses. 
Indianapolis P&L states that the NOPR is unclear as to whether 
different geographic markets can be proposed for the indicative screen 
analyses or only for additional, ``second stage'' analyses, such as the 
DPT.\241\
---------------------------------------------------------------------------

    \241\ Indianapolis P&L at 5-6.
---------------------------------------------------------------------------

    265. Powerex seeks clarification on how the definition of ``home 
control area'' (the control area where the seller is located) applies 
to an entity that has small-volume contracts in multiple control areas 
remote from its physical location. Powerex asks whether contracts with 
third parties, to the extent they confer some level of ``control,'' 
create a multitude of home control areas. Powerex seeks additional 
guidance, including whether the answer to the question depends on the 
quantity of generation available under each contract, the level of 
control, whether the seller is affiliated with the transmission 
provider in that control area, or the remoteness of the contracted 
generation from the sellers' physical location.\242 \
---------------------------------------------------------------------------

    \242\ Powerex at 13-17.
---------------------------------------------------------------------------

    266. Duke requests clarification of whether first-tier markets, 
which are part of a larger RTO/ISO market (with an energy market that 
has central commitment and dispatch and Commission-approved market 
monitoring and mitigation) can be represented as the entire RTO/ISO 
market. For example, in the case of the Duke Energy Carolinas' control 
area, which is directly interconnected to the AEP transmission system, 
Duke queries

[[Page 39936]]

whether all of PJM would be the relevant first-tier market for purposes 
of determining the simultaneous import limitations into the Duke Energy 
Carolinas control area.\243\
---------------------------------------------------------------------------

    \243\ Duke at 28.
---------------------------------------------------------------------------

Commission Determination
    267. As an initial matter, we acknowledge the desire for the 
Commission to provide greater guidance to sellers wishing to argue for 
a broader or smaller market definition. We continue to believe that 
default geographic markets are adequate and sufficient for the typical 
situation. However, defaults may not be appropriate in all 
circumstances. Therefore, we will attempt to provide additional 
guidance and clarification to help inform market participants regarding 
the factors we believe are significant to consider when defining the 
market.\244\
---------------------------------------------------------------------------

    \244\ Although the following discussion generally refers to an 
expanded market (i.e., arguing that two or more default geographic 
markets constitute a single market) the same guidance is applicable 
for arguing that the market is smaller than the default geographic 
market (e.g., a load pocket).
---------------------------------------------------------------------------

    268. First, we reiterate that reaching beyond the default 
geographic market in which an entity is located can mean addressing 
additional physical and other challenges than when trading within that 
market. When assessing an alternative geographic market, the Commission 
looks for assurance that no frequently recurring physical impediments 
to trade exist within the alternative geographic market that would 
prevent competing supply in the alternative geographic market from 
reaching wholesale customers. Any proposal to use an alternative 
geographic market (i.e., a market other than the default geographic 
market) must include a demonstration regarding whether there are 
frequently binding transmission constraints during historical seasonal 
peaks examined in the screens and at other competitively significant 
times that prevent competing supply from reaching customers within the 
proposed alternative geographic market. We will require that a 
demonstration be made based on historical data and that a sensitivity 
analysis be performed analyzing under what circumstances transmission 
constraints would bind. If the seller fails to show that there are no 
frequently binding constraints at these critical times, then the 
Commission may not consider other evidence of an expanded market since 
we regard this as a necessary condition that must be satisfied to 
justify an expanded market.
    269. The Commission also considers whether there is other evidence 
that would support the existence of an alternative geographic market. 
In deciding whether customers may be considered as part of an expanded 
geographic market, the Commission will consider evidence that they can 
access the resources outside of the default geographic market on 
similar terms and conditions as those inside the default geographic 
market.
    270. Any such evidence submitted to show that the seller's 
customers have access to resources outside of their balancing authority 
area at terms and conditions similar to those at which they can access 
resources inside the balancing authority area could be empirical or it 
could point to factors that indicate a single market. For example, the 
Commission has previously stated that the operation of a single central 
unit commitment and dispatch function for the proposed geographic 
market would be an indicator of a single market. However, there are 
other ways to demonstrate that two or more balancing authority areas 
are indeed a single market. For example, other evidence of a single 
market could include a demonstration that: there is a single 
transmission rate; there is a common OASIS platform for scheduling 
transmission service across separate balancing authority areas; or 
there is a correlation of price movements between the areas being 
considered as an expanded geographic market or other information 
regarding wholesale transactions in the proposed single market. 
Evidence of active trading throughout the proposed geographic market 
would also be considered.
    271. In determining whether two or more balancing authority areas 
are a single market, the Commission would weigh, on a case-by-case 
basis, all relevant factors presented. As discussed above, there are 
several factors the Commission would consider once it has been 
established that historically there were no physical impediments to 
trade, and no one factor or factors would be dispositive. Rather, all 
factors will be considered and as a whole will indicate whether there 
exists a single market.\245\
---------------------------------------------------------------------------

    \245\ We agree with Powerex that the Commission's enumeration of 
relevant factors it would consider is not an exhaustive list. As 
stated above, no comprehensive list of factors captures all factors 
that could indicate a single market. Accordingly, the Commission 
will consider additional types of evidence that may be presented on 
a case-by-case basis.
---------------------------------------------------------------------------

    272. With regard to Puget's request that the Commission provide 
additional guidance with regard to the levels of price convergence, 
trading activity, and transmission constraints that define a market, no 
such generic finding will encompass all possibilities and, therefore, 
in all instances define the market. Accordingly, we will not attempt to 
do so here.
    273. We also reject Southern's contention that the Commission has 
somehow rendered ``illusory'' the opportunity for entities outside RTOs 
and ISOs to demonstrate a larger geographic market.\246\ The examples 
provided by the Commission of ways an entity could demonstrate a larger 
geographic market were just that: examples.\247\ The Commission does 
not require an entity proposing an alternative geographic market to 
provide evidence other than historical transmission access. Sellers and 
intervenors in both RTO/ISO and non-RTO/ISO markets may present any 
probative evidence based on historical data of transmission 
availability, wholesale sales, resource accessibility, and market 
prices.
---------------------------------------------------------------------------

    \246\ Southern at 25.
    \247\ Thus, we agree with Avista that expansion of the 
geographic market is not limited to only those instances where there 
is either: a single transmission rate; a common OASIS; or operation 
of a single central unit commitment and dispatch function.
---------------------------------------------------------------------------

    274. In response to Indianapolis Power & Light's comments, we 
clarify that when a seller submits its screen analysis, it can also 
propose an alternative analysis based on the use of a geographic market 
larger than the default geographic market. However, such proposal 
should be made in addition to, not in lieu of, the screen analysis 
based on the default geographic market.
    275. With regard to using trading hubs as alternative market areas, 
the Commission understands that numerous electricity trading hubs have 
emerged over the past few years. A trading hub is a representative 
location at which multiple sellers buy and sell power and ownership 
changes hands, typically with trading of financial and physical 
products. For physical trades, the hub may represent a specific 
delivery point or set of points. Currently only select trading hubs 
account for the majority of physical power trading although there 
remains the possibility that market demand could initiate trading hubs 
for each balancing authority area. In evaluating market power, however, 
trading hub data alone does not provide a foundation for the Commission 
to analyze transmission limitations and other transfers of energy. 
Moreover, with regard to trading hubs, the combination of physical and 
diverse financial products, the low barriers for

[[Page 39937]]

entry of new participants, and the unlimited potential for resale of 
limited physical output may not provide a reasonable measure of the 
relevant geographic market under typical situations, as a balancing 
authority area does. Therefore, while trading data may be considered in 
the illustration of relevant price correlation or of liquid trading 
activity to demonstrate that two or more balancing authority areas are 
indeed a single market, the Commission will not allow use of a trading 
hub to define a relevant geographic market.
    276. With regard to one commenter's suggestion that the Commission 
should allow (or encourage) sellers to present analytical results for 
several market definitions because the appropriate definition of the 
relevant geographic market can be conditioned on the existence or 
nonexistence of binding transmission constraints, the Commission agrees 
in principle. The Commission provides an opportunity for sellers who 
fail one or more of the initial screens to present a more thorough 
analysis using the DPT. As the April 14 Order states ``the [DPT] 
defines the relevant market by identifying potential suppliers based on 
market prices, input costs, and transmission availability, and 
calculates each supplier's economic capacity and available economic 
capacity for each season/load condition.'' \248\ In addition, in the 
Merger Policy Statement the Commission stated that the flows on a 
transmission system can be very different under different supply and 
demand conditions (e.g. peak vs. off-peak). Consequently, the amount 
and price of transmission available for suppliers to reach wholesale 
buyers at different locations throughout the network can vary 
substantially over time. If this is the case, the DPT analysis should 
treat these narrower periods separately and separate geographic markets 
should be defined for each period.\249\
---------------------------------------------------------------------------

    \248\ AEP Power Marketing, Inc., 107 FERC ] 61,018 at P 106.
    \249\ Merger Policy Statement, FERC Stats. & Regs. Regulations 
Preambles July 1996-December 2000 ] 31,044 at 30,132.
---------------------------------------------------------------------------

    277. The Commission believes that the DPT can address the dynamic 
nature of markets. Under the DPT, the amount and price of transmission 
available for suppliers to reach wholesale buyers at different 
locations throughout the network during different season/load 
conditions (e.g., peak vs. off-peak) can be analyzed. For example, an 
area may become constrained only during the highest load levels, in 
which case the relevant geographic market could differ across seasons, 
and separate geographic markets could be defined for each period. 
However, as discussed earlier, in an effort to provide as much 
regulatory certainty as possible, the Final Rule adopts as the default 
geographic market the balancing authority area or the RTO footprint, as 
applicable, but allows sellers or intervenors to propose alternative 
markets based on historical transmission and sales data.
    278. We clarify in response to Powerex that sellers should do 
market power studies for each balancing authority area where they own 
or control assets (i.e., should study all balancing authority areas 
where generation assets they own or control are located) regardless of 
the quantity or location of generation they control (subject to the 
terms adopted herein regarding Category 1 sellers). Also, to the extent 
a market power study is required, sellers should study each balancing 
authority area where they own or control assets regardless of whether 
the seller is affiliated with the transmission provider in that 
balancing authority area. The Commission also clarifies for Duke that 
if the first-tier markets for a seller (whether or not the seller is a 
member of the RTO) are part of a larger RTO/ISO market, all of the RTO/
ISO market would be a relevant first-tier market for purposes of 
determining the simultaneous import limitations.
d. Specific Issues Related to Power Pools and SPP
Commission Proposal
    279. In the NOPR, the Commission proposed to continue its practice 
of designating an RTO/ISO in which a seller is located as the default 
relevant geographic market if the RTO/ISO has sufficient market 
structure and a single energy market with Commission approved market 
monitoring and mitigation.
Comments
    280. A number of commenters urge the Commission to consider power 
pools as geographic market areas. Midwest Energy claims that, ``under 
current Commission policy, sellers of power in RTOs/ISOs with a full-
fledged single central commitment and dispatch system are allowed to 
treat the full RTO footprint as the relevant geographic market, thereby 
facilitating qualification for market-based rates. Sellers in a 
Commission-approved RTO without a single central commitment and 
dispatch system are relegated to a relevant market defined by their own 
control area.'' \250\ Midwest Energy urges the Commission to consider 
changing its existing policy to create a presumption that the relevant 
geographic market for a Commission-approved RTO is the region covered 
by a single transmission tariff.\251\ Alternatively, Midwest Energy 
states that the Commission could require, in addition to a regional 
tariff, the implementation of a Commission-approved market monitor and 
a centrally dispatched energy imbalance market. It states that these 
changes would allow sellers to treat the Southwest Power Pool (SPP) 
region as the relevant geographic market.
---------------------------------------------------------------------------

    \250\ Midwest at 1-3.
    \251\ Midwest at 1-3, 4-8.
---------------------------------------------------------------------------

    281. Westar states that the Commission should find that a 
transmission region with a single OATT, non-pancaked transmission 
rates, a common OASIS platform for scheduling transmission, and 
approved market monitoring (e.g., SPP) presumptively qualifies as a 
single region for purposes of the market power screens. Westar states 
that although the NOPR identifies single unit commitment and/or 
centralized dispatch of generation to be an important characteristic of 
a regional market, the Commission has not always done so. For example, 
the Commission did not identify this as a defining characteristic when 
it accepted other RTOs/ISOs as a single region for market-based rate 
purposes, such as New England. The Commission also did not rely upon 
centralized dispatch in authorizing market-based power sales across the 
California, New York or PJM markets. Westar states that the Commission 
should find that SPP meets the criteria for a single market once its 
energy imbalance market (EIM) becomes operational.\252\
---------------------------------------------------------------------------

    \252\ Westar at 3-6.
---------------------------------------------------------------------------

    282. In its reply comments, Southwest Coalition disagrees with 
those commenters requesting that SPP qualify as a single geographic 
region for sellers in its region once its EIM is operational. Southwest 
Coalition states that Westar has not presented any evidence for the 
Commission to change course with SPP in this rulemaking. It asserts 
that SPP currently has underway a variety of market implementation 
proceedings, of which Westar is a party, through which the Commission 
can make a reasoned decision regarding SPP's status. As such, Southwest 
Coalition states that this generic rulemaking proceeding is not the 
appropriate vehicle for considering Westar's request. In addition, 
Southwest Coalition states that Westar's request represents an improper 
request for rehearing of the Commission's March 20, 2006 Order in

[[Page 39938]]

SPP's market implementation proceeding. Southwest Coalition requests 
that, if the Commission were to consider Westar's request in this 
proceeding, the Commission should reject Westar's request for a 
Commission finding that SPP is a single geographic region for purposes 
of the Commission's market power screens.\253\
---------------------------------------------------------------------------

    \253\ Southwest Industrial Customer Coalition reply comments at 
2-9.
---------------------------------------------------------------------------

    283. Puget argues that applying the control area default to 
utilities in the Pacific Northwest is arbitrary, and does not result in 
an accurate measurement of a seller's potential market power in the 
region's energy markets. According to Puget, the relevant geographic 
market for the purpose of measuring horizontal market power in the 
Pacific Northwest is the United States portion of the Northwest Power 
Pool, which is dominated by a transmission system operated by 
Bonneville Power Administration. Puget submits that many of the 
criteria outlined in the NOPR--particularly those addressing parallel 
price movements, single transmission rates, and active trading--are met 
in this geographic region. Utilities in the Pacific Northwest would 
like to have the opportunity to make a showing to the Commission that 
the relevant geographic market for measuring market power in their 
region is an area other than their home and first-tier control 
areas.\254\
---------------------------------------------------------------------------

    \254\ Puget at 9-11.
---------------------------------------------------------------------------

Commission Determination
    284. We decline to address whether additional regions of the 
country qualify as relevant geographic markets. Through this Final 
Rule, we set forth several examples of criteria that sellers can use in 
proposing an alternative geographic market. Individual sellers can 
challenge our default geographic market and provide evidence to support 
their proposal. Intervenors will have the opportunity to comment prior 
to the Commission rendering a decision.
e. RTO/ISO Exemption
Commission Proposal
    285. In the April 14 Order, the Commission concluded that it would 
no longer exempt sellers located in markets with Commission-approved 
market monitoring and mitigation from providing generation market power 
analyses, on the basis that requiring sellers located in such markets 
to submit screen analyses provides an additional check on the potential 
for market power.\255\ The Commission did not address this point in the 
NOPR.
---------------------------------------------------------------------------

    \255\ 107 FERC ] 61,018 at P 186. The Commission had previously 
stated that all sales, including bilateral sales, into an ISO or RTO 
with Commission-approved market monitoring and mitigation would be 
exempt from the Supply Margin Assessment test and, instead, would be 
governed by the specific thresholds and mitigation provisions 
approved for the particular market. AEP Power Marketing, Inc., 97 
FERC ] 61,219 at P 176 (2001).
---------------------------------------------------------------------------

Comments
    286. In their comments in this proceeding, Reliant, NRG and 
FirstEnergy urge the Commission to reinstate the exemption.\256\ 
Reliant states that reinstating the exemption would be appropriate 
because real-time market monitoring by an independent market monitor 
consistent with Commission-approved rules and Commission-approved 
targeted mitigation address identification of market power concerns as 
well as mitigation of market power in those markets and, therefore, 
eliminate the value of any separate market power analysis submitted by 
an individual seller. Reliant states that Commission-approved market 
monitoring and mitigation provide the Commission with a better and more 
sophisticated picture of market power issues in RTO/ISO markets as 
compared to a seller's market power analysis, which looks only at 
market power at a fixed moment in time.
---------------------------------------------------------------------------

    \256\ Reliant at 6-7; NRG at 7; and FirstEnergy at 33.
---------------------------------------------------------------------------

    287. Reliant states that if the Commission decides not to reinstate 
the exemption, it is critical that the Commission continue to use RTO/
ISO markets as the default geographic market for sellers with 
generation located in those markets. Reliant states that the key to the 
determination of relevant geographic markets is the extent to which 
sellers can compete in the defined market. RTO/ISO markets with 
centralized markets provide a platform for all sellers located in the 
pertinent RTO/ISO market to compete. Thus, Reliant states that it is 
entirely appropriate to consider such markets as the default market 
unless and until an intervenor can show that this is no longer 
appropriate (e.g., due to transmission constraints).\257\
---------------------------------------------------------------------------

    \257\ Reliant at 6-7.
---------------------------------------------------------------------------

    288. In its reply comments, PSEG states that while it believes that 
the RTO/ISO exemption would be warranted at least for regions with 
pervasive market monitoring unit (MMU) oversight such as PJM, it 
recognizes that some affected parties may not be comfortable with a 
blanket exemption. It suggests that the Commission's regulations should 
take account of the fact that the Commission has approved comprehensive 
MMU oversight of markets and that MMUs take their duties seriously and 
routinely exercise their authority. Accordingly, PSEG proposes that 
evidence of active MMU oversight supply the basis for obviating the 
need to conduct a market power study for a particular zone or sub-zone 
of an RTO or ISO.\258\
---------------------------------------------------------------------------

    \258\ PSEG reply comments at 5-6.
---------------------------------------------------------------------------

    289. APPA/TAPS, in contrast, state that reinstating the RTO/ISO 
exemption would represent an abdication of the Commission's 
responsibilities.\259\
---------------------------------------------------------------------------

    \259\ APPA/TAPS reply comments at 2-3.
---------------------------------------------------------------------------

Commission Determination
    290. The Commission declines the request that it reinstate the pre-
April 14 Order exemption for sellers located in markets with 
Commission-approved market monitoring and mitigation from providing 
generation market power analyses. The Commission will continue to 
require generation market power analyses from all sellers, including 
those in RTO/ISO markets. All sellers are required to receive 
authorization from the Commission prior to undertaking market-based 
rate sales, and as discussed herein, all new applicants for market-
based rate authority are required to, among other things, provide a 
horizontal market power analysis. The first step for a seller seeking 
market-based rate authority is to file an application to show that it 
and its affiliates do not have, or have adequately mitigated, market 
power. Sellers can refer to RTO/ISO monitoring and mitigating as a 
factor. We believe that a single market with Commission-approved market 
monitoring and mitigation and transparent prices provides added 
protection against a seller's ability to exercise market power but 
cannot replace the generation market power analysis.
    291. To address Reliant's concern, we note that, as discussed 
above, we will use RTO/ISO markets (including Commission findings with 
regard to RTO/ISO submarkets) as the default geographic market for the 
indicative screens for sellers with generation in those markets.
8. Use of Historical Data
Commission Proposal
    292. The Commission proposed in the NOPR to retain the ``snapshot 
in time'' approach for the indicative screens, so that sellers are 
required to use the most recently available unadjusted 12 months' 
historical data. The

[[Page 39939]]

Commission stated that historical data are more objective, readily 
available, and less subject to manipulation than future projections. 
The Commission proposed to continue to permit sellers to make 
adjustments to data that are essential to perform the indicative 
screens provided that the seller fully justifies the need for the 
adjustments, justifies the methodology used, provides all workpapers in 
support, and documents the source data.
    293. However, the Commission proposed to allow, for the DPT 
analysis, sellers and intervenors to account for changes in the market 
that are known and measurable at the time of filing.\260\ The 
Commission noted that this proposal mirrors the Commission's approach 
in connection with its merger analysis. Sellers and intervenors 
proposing known and measurable changes to be considered in the DPT 
analysis would bear the burden of proof for their adjustments to 
historical data. The Commission sought comment on whether the 
Commission should provide a limitation on the time period past the 
historical test period for which sellers can account for changes, what 
that time period should be, and how flexible or inflexible that 
limitation should be. In addition, the Commission sought comment on 
exactly what types of changes should be allowed and under what 
circumstances.
---------------------------------------------------------------------------

    \260\ See 18 CFR 35.13(a).
---------------------------------------------------------------------------

Comments
    294. Various commenters generally support the Commission's proposal 
to use historical data for the indicative screens and allow known and 
measurable changes for the DPT.\261\ Some suggestions made as to what 
should be considered known and measurable changes include: Allowing 
only changes that occur between updated market power analysis filings 
\262\ and allowing only publicly available data or company 
information.\263\ Powerex expresses concern that known and measurable 
changes may not be publicly available.\264\ PG&E suggests that the 
Commission evaluate on a case-by-case basis whether the seller or 
intervenor can prove that the change is both foreseeable and 
reasonable. It says that the Commission should not impose a time 
restriction on such changes provided that the seller provides the 
necessary support for changes that it claims are known and 
measurable.\265\
---------------------------------------------------------------------------

    \261\ See, e.g., EEI at 23, PPL at 17-19; Powerex at 18-19.
    \262\ See, e.g., Ameren at 6. Ameren proposes that if a seller 
chooses to rely on an historical period with no changes, the 
Commission should honor that choice and not allow intervenors to 
introduce suggested known and measurable changes. Conversely, if a 
seller proposes to adjust the historical period for certain known 
and measurable changes, Ameren states that the Commission should 
permit intervenors to introduce competing known and measurable 
changes. Id. at 6-7.
    \263\ Drs. Broehm and Fox-Penner at 12-13 (any adjustments to 
historical base year must be known and measurable at the time of 
filing; new capacity additions should only be accounted for if they 
are on-line or under construction).
    \264\ Powerex at 18-19.
    \265\ PG&E at 9-10.
---------------------------------------------------------------------------

    295. A number of commenters suggest that sellers should be 
permitted to account for known and measurable changes in both the 
indicative screens and the DPT.\266\ Southern states that the 
Commission ``should not * * * restrict the ability of parties to 
provide the Commission with the best possible information and 
analysis.'' \267\ Duke states that in all instances the objective 
should be to obtain the most accurate and timely assessment of the 
seller's ability to exercise market power under current market 
conditions.\268\
---------------------------------------------------------------------------

    \266\ PG&E at 2; Southern at 25-26; Duke at 26; NRECA at 21-23.
    \267\ Southern at 26.
    \268\ Duke at 26.
---------------------------------------------------------------------------

    296. NRECA states that the screens should incorporate imminent 
changes and that an example of known and measurable changes that should 
be included in initial applications and triennial filings is the 
capacity freed up by expiring long-term contracts. It submits that 
these contracts will expire on a known schedule and, if the market is 
competitive, the seller should not be allowed to assume that the 
capacity will remain committed to the buyer.\269\
---------------------------------------------------------------------------

    \269\ NRECA at 21-23. See also APPA/TAPS at 13-15.
---------------------------------------------------------------------------

    297. PPL argues that long-term contracts should retain the current 
definition as those expiring in one year or more, and recommends not 
considering contracts that take effect after one year but before the 
triennial update is due. It argues that buyers could withhold signing 
contracts and force a market power finding. PPL also notes that a 
notice of change in status must be filed at the expiration of contracts 
that increase the seller's capacity by 100 MW or more and that the 
Commission can initiate a section 206 investigation at that point if 
need be.\270\
---------------------------------------------------------------------------

    \270\ PPL reply comments at 3-4.
---------------------------------------------------------------------------

Commission Determination
    298. We will continue to require the use of historical data for 
both the indicative screens and the DPT in market-based rate cases. The 
indicative screens are designed as a tool to identify those sellers 
that raise no generation market power concerns and can otherwise be 
considered for market-based rate authority. Accordingly, the indicative 
screens are conservative in nature and not generally subject to debates 
over projected data, which may unnecessarily prolong proceedings and 
create regulatory uncertainty. However, in light of adopting a regional 
approach with regard to regularly scheduled updated market power 
analyses, we will require the use of the actual historical data for the 
previous calendar year. Requiring all sellers in a region to provide 
analyses using the same data set further enhances the Commission's 
ability to evaluate market power and identify any discrepancies between 
market studies.
    299. After careful consideration of the comments received, the 
Commission will not adopt the NOPR proposal that the DPT analysis allow 
sellers and intervenors to account for changes in the market that are 
known and measurable at the time of filing. Instead, the Commission 
will adopt its current practice that sellers are required to use, in 
the preparation of a DPT for a market-based rate analysis, unadjusted 
historical data and, consistent with the above discussion, the 
Commission will require the use of the actual historical data for the 
previous calendar year. The Commission has stated that historical data 
are more objective, readily available, and less subject to manipulation 
than future projections.
    300. We acknowledge that the Commission's approach in its merger 
analysis requires applicants and intervenors to account for changes in 
the market that are known and measurable at the time of filing. 
However, we find that the purpose of using the DPT in market-based rate 
proceedings is different from that in merger analysis. Intrinsically, a 
merger analysis is forward-looking to identify what effect, if any, 
there will be on competition if the proposed merger is consummated. 
Even though the Commission has the ability to reopen a merger 
proceeding under its section 203(b) authority, it is difficult and 
costly to undo a merger, so the Commission is cognizant of the need to 
analyze what might happen as a result of a proposed merger and put any 
necessary mitigation in place prior to consummation of the merger.
    301. In contrast, the market-based rate analysis is a ``snapshot in 
time'' approach. When the Commission evaluates an application for 
market-based rate authority, the Commission's focus is on whether the 
seller passes both of the indicative screens based on unadjusted 
historical data. Likewise,

[[Page 39940]]

when a seller fails one of the screens and the Commission evaluates 
whether that seller passes the DPT, the Commission's focus is on 
whether the seller passes the DPT based on unadjusted historical data. 
The Commission's grant of market-based rate authority is conditioned, 
among other things, on the seller's obligation to inform the Commission 
of any change in status from the circumstances the Commission relied 
upon in granting it market-based rate authority. As such, the 
Commission's market-based rate program is designed to require sellers 
to report, and enable the Commission to examine, changes in facts and 
circumstances on an ongoing basis. Such a reporting requirement 
provides the Commission with ongoing monitoring in addition to its 
right to require any market-based rate seller to provide an updated 
market power analysis at any time. Accordingly, the market-based rate 
change in status reporting requirement allows the Commission to 
evaluate changes when they actually happen rather than relying on 
projections, making it unnecessary and redundant for the Commission to 
allow sellers to account for known and measurable changes in the DPT 
for market-based rate purposes. For these reasons and the reasons 
explained in the April 14 and July 8 Orders and existing Commission 
precedent, the Commission reaffirms that the indicative screens and DPT 
analyses should be based on unadjusted historical data.
9. Reporting Format
Commission Proposal
    302. In the NOPR, the Commission proposed to require all sellers to 
submit the results of their indicative screen analysis in a uniform 
format to the maximum extent practicable and appended a proposed 
format. This format, provided in Appendix C of the NOPR, was intended 
to promote consistency and aid the Commission in the decision-making 
process. The Commission sought comment on this proposal.
Comments
    303. Although only a few comments were received on this topic, 
those comments support the proposal to adopt a uniform reporting format 
for the indicative screens. APPA/TAPS suggest that the proposed uniform 
format should help all market participants, especially when assessing 
the filings of a number of public utilities as part of the proposed 
regional review process. APPA/TAPS state that the uniformity should 
also help the Commission analyze market-based rate filings on a 
consistent basis, thus increasing market participant confidence in 
those assessments.\271\ Other commenters concur with the Commission's 
proposal for a uniform reporting format. They state that a uniform 
reporting format will increase consistency and thus aid the Commission 
in its decision making process.\272\
---------------------------------------------------------------------------

    \271\ APPA/TAPS at 35.
    \272\ Drs. Broehm and Fox-Penner at 12.
---------------------------------------------------------------------------

    304. One commenter suggests formatting and presentation changes to 
the NOPR's Appendix C reporting form. These changes include creating 
sections for items such as the calculation of seller and market 
uncommitted capacity and rearranging some in a more logical 
fashion.\273\
---------------------------------------------------------------------------

    \273\ Dr. Pace at 8-9.
---------------------------------------------------------------------------

Commission Determination
    305. We will adopt the reporting format as proposed in the NOPR, 
maintaining the same order of items as in the form provided in Appendix 
C of the NOPR, but note that this form now appears as Appendix A of 
this Final Rule. We believe standardizing the submission format has 
benefits to all market participants. As noted, it appears that 
commenters as well are generally supportive of this proposal to require 
all sellers to submit the results of their indicative screen analyses 
in a uniform format.
    306. Also, we will adopt many of the formatting changes suggested 
in the comments. The row letter will be the first column and a better 
delineation of sections will increase the comprehensibility of the 
form. The revised form can be found in Appendix A.\274\
---------------------------------------------------------------------------

    \274\ The ``Workpapers'' column is meant to provide an easy way 
to find sources and ensure that all submissions are properly 
sourced. Hence, the items in that column (e.g., ``Workpaper 5'') 
were merely meant to be illustrative and do not require that 
information be submitted on specific workpapers or that workpapers 
be submitted in a particular order.
---------------------------------------------------------------------------

10. Exemption for New Generation (Formerly Section 35.27(a) of the 
Commission's Regulations)
a. Elimination of Exemption in Section 35.27(a)
Commission Proposal
    307. The Commission's regulations provide that any public utility 
seeking authorization to engage in market-based rate sales is not 
required to demonstrate a lack of market power in generation with 
respect to sales from capacity for which construction commenced on or 
after July 9, 1996.\275\ In the NOPR, the Commission noted that when it 
established the exemption in Order No. 888 it indicated that it would 
consider whether a seller citing Sec.  35.27(a) nevertheless possesses 
horizontal market power if specific evidence is presented by an 
intervenor.\276\
---------------------------------------------------------------------------

    \275\ 18 CFR 35.27(a). The regulation reads: ``Notwithstanding 
any other requirements, any public utility seeking authorization to 
engage in sales for resale of electric energy at market-based rates 
shall not be required to demonstrate any lack of market power in 
generation with respect to sales from capacity for which 
construction has commenced on or after July 9, 1996.
    \276\ NOPR at P 67.
---------------------------------------------------------------------------

    308. The Commission stated in the NOPR that although it remains 
committed to encouraging new entry of generation, it is concerned that 
the continued use of the Sec.  35.27(a) exemption may become too broad 
and, over time, would encompass all market participants as all pre-July 
9, 1996 generation is retired. Accordingly, the Commission proposed in 
the NOPR to eliminate the exemption in Sec.  35.27(a) and to require 
that all new sellers seeking market-based rate authority on or after 
the effective date of the Final Rule and all sellers filing updated 
market power analyses on or after the effective date of the Final Rule 
must provide a horizontal market power analysis of all of their 
generation, whether or not it was built after July 9, 1996. Because the 
Commission allows a seller to make simplifying assumptions where 
appropriate and to submit a streamlined analysis, the Commission 
explained that any additional burden imposed on sellers by this reform 
would be minimal. In addition, the Commission anticipated that those 
entities that otherwise would have relied on the exemption would, in 
most cases, qualify as Category 1 sellers and therefore no longer be 
required to file updated market power analyses as a routine matter. The 
Commission sought comment on this proposal.
Comments
    309. Many commenters support the Commission's proposed elimination 
of the Sec.  35.27(a) exemption, stating that there should be a level 
playing field for market-based rate sellers so that all market 
participants would be required to perform the generation market power 
screens.\277\ A number of commenters support the Commission's position 
that there is a valid concern that over time the exemption would 
encompass all generation as older generating units are

[[Page 39941]]

retired and new generation is built.\278\ Several commenters state that 
the Commission correctly observes that the indefinite continuation of 
the exemption would ultimately result in the automatic grant of market-
based rate authority to all sellers as pre-1996 generation is 
retired.\279\ They further state that eliminating the exemption will 
not impose significant new burdens, deter new entry into a market, or 
create any unreasonable disincentive or impediment for the construction 
of future generating capacity.\280\ Contrary to the assertions of 
several commenters, FirstEnergy states that the elimination would 
encourage merchant power developers to expand generation in markets 
where they do not already have a dominant position which, in turn, 
would dilute market power concerns in these markets.
---------------------------------------------------------------------------

    \277\ Progress Energy at 2; PG&E at 10; FirstEnergy at 9; TDU 
Systems at 2; New Jersey Board at 2; NASUCA at 7; Drs. Broehm/Fox-
Penner at 13.
    \278\ See PG&E at 10; APPA/TAPS at 27; NRECA at 11; Carolina 
Agencies at 1.
    \279\ APPA/TAPS at 27; NRECA at 11; Carolina Agencies at 1.
    \280\ See FirstEnergy at 10; APPA/TAPS at 27; NRECA at 11; 
Carolina Agencies at 1.
---------------------------------------------------------------------------

    310. NRECA and APPA/TAPS maintain that, despite EPSA's, Mirant's, 
and PPL's assertions to the contrary,\281\ the Commission did not 
create the exemption as an incentive to encourage new generation 
investment.\282\ APPA/TAPS elaborates further, agreeing with the 
Commission that many new entrants would qualify as Category 1 sellers 
and, therefore, would not have to submit updated market power analyses 
and that other entrants could make simplifying assumptions to 
demonstrate that they qualify for market-based rate authority.\283\ 
These commenters contend that the benefits of eliminating the exemption 
far outweigh any added burdens to ensure that all market participants 
are treated equally and to ensure that rates for jurisdictional sellers 
are just and reasonable.\284\
---------------------------------------------------------------------------

    \281\ EPSA at 12-13; Mirant at 11; PPL at 19-20.
    \282\ NRECA reply comments at 11; APPA/TAPS reply comments at 
16-17.
    \283\ See APPA/TAPS at 27.
    \284\ APPA/TAPS at 27; NRECA at 11; Carolina Agencies at 1.
---------------------------------------------------------------------------

    311. In support of the elimination of the Sec.  35.27(a) exemption, 
NASUCA acknowledges that under current procedures, if all the 
generation owned or controlled by an applicant for market-based rate 
authority and its affiliates in the relevant control area is new 
generation, such seller is not required to provide a horizontal market 
power analysis because of the exemption under Sec.  35.27(a).\285\ 
NASUCA asserts that under the current rule, there is no limit on the 
amount of post-July 9, 1996 generation that could be exempt from the 
Commission's analysis of market power. In addition, a commenter 
explains that the potential to exercise market power has no relation to 
whether generating plants were built before or after 1996.\286\ ELCON 
suggests that generators that were built after July 9, 1996 are capable 
of exercising market power.\287\ In addition, FirstEnergy points out 
that merchant power plant developers have begun to aggregate fleets of 
newer generating plants to which this exemption is applicable, and may 
now be able to exercise generation market power.\288\ PG&E adds, ``in 
situations where all generation owned or controlled by an applicant and 
its affiliates in the relevant market is new generation, should they 
control sufficient generation, the applicants and its affiliates may 
freely exercise market power.'' \289\ In addition, Morgan Stanley 
supports elimination of the exemption, stating that maintaining the 
exemption would have unintended consequences going forward.\290\
---------------------------------------------------------------------------

    \285\ NASUCA at 7.
    \286\ Drs. Broehm/Fox-Penner at 13.
    \287\ ELCON at 6.
    \288\ See FirstEnergy at 9-10.
    \289\ PG&E at 10.
    \290\ Morgan Stanley at 13-14.
---------------------------------------------------------------------------

    312. Among those who oppose elimination of the exemption, 
Constellation asserts that it would send an unfavorable signal to 
market participants that the rules may be changed with a retroactive 
effect, which in turn would deter investment.\291\ Constellation also 
contends that the Commission offers no support and/or analysis to 
demonstrate its inference that older generating units will be retired 
in significant quantities to make a substantial difference to the 
screening analysis of any seller. PPL submits, among other ill-effects, 
that the elimination will deter investment in areas where there is a 
limited supply and the new entrant may be deemed pivotal. In addition, 
PPL contends that some sellers relied on the presumption that they 
would not need to demonstrate a lack of market power in financing, 
constructing, and operating their new power plants.\292\
---------------------------------------------------------------------------

    \291\ Constellation at 30.
    \292\ PPL at 19-20.
---------------------------------------------------------------------------

    313. EPSA opposes the elimination of the exemption under Sec.  
35.27(a). EPSA states that the electric industry needs incentives for 
new generation and does not need disincentives if capital is to be 
invested on a timely basis to meet future demand and enhance 
competition.\293\ EPSA asserts that the exemption encourages the 
development of competitive supply outside of organized markets.\294\ 
Similarly, NRG contends that the elimination of the Sec.  35.27(a) 
exemption will delay and deter investment in load pockets. NRG also 
argues that eliminating the exemption runs counter to the Commission's 
policy of encouraging investment in electric power infrastructure to 
enhance reliability and market liquidity.\295\
---------------------------------------------------------------------------

    \293\ EPSA at 12.
    \294\ EPSA reply comments at 6.
    \295\ NRG at 2.
---------------------------------------------------------------------------

    314. In addition, EPSA argues that the purpose of the exemption was 
to encourage new generation investment by competitive suppliers, 
especially in areas of the country that are mostly dominated by 
utility-owned generation.\296\ Specifically, EPSA explains that it is 
in these regions of the country where affiliated generation is largely 
treated as native load and, thus, is excluded from the market power 
analysis even though it represents most of the capacity in the 
region.\297\ EPSA explains that, even if a small increment of 
competitive supply is introduced into the market, the analysis might 
detect market power when measured against relatively small existing 
generation. Therefore, without the exemption, a new competitive 
supplier would fail the test and would have to utilize cost-based 
rates.\298\
---------------------------------------------------------------------------

    \296\ EPSA at 13.
    \297\ In its reply comments NASUCA disagrees, submitting that 
there are other regions where a seller with a fleet of newer 
exempted generating plants could exercise market power or bid the 
output strategically to drive prices up. NASUCA reply comments at 4-
5.
    \298\ EPSA at 13.
---------------------------------------------------------------------------

    315. Allegheny argues that the Commission overlooks the reason why 
it initially adopted the exemption. Allegheny states that, in Order No. 
888, the Commission determined that long-term generation markets are 
competitive.\299\ Allegheny further argues that ``the Commission cannot 
`gloss over' its prior reasoning without discussion, and without 
showing that there has been a fundamental change in facts and 
circumstances that have [sic] caused long-term markets to be no

[[Page 39942]]

longer competitive.'' \300\ PPL asserts that the Commission in Order 
No. 888 recognized the power that the opportunity of free entry has to 
eliminate market power concerns and stated that open access 
advancements removed structural impediments for new entrants competing 
with existing market participants.\301\
---------------------------------------------------------------------------

    \299\ Allegheny at 8-9 (citing Promoting Wholesale Competition 
Through Open Access Non-discriminatory Transmission Services by 
Public Utilities and Recovery of Stranded Costs by Public Utilities 
and Transmitting Utilities, Order No. 888, FERC Stats. & Regs., 
Regulations Preambles, January 1991-June 1996 ] 31,036 at 31,657 
(1996), order on reh'g, Order No. 888-A, FERC Stats. & Regs. 
Regulations Preambles July 1996-December 2000 ] 31,048 (1997), order 
on reh'g, Order No. 888-B, 81 FERC ] 61,248 (1997), order on reh'g, 
Order No. 888-C, 82 FERC ] 61,046 (1998), aff'd in part and rev'd in 
part sub nom. Transmission Access Policy Study Group v. FERC, 225 
F.3d 667 (D.C. Cir. 2000), aff'd sub nom. New York v. FERC, 535 U.S. 
1 (2002)).
    \300\ Allegheny at 9 (citation omitted).
    \301\ PPL at 20.
---------------------------------------------------------------------------

    316. Mirant and EPSA expand on arguments that eliminating the 
exemption will deter investment. They argue that, when reserve levels 
are tight in a control area where the host utility has lost or forgone 
its market-based rate authority, a competitive supplier would have to 
weigh the risks as to whether the Commission would authorize it to make 
market-based rate sales if it were to build a new asset in that control 
area.\302\ They contend that there is no incentive for a competitive 
supplier to build new generation if its sales will be mitigated at some 
level of cost-based rates.\303\ In particular, Mirant explains that if 
a municipal utility issued a request for proposals (RFP) for 600 MW of 
power commencing in 2010 and terminating in 2020, with the current 
exemption competitive suppliers could bid on the RFP knowing that the 
supplier would be authorized to sell the output of its new generating 
station at market-based rates. However, Mirant asserts that if the 
exemption were eliminated, a supplier would have to get Commission 
approval for market-based rate sales prior to bidding on the RFP. \304\
---------------------------------------------------------------------------

    \302\ Mirant at 11-12; EPSA at 13-14.
    \303\ EPSA at 13; Mirant at 12.
    \304\ Mirant at 11-12. Mirant elaborates: ``In calculating the 
pivotal supplier and market share screens, an applicant is allowed 
to deduct from its installed capacity the amount of capacity that is 
committed under a long-term sale, but the seller is presented with a 
Catch-22. The seller cannot enter into a long-term sales contract at 
market-based rates without prior Commission authorization, but the 
seller cannot pass the applicable indicative screens without 
deducting the amount of the capacity sold under long-term contract. 
Retaining the exemption eliminates this problem and is consistent 
with Commission precedent regarding competitive forward markets.'' 
Id. at 12.
---------------------------------------------------------------------------

    317. Mirant disagrees with the Commission's contention that 
eliminating the exemption would not affect many sellers and that the 
cost of compliance would be minimal. Mirant states that five of its 
subsidiaries would have to file updated market power analyses if the 
exemption were eliminated because they own more than 500 MW in the 
relevant market or control area and would not qualify as Category 1 
sellers. Mirant argues that its cost of compliance would increase 
because it would have to prepare four updated market power analyses, 
each costing $20,000 to prepare and file.\305\ In its reply comments, 
APPA/TAPS state that Mirant's increased cost is paltry compared to the 
over $3.4 billion in generation revenues reported by Mirant in 2005, 
which APPA/TAPS suggest is in no small part due to Mirant's market-
based rate sales.\306\
---------------------------------------------------------------------------

    \305\ Mirant at 11.
    \306\ APPA/TAPS reply comments at 17.
---------------------------------------------------------------------------

    318. Some commenters contend that the Commission's concern that 
over time all older generation will be retired and the Commission will 
be unable to analyze sellers for market power is not a valid concern in 
the immediate or mid-term; they state that the most recent retirement 
announcements concern generation assets that were built in the 1940s 
and 1950s.\307\ PPM and Allegheny argue that the Commission offers no 
evidence or observations to quantify the magnitude of future 
retirements.\308\ Some commenters assert that, in order for this 
speculative concern to become realistic, the retirement of generating 
units that were constructed in the 1980s would have to become 
commonplace, and it will take decades for this situation to 
materialize. As such, they suggest that the Commission revisit this 
issue in 5 to 10 years rather than act prematurely.\309\
---------------------------------------------------------------------------

    \307\ Mirant at 10; EPSA at n.2, citing for example: http://pjm.com/planning/project-queues/gen-retirements/20060601-pjm-gen-retir-list-public-future.pdf
.

    \308\ PPM at 6; Allegheny at 8.
    \309\ EPSA at 15; Mirant at 10.
---------------------------------------------------------------------------

    319. PPM suggests that, if the Commission wishes to limit the 
overall amount of generation that is exempt for purposes of conducting 
a horizontal market power analysis, an alternative approach would be to 
keep the exemption and phase in exempted units over time. Thus, units 
that were built after 1996 but before 1999 would lose the exemption in 
2010, while facilities built in 2001 would lose it in 2015, and so 
on.\310\
---------------------------------------------------------------------------

    \310\ PPM at 6.
---------------------------------------------------------------------------

Commission Determination
    320. The Commission adopts the proposal set forth in the NOPR and 
eliminates the exemption provided in Sec.  35.27(a). All sellers 
seeking market-based rate authority, or filing updated market power 
analyses, on or after the effective date of this Final Rule must 
provide a horizontal market power analysis for all of the generation 
they own or control. As a number of commenters recognize, over time the 
exemption would become too broad and would encompass all market 
participants as pre-July 9, 1996 generation is retired. In addition, we 
note that even assuming for the sake of argument that there are not a 
large number of retirements, the current exemption would allow sellers 
to grow unabated as load increases and could result in such sellers 
gaining a dominant position in the market without being subject to any 
horizontal market power analysis. Thus, continuing the exemption would 
result in unintended consequences where all sellers would be given an 
automatic presumption that they lack market power in generation. 
Accordingly, the Commission finds that eliminating the exemption in 
Sec.  35.27(a) and requiring every new seller to submit a generation 
market power analysis will allow the Commission to ensure that the 
seller does not have market power in generation.\311\
---------------------------------------------------------------------------

    \311\ We note that the Commission may change its policy if it 
provides, as it does here, a reasoned analysis indicating that prior 
policies are being deliberately changed and the basis for that 
change. E.g., B&J Oil and Gas v. FERC, 353 F.3d 71 (D.C. Cir. 2004).
---------------------------------------------------------------------------

    321. We do not believe that this change will have an adverse effect 
on the majority of sellers that have previously relied on the Sec.  
35.27(a) exemption. The sellers that have taken advantage of the 
exemption will largely qualify as Category 1 sellers, and thus will be 
unaffected to the extent that they will not be required to file a 
regularly scheduled updated market power analysis. For those sellers 
seeking market-based rate authority for the first time (e.g., building 
new generation facilities), and those that do not qualify as Category 1 
sellers, there are several mechanisms or alternatives that can help to 
minimize the burden of submitting a horizontal market power analysis. 
For example, a seller, where appropriate, can make simplifying 
assumptions, such as performing the indicative screens assuming no 
import capacity or treating the host balancing authority area utility 
as the only other competitor.\312\ We expect that, for most sellers, 
the cost of compliance and document preparation occasioned by the 
elimination of Sec.  35.27(a) will not be burdensome. To the extent 
that there are greater costs for some sellers, we find that the benefit 
of ensuring that markets do not become less competitive over time 
outweighs any additional costs. Equally important, the elimination of 
Sec.  35.27(a) will place all sellers on the same footing. On this 
basis, we disagree with commenters that eliminating the exemption would 
send an unfavorable

[[Page 39943]]

signal to market participants and deter investment.
---------------------------------------------------------------------------

    \312\ See April 14 Order, 107 FERC ] 61,018 at P 69, 117.
---------------------------------------------------------------------------

    322. We also disagree with commenters that find our rationale for 
adopting the exemption in 1996 necessarily constrains our decision 
making at this time. In light of our experience over the past decade 
and our desire to have a more rigorous market-based rate program, 
combined with the concern that over time generation will be retired, we 
believe a more conservative approach for granting market-based rate 
authority is appropriate and will provide us a better means to ensure 
that customers are protected.
    323. We find unpersuasive Mirant's concern that, if the Sec.  35.27 
exemption were eliminated, a seller would have to get Commission 
approval for market-based rate sales prior to bidding on an RFP. If 
Mirant is concerned that certain RFPs require, among other things, that 
all bidders have in place all regulatory requirements including any 
applicable market-based rate authority, we find that RFPs typically 
afford bidders ample opportunity to put together their bids and put in 
place any necessary regulatory approvals. In this regard, we note that 
if a potential seller wishes to participate in an RFP but does not have 
market-based rate authority, the seller can file for such authorization 
and request expedited treatment and the Commission will use its best 
efforts to process the request as quickly as possible.
    324. With regard to the specific argument raised by Mirant, if a 
prospective seller wins an RFP, then the capacity would be counted as 
committed capacity, and therefore would not adversely affect the 
results of the seller's generation market power screen (which analyzes 
uncommitted capacity). If the entity loses the RFP, then it would not 
build the plant. In either case, the need for market-based rate 
authorization does not appear to discourage new investment by 
competitive suppliers as Mirant suggests.
    325. Some commenters assert that the retirement of generating units 
that were constructed in the 1980s would have to become commonplace 
before the Commission's concern is realized that over time all older 
generation will be retired. Others contend that it will take decades 
for this situation to materialize. However, commenters have provided no 
evidence that the elimination of Sec.  35.27(a) will create a 
regulatory barrier to new construction or otherwise depress the 
building of new generation facilities, and we need not wait for an 
inevitable adverse circumstance to materialize.
    326. Finally, we will not implement PPM's suggestion that we retain 
the exemption and apply a phasing in approach whereby generating units 
would lose the exemption over time based on the date on which the units 
were built. Such an approach would create several ``classes'' of 
generation facilities which would result in confusion for both the 
Commission and market participants. This confusion would become more 
acute in situations where market participants may own a number of 
generating facilities located in the same balancing authority area or 
relevant geographic market, each of which may be considered a different 
``class'' of generator in terms of filing horizontal market power 
analyses. Moreover, given the regional review and schedule for updated 
market power analyses discussed below in this rule, we believe that a 
phased-in approach would become overly problematic and unmanageable for 
market participants as a whole. Therefore, we will not accept PPM's 
suggestion.
b. Grandfathering
Comments
    327. EPSA and Mirant suggest grandfathering units for which 
construction commenced between July 9, 1996 and May 19, 2006, the date 
of issuance of the NOPR, when generation owners were put on notice that 
the Commission was considering eliminating the exemption in Sec.  
35.27(a).\313\ Constellation proposes that the exemption not be 
eliminated entirely but be limited to generation with construction that 
commenced on or after July 9, 1996, but before the effective date of 
the Final Rule in this proceeding.\314\ Constellation and EPSA also 
contend that this would be consistent with the Commission's prior 
decision to grandfather from PJM's mitigation any generating units that 
were built in reliance on the post-1996 exemption.\315\
---------------------------------------------------------------------------

    \313\ EPSA at 15; Mirant at 13.
    \314\ See Constellation at 31; PPL reply comments at 20.
    \315\ Constellation at 31, citing PJM Interconnection, LLC, 110 
FERC ] 61,053 at P 60-62 (grandfathering the exemption from 
mitigation for generating units for which construction commenced on 
or after the date the exemption became effective and before the date 
when PJM filed its proposal to eliminate the exemption for all 
generation units) (PJM), order on reh'g, 112 FERC ] 61,031 at P 38 
(2005) (PJM II), order on reh'g, 114 FERC ] 61,302 (2006); EPSA at 
16-17.
---------------------------------------------------------------------------

    328. Although NASUCA agrees with the Commission's proposal to 
eliminate the new generator exemption, NASUCA raises a concern about 
the prospective treatment of sellers with generating plants built after 
July 9, 1996 that initially received market-based rate authority 
without any generation market power assessment. NASUCA notes that its 
understanding is that, ``the Commission would effectively 
``grandfather'' the market-based rate status for owners of these newer 
power plants,\316\ at least until the time of the next applicable 
triennial review, when a market power analysis would be required for 
continuation of market-based rate authority.'' \317\ Specifically, 
NASUCA explains that a Category 2 seller who recently obtained market-
based rate authority, could have up to three years of future market-
based rate sales with no review of its horizontal market power, while 
any that fall into Category 1 would be exempted entirely from the 
triennial review process and thus ``grandfathered'' indefinitely and 
able to sell at market-based rates without passing any market power 
test. If this ``grandfathering'' is not intended, then, according to 
NASUCA, the Commission should clarify that new market power assessments 
must be made now for those sellers whose market power has never been 
reviewed.\318\ Otherwise, NASUCA contends that their rates could be 
vulnerable to challenge because they are established solely on the 
basis of market price.\319\
---------------------------------------------------------------------------

    \316\ NASUCA at 10 n.12, ``[T]he Commission would require that 
all new applicants seeking market-based rate authority on or after 
the effective date of the final rule issued in this proceeding, 
whether or not all of their or their affiliates' generation was 
built after July 9, 1996, must provide a horizontal market power 
analysis of their generation.'' Citing NOPR at P 71 (emphasis 
added).
    \317\ Id. at n.13, ``[W]ith regard to triennial reviews, the 
Commission's proposal to eliminate the section 35.27(a) exemption 
would require that, in its triennial review, a seller must perform a 
horizontal market power analysis of all of its generation regardless 
of when it was built, thus eliminating any special treatment of 
generation built after July 9, 1996.'' Citing NOPR at P 72.
    \318\ NASUCA at 10-11.
    \319\ Id. at 11, citing FPC v. Texaco, Inc., 417 U.S. 380 (1974) 
(stating that the prevailing price in the marketplace cannot be the 
final measure of just and reasonable rates) (Texaco). See also 
NASUCA reply comments at 7-8 (asserting that for any grandfathered 
sellers the market is the final determinant of price, an 
impermissible result under Texaco.)
---------------------------------------------------------------------------

Commission Determination
    329. We will not adopt commenters' proposals with regard to the 
grandfathering of any generating units that were built relying on the 
exemption in Sec.  35.27(a). As discussed above, we find establishing 
``classes'' of generation facilities would result in confusion for both 
the Commission and market participants. In this regard, no

[[Page 39944]]

commenter has demonstrated that harm would result from having to submit 
a horizontal market power analysis, and no commenter has claimed that 
it would lose its financing or that its financing would be adversely 
affected as a result of the elimination of the exemption in Sec.  
35.27(a). Moreover, as the Commission stated in Order No. 888, 
intervenors could present evidence that a seller seeking market-based 
rates for sales from new generation possesses market power, and sellers 
were aware that they may have to submit a horizontal market power 
analysis even if their generation fell within the exemption.\320\ 
Therefore, we will require that all sellers seeking market-based rate 
authority for the first time on or after the effective date of the 
Final Rule in this proceeding must provide a horizontal market power 
analysis that includes all generation that the seller owns or controls.
---------------------------------------------------------------------------

    \320\ See Order No. 888-A, FERC Stats.& Regs. Regulations 
Preambles July 1996-December 2000 ] 31,048 at 30,188 (``[T]he policy 
eliminates the [generation dominance] showing only as a matter of 
routine in each filing.'')
---------------------------------------------------------------------------

    330. All existing sellers that fall in Category 2 must provide a 
horizontal market power analysis that includes all generation that each 
seller owns or controls when it files its regularly scheduled updated 
market power analysis. To the extent a Category 1 seller acquires 
enough generation to be reclassified as a Category 2 seller, that 
seller will be required to submit a change in status report and provide 
a horizontal market power analysis.
    331. Further, with regard to PJM, in establishing whether units 
constructed after July 9, 1996 should be exempt from PJM's existing 
market power mitigation rules, we initially approved the post-1996 
exemption based on the concern that the price cap regulation or the 
mitigation rules in PJM might deter market entry and would create 
certain equity issues. However, we reconsidered our position and found 
that the exemption was unduly discriminatory by creating two classes of 
reliability must run generators: one that is price or offer capped and 
another that is not. Equally important, other RTOs/ISOs applied local 
market mitigation rules to all generation within their respective areas 
regardless of when the generator was built, and we determined that 
comparable authority for PJM would allow it to address local market 
power issues.\321\ We concluded that units built on or after July 9, 
1996 had the same ability to exercise market power as counterparts that 
were built prior to July 9, 1996. Accordingly, the Commission 
terminated the blanket exemption, but in the case of units that were 
built with the expectation that they would not be subject to 
mitigation, the Commission allowed the exemption to be 
grandfathered.\322\
---------------------------------------------------------------------------

    \321\ PJM, 110 FERC  61,053 at P 59.
    \322\ PJM II, 112 FERC  61,031 at P 38.
---------------------------------------------------------------------------

    332. Our reasons for grandfathering units in PJM are dissimilar 
enough that our holding in the PJM orders should not affect our 
decision here. The factors that led to the establishment and later the 
termination of the exemption from mitigation in PJM are unrelated to 
the reasons for instituting and, now, eliminating the express exemption 
in Sec.  35.27(a). In PJM and PJM II, the Commission considered whether 
local market power mitigation might deter new entry and whether new 
units were built with the expectation that they would not be subject to 
mitigation. The Commission grandfathered units that could reasonably 
have relied on the exemption after it went into effect in their 
zone.\323\ In contrast, in this proceeding the Commission desires a 
more rigorous market-based rate program and is concerned that over time 
generation will be retired leaving less and less generation subject to 
our horizontal analysis or sellers relying on the Sec.  35.27 exemption 
will otherwise grow to a degree that they have market power in the 
relevant market in which they are located. The Commission's primary 
statutory obligation under FPA sections 205 and 206 is to ensure that 
rates are just and reasonable, and we believe the elimination of the 
exemption will better provide us with the ability to screen all market 
participants' ability to exercise horizontal market power regardless of 
whether their generation units were constructed before or after July 9, 
1996. Therefore, we will not allow any grandfathering as part of this 
proceeding.
---------------------------------------------------------------------------

    \323\ Nevertheless, the Commission stated that the units would 
still be subject to mitigation if PJM or its market monitor 
concluded that they exercised significant market power. Id. at P 60.
---------------------------------------------------------------------------

    333. NASUCA's concerns regarding entities that originally enjoyed 
the Sec.  35.27 exemption are addressed by our decision, discussed 
below in the Implementation Process section of this Final Rule, to 
require a seller that believes it qualifies as Category 1 to make a 
filing with the Commission at the time that its updated market power 
analysis for the seller's region would otherwise be due (based on the 
regional schedule set forth in Appendix D). That filing should explain 
why the seller meets the Category 1 criteria and should include a list 
of all generation assets (including nameplate or seasonal capacity 
amounts) owned or controlled by the seller and its affiliates grouped 
by balancing authority area. Thus, a seller that previously qualified 
for the Sec.  35.27 exemption and that believes it qualifies as a 
Category 1 seller would be required to provide support for its claim to 
Category 1 status. This filing will give the Commission and interested 
parties an opportunity to review and, if appropriate, challenge a 
seller's claim that it qualifies as a Category 1 seller. To the extent 
that an intervenor has concerns about a seller's potential to exercise 
market power, the Commission will entertain them at that time.\324\ In 
addition, a seller that previously qualified for the Sec.  35.27 
exemption and that believes it qualifies as a Category 2 seller will be 
required to file an updated market power analysis based on the regional 
schedule set forth in Appendix D.
---------------------------------------------------------------------------

    \324\ Moreover, if specific concerns regarding market power 
exist, interested persons may file a complaint pursuant to FPA 
section 206.
---------------------------------------------------------------------------

    334. While it is true that a portion of these sellers will continue 
to sell at market-based rates for a time until their updated market 
power analyses (in the case of Category 2 sellers) or their filings 
addressing qualification as Category 1 sellers are due, no commenter 
has submitted compelling evidence that Category 1 sellers have 
unmitigated market power. We will rely on our change in status 
requirements that require, among other things, all sellers that obtain 
or acquire a net increase of 100 MW in owned or controlled generation 
to make a filing with the Commission and to provide the effect, if any, 
such an increase in generation has on the indicative screens. 
Additionally, all sellers must file EQRs of transactions no later than 
30 days after the end of each reporting quarter. Furthermore, the 
Commission retains the ability to require an updated market power 
analysis from any seller at any time. With these procedures in place, 
we believe NASUCA's concerns are addressed.
c. Creation of a Safe Harbor
Comments
    335. NRG urges the Commission to create a ``safe harbor'' such that 
``if the generation owner controls less than 20 percent of the capacity 
in an organized market, the Commission should irrebuttably presume that 
the new entry will not contribute to market power and thus no 
demonstration is required to obtain market-based rate authority for the 
new capacity.'' \325\ NRG states that

[[Page 39945]]

only where an owner controls more than 20 percent of capacity in a 
relevant market should the presumption be rebuttable and subject to 
challenge by intervening parties. It is NRG's contention that the 
creation of such a ``safe harbor'' retains most of the benefits of the 
Commission's current policy under Sec.  35.27(a), while preserving its 
flexibility to investigate where a seller adding generating capacity 
already has a large market share. NRG believes that this codifies the 
general approach the Commission took in Order No. 888 \326\ and 
responds to the Commission's evolving concerns in this area, while at 
the same time facilitating new entry in the organized markets where 
sufficient safeguards exist.\327\ NRG contends that new generation, 
timely developed and brought online, is imperative; thus, a ``safe 
harbor'' for new generation is necessary.
---------------------------------------------------------------------------

    \325\ NRG at 5 & n.8, suggesting that the use of a 20 percent 
market share in the safe harbor proposal replicates one of the two 
screens that the Commission proposes in the NOPR to use as a general 
screen for market power in all markets reviewed for market-based 
rate authority. NRG argues that a 20 percent market share screen is 
well-established and appropriate for use in reviewing the market 
power implications associated with the addition of new generation. 
The use of a lightened, single screen approach to review the market 
power implications of new generation is appropriate, argues NRG, in 
that new generation expands the supply available in a market. 
According to NRG, for organized markets administered by RTOs that 
have in place Commission-approved market monitoring and mitigation 
authority, subjecting new generation only to a 20 percent market 
share screen is appropriate in light of the existing controls over 
the exercise of market power.
    \326\ Id. at n.9, citing Order No. 888, FERC Stats. & Regs., 
Regulations Preambles, January 1991--June 1996 ] 31,036 at 31,657.
    \327\ Id. at n.10. Under NRG's proposal, the Commission would 
also need to apply the safe harbor analysis to the notice of change 
of status for the suppliers' existing generation, when the notice of 
change is triggered by the addition of new generation capacity. 
Failure to do so would mean the lightened review appropriate for new 
generation would not, in effect, produce the intended lessening of 
regulatory burden.
---------------------------------------------------------------------------

    336. Ameren agrees that there is a need for the Commission to 
address the Sec.  35.27 exemption before it encompasses all generating 
capacity; however, Ameren submits that the Commission should allow an 
exemption for new generation under certain circumstances. Ameren argues 
that ``the Commission should amend its regulations to provide that new 
generation that represents less than 20 percent of the uncommitted 
capacity at peak in the relevant geographic market be exempt from the 
requirement of a horizontal market power analysis, so long as the owner 
of, or entity that controls, such capacity and its affiliates own no 
other generation or transmission facilities (other than interconnection 
facilities) in the relevant market.'' \328\ Ameren submits that the 
Commission should allow the seller to file a letter which identifies: 
(1) The transmission system it is interconnected to; (2) the amount of 
uncommitted capacity it controls; and (3) the Commission-approved 
market power study that it relied on to determine that its uncommitted 
capacity is less than twenty percent of the net uncommitted capacity in 
the relevant geographic market. Ameren contends that this abbreviated 
process would reduce a seller's cost of compliance and administrative 
burdens.\329\
---------------------------------------------------------------------------

    \328\ Ameren at 7-8.
    \329\ Id.
---------------------------------------------------------------------------

Commission Determination
    337. The Commission will not create a safe harbor.\330\ For the 
reasons set forth in the April 14 Order and reiterated in the July 8 
Order, there will be no safe harbor exemption from the generation 
market power screen based upon a seller's size.\331\ While there is no 
safe harbor exemption from the screens based on the seller's size, any 
seller, regardless of size, has the option of making simplifying 
assumptions in its analysis where appropriate that do not affect the 
underlying methodology utilized by these screens.
---------------------------------------------------------------------------

    \330\ We note that although Category 1 sellers are not required 
to provide a regularly scheduled updated market analysis, such an 
approach does not establish a safe harbor because all sellers will 
be required to perform the indicative screens as part of their 
initial applications, make change in status filings and file EQRs.
    \331\ See April 14 Order, 107 FERC ] 61,018 at P 69, 117; July 8 
Order, 108 FERC 61,026 at P 107 (the Commission explained that small 
sellers are able to use simplifying assumptions).
---------------------------------------------------------------------------

    338. Further, while we eliminate the Sec.  35.27 exemption in this 
Final Rule, we note that sellers that have enjoyed that exemption 
historically have been required to address the other parts of the 
market-based rate analysis, vertical market power, affiliate abuse, and 
other barriers to entry.\332\ Therefore, the Commission believes that, 
on balance, any additional cost of compliance or administrative burden 
due to this change will not be substantial compared to a seller's 
investment and revenues.\333\
---------------------------------------------------------------------------

    \332\ As described in this Final Rule, we consolidate the 
transmission market power and other barriers to entry analyses into 
one vertical market power analysis. In addition, we discontinue 
considering affiliate abuse as a separate part of the analysis and 
instead codify affiliate restrictions in our regulations.
    \333\ NOPR at P 71.
---------------------------------------------------------------------------

11. Nameplate Capacity
Commission Proposal
    339. In the NOPR, the Commission proposed to allow sellers the 
option of using seasonal capacity instead of nameplate capacity, as is 
currently required. The Commission indicated that the seller must be 
consistent in its choice and thus must choose either seasonal or 
nameplate capacity and use it consistently throughout the analysis. The 
Commission stated that it believed the use of seasonal capacity ratings 
more accurately reflects the seasonal real power capability and is not 
inconsistent with industry standards and, therefore, it may be more 
convenient for sellers to acquire and compile the associated data. The 
Commission added that it did not think the use of such ratings will 
materially impact results. The Commission sought comment on this 
proposal, including comment as to whether this information is publicly 
available to all market participants.
Comments
    340. Many commenters on this topic express strong support for the 
proposal to substitute seasonal capacity for nameplate capacity.\334\ 
The reason most commonly cited is that seasonal capacity is a more 
accurate representation of actual output. Several commenters state that 
firms should be allowed to use net seasonal capacity,\335\ which allows 
for station service requirements and energy consumed by environmental 
equipment. MidAmerican points out that station usage, including 
environmental equipment, can approach 10 percent of overall output in 
steam plants.\336\ EEI states that coal plants, which make up 51 
percent of generation in the United States, are required to comply with 
both Federal and State regulations that mandate emission reductions. 
The plants are equipped with scrubbers and other emissions reduction 
technology that require a portion of the power produced by the plant in 
order to operate, thereby reducing the output available to serve 
customers. For companies with a large percentage of their generation 
coming from coal, the reduced output from such equipment could be 
significant.\337\ PG&E favors using seasonal capacity if it could be 
filed confidentially, because it maintains that it is commercially 
sensitive information.\338\
---------------------------------------------------------------------------

    \334\ Duke at 22; First Energy at 10; Southern at 26; SoCal 
Edison at 8.
    \335\ EEI at 18; PNM/Tucson at 10; Allegheny at 7-8; Pinnacle 
West at 5-6; PPL at 17.
    \336\ MidAmerican at 8.
    \337\ EEI at 18.
    \338\ PG&E at 10-11.
---------------------------------------------------------------------------

    341. PG&E requests clarification that if sellers are allowed to 
submit seasonal capacity, they are allowed to de-rate

[[Page 39946]]

hydroelectric capacity resources based on historical output for the 
past five years, as specified in the April 14 Order.\339\ Powerex 
supports seasonal ratings as more accurate, because hydroelectric 
systems are often able to generate in excess of nameplate ratings and 
these ``peak capability'' ratings are typically reflected in seasonal 
determinations, and seasonal ratings better reflect operating 
conditions that can impact the capacity ratings of renewable 
resources.\340\
---------------------------------------------------------------------------

    \339\ April 14 Order, 108 FERC ] 61,018 at P 126. The July 8 
Order allowed this method to be used for wind resources as well. 
July 8 Order, 108 FERC ] 61,026 at P 129.
    \340\ Powerex at 20.
---------------------------------------------------------------------------

    342. APPA/TAPS support the adoption of seasonal capacity ratings if 
they are consistently used, and request that the Commission clarify 
that the seasonal capacity ratings be used for all plants in a 
geographic region ``so that the consistency benefits of the regional 
reviews are not diminished.'' \341\
---------------------------------------------------------------------------

    \341\ APPA/TAPS at 35.
---------------------------------------------------------------------------

Commission Determination
    343. We will adopt the NOPR proposal that allows sellers to use 
seasonal capacity. We clarify that each seller must be consistent in 
its choice and thus must choose either seasonal or nameplate capacity 
and use it consistently throughout the analysis. In addition, a seller 
using seasonal capacity must identify in its submittal from what source 
the data was obtained.\342\ We also note and adopt the Energy 
Information Administration (EIA) definition of seasonal capacity as it 
is reported on Form EIA-860, Schedule 3, Part B, Line 2, which provides 
that seasonal capacity is the ``net summer or winter capacity.'' \343\ 
EIA instructions elaborate that ``net capacity should reflect a 
reduction in capacity due to electricity use for station service or 
auxiliaries,'' \344\ which includes scrubbers and other environmental 
devices.
---------------------------------------------------------------------------

    \342\ In the July 8 Order, the Commission stated that ``[w]ith 
respect to data that is only available from commercial sources, we 
clarify that commercial sources may be used to the extent the data 
is made available to intervenors and other interested parties. 
Applicants utilizing commercial information to perform the screens 
should include it in their filing.'' July 8 Order, 108 FERC ] 61,026 
at P 121.
    \343\ EIA-860 Instructions are available at http://www.eia.doe.gov/cneaf/electricity/forms/eia860/eia860.pdf
.

    \344\ Tip Sheet for Reporting on Form EIA-860, ``Annual Electric 
Generator Report'' at item ``III. Schedule 3B, Line 2 and Schedule 
3D, Line 2: Net Capacity'' available at http://www.eia.doe.gov/cneaf/electricity/forms/eia860/tipsheet.doc
.

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

    344. With regard to energy-limited resources, such as hydroelectric 
and wind capacity, in lieu of using nameplate or seasonal capacity in 
their submissions, we will allow such resources to provide an analysis 
based on historical capacity factors reflecting the use of a five-year 
average capacity factor including a sensitivity test using the lowest 
capacity factor in the previous five years, and in recognition of 
Powerex's concern that hydroelectric systems can generate in excess of 
nameplate ratings and these ``peak capability'' ratings, the highest 
capacity factor in the previous five years. Our approach in this regard 
will more accurately capture hydroelectric or wind availability.\345\
---------------------------------------------------------------------------

    \345\ In the April 14 Order, we explained that commenters 
expressed concerns regarding the appropriate measure of the capacity 
of hydroelectric units given that hydroelectric facilities are 
energy-limited units. Our experience with Western markets shows that 
market outcomes can be significantly different during low water 
years. We agree with the comments raised by Western market 
participants and conclude that properly accounting for water 
availability will provide a better picture of competitive conditions 
in the West. Moreover, while not as critical in other parts of the 
country as in the West, the same principle regarding water 
availability applies to all electricity markets, and we will permit 
all sellers to de-rate hydroelectric capacity in the analysis.
---------------------------------------------------------------------------

    345. We will not adopt APPA/TAPS' suggestion that we require use of 
either nameplate capacity or seasonal capacity throughout a region. 
While we appreciate APPA/TAPS' concern for data consistency for 
analysis purposes, we note that although we adopt a regional approach 
for the filing of updated market power analyses, the horizontal market 
power analysis itself continues to focus on the seller seeking to 
obtain or retain market-based rate authority. We find that consistency 
of data is critical within each individual analysis as results could 
vary depending on the assumptions taken. However, because we are not 
necessarily analyzing the entire region within a single study, we will 
not mandate the use of either nameplate capacity or seasonal capacity 
on a regional basis, but instead will allow sellers to choose either 
nameplate or seasonal capacity, and require them to identify the choice 
and use it consistently throughout the analysis.\346\
---------------------------------------------------------------------------

    \346 \ When submitting a change in status filing regarding 
horizontal market power, sellers should use the same assumptions 
they used (e.g., use of nameplate or seasonal ratings) in their most 
recent market power analysis.
---------------------------------------------------------------------------

12. Transmission Imports
    346. In the NOPR, the Commission proposed to continue to measure 
limits on the amount of capacity that can be imported into a relevant 
market based on the results of a simultaneous transmission import 
capability study. A seller that owns, operates or controls transmission 
is required to conduct simultaneous transmission import capability 
studies for its home control area and each of its directly-
interconnected first-tier control areas consistent with the 
requirements set forth in the April 14 Order, as clarified in Pinnacle 
West Capital Corp.\347\ These studies are used in the pivotal supplier 
screen, market share screen, and DPT to approximate the transmission 
import capability. When centering the generation market power analysis 
on the transmission providing utility's first-tier control area (i.e., 
markets), the transmission-providing seller should use the 
methodologies consistent with its implementation of its Commission-
approved OATT, thereby making a reasonable approximation of 
simultaneous import capability that would have been available to 
suppliers in surrounding first-tier markets during each seasonal peak. 
The transfer capability should also include any other limits (such as 
stability, voltage, Capacity Benefit Margin, or Transmission 
Reliability Margin) as defined in the tariff and that existed during 
each seasonal peak. The ``contingency'' model should use the same 
assumptions used historically by the transmission provider in 
approximating its control area import capability.
---------------------------------------------------------------------------

    \347\ 110 FERC ] 61,127 (2005).
---------------------------------------------------------------------------

    347. The Commission also proposed to reaffirm the exclusion of 
control areas that are second-tier to the control area being studied. 
In addition, it proposed that a seller's pro rata share of simultaneous 
transmission import capability should be allocated between the seller 
and its competitors based on uncommitted capacity. The Commission 
sought comment on this proposal.
a. Use of Historical Conditions and OASIS Practices
Comments
    348. Montana Counsel states that transmission capability used in 
the tests should not be greater than the capability measures that are 
shown on the OASIS or that are used to measure ATC into markets unless 
there is a demonstrated change in available transmission 
capability.\348\ In particular, Montana Counsel states that the 
Commission's requirement that sellers follow historical OASIS practice 
during each historical seasonal peak is essential; otherwise, companies 
could submit screens using transmission availability numbers that 
differ substantially from those which sellers and transmission

[[Page 39947]]

providers use in day-to-day activities in providing transmission market 
access.\349\ In Montana Counsel's view, one cannot rely on capacity 
being able to reach a market based upon hypothetical transmission 
availability, as the Commission appropriately recognizes.
---------------------------------------------------------------------------

    \348\ Montana Counsel at 4.
    \349 \ Id. at 14.
---------------------------------------------------------------------------

    349. In response to Montana Counsel's assertion to use OASIS 
postings, PPL Companies maintain that the Commission should continue to 
use simultaneous import limit studies. OASIS postings do not adjust for 
transmission rights controlled by unaffiliated resources that may be 
used to compete against the seller in wholesale markets. PPL Companies 
state: ``The Commission should reject this proposal and continue to 
rely on [SILs]. The Commission properly has found that using actual 
OASIS postings understates import capability because OASIS postings do 
not take into account the capacity that may be imported as a result of 
existing reservations.''\350\
---------------------------------------------------------------------------

    \350\ PPL Companies reply comments at 9-11.
---------------------------------------------------------------------------

    350. EEI and Southern request clarification of a perceived conflict 
in Appendix E, which instructs sellers to use Commission criteria for 
calculating simultaneous import capability and also to strictly follow 
their OASIS practices.\351\ They recommend that the Commission clarify 
that if historical practices are different from Appendix E, historical 
practices should be used to calculate simultaneous transmission import 
capability and to allocate this transmission capability.
---------------------------------------------------------------------------

    \351\ EEI at 27-29; Southern at 32.
---------------------------------------------------------------------------

    351. Duke asserts that scaling methods for calculating simultaneous 
transmission import capability should not be solely limited to 
historical practices used by the seller to post ATC on OASIS. Duke 
proposes a collaborative method involving the seller and transmission 
customers. Duke states: ``the Commission should allow applicants 
flexibility to use the appropriate methodology for SIL determinations 
including collaborative, regional efforts--so that screen results for 
control area markets can be accurate. For example, the Commission 
should not be overly prescriptive as to the scaling methodology to be 
used in such a collaborative effort, as long as the methodology is 
clearly defined and supported by the applicants.''\352\ PPL Companies 
support the collaborative effort proposed by Duke, stating that sellers 
should have ``the option of proposing alternative [SILs] for first-tier 
markets, but would have to justify and document the proposed 
deviations.''\353\
---------------------------------------------------------------------------

    \352\ Duke at 27-28.
    \353\ PPL Companies reply comments at 9-11
---------------------------------------------------------------------------

    352. Southern states that the SIL study requires ``blind'' scaling 
(scaling that does not consider economic dispatch) because only 
generation that is ``on-line'' is used. Southern states that to the 
extent a transmission provider does not customarily employ blind 
scaling, its use would not be consistent with historical practice. It 
asserts that a problem with blind scaling is that it does not 
necessarily reflect reality and therefore has the potential to 
understate, perhaps significantly, the simultaneous import limit.\354\ 
EEI seeks clarification that the Commission is not requiring blind 
scaling in a manner that requires proportionate increases and decreases 
to generation resources. EEI requests clarification that scaling is 
allowed to include expert judgment reflecting how generation resources 
would likely be scaled up or down in a real-time operating environment. 
EEI contends that expert judgment in some cases may determine 
simultaneous import capability by scaling load rather than generation 
resources. EEI requests that the Commission defer to expert judgment in 
scaling and not be overly prescriptive as to whether generation or load 
is scaled to determine simultaneous import capability.\355\
---------------------------------------------------------------------------

    \354\ Southern at 35 and 36.
    \355\ EEI at 24.
---------------------------------------------------------------------------

    353. PPL Companies contend the simultaneous import capability 
should not be limited by load in a control area. Since generators 
within the control area may sell power within or outside the control 
area, the Commission should consider the market prices of surrounding 
regions. If the prices are 105 percent or less, compared to control 
area prices, then the Commission should assume the resident control 
area resources will remain within the control area and not result in 
economic withholding within the seller's area.\356\
---------------------------------------------------------------------------

    \356\ PPL Companies at 8.
---------------------------------------------------------------------------

Commission Determination
    354. The Commission will continue to require sellers to submit the 
Appendix E analysis, i.e., the SIL study, to calculate aggregated 
simultaneous transfer capability into the balancing authority area 
being studied.\357\ The Commission reaffirms that the SIL study is 
``intended to provide a reasonable simulation of historical 
conditions'' \358\ and is not ``a theoretical maximum import capability 
or best import case scenario.'' \359\ To determine the amount of 
transfer capability under the SIL study, ``historical operating 
conditions and practices of the applicable transmission provider (e.g., 
modeling the system in a reliable and economic fashion as it would have 
been operated in real time) are reflected.'' \360\ In addition, the 
``analysis should not deviate from'' and ``must reasonably reflect'' 
its OASIS operating practices\361\ and ``the techniques used must have 
been historically available to customers.'' \362\ We also reaffirm that 
the power flow cases (which are used as inputs to the SIL study) should 
represent the transmission provider's tariff provisions and firm/
network reservations held by seller/affiliate resources during the most 
recent seasonal peaks.\363\
---------------------------------------------------------------------------

    \357\ Benefits of using a uniform transmission import model 
include: Transparency, consistency, clarity, and reasonable 
assurance that system conditions have been adequately captured.
    \358\ In this regard, actual flows during the study periods may 
be used as a proxy for the simultaneous transmission import limit.
    \359\ NOPR at P 77.
    \360\ Id.
    \361\ By OASIS practices, we mean sellers shall use the same 
OASIS methods and studies used historically by sellers (in 
determining simultaneous operational limits on all transmission 
lines and monitored facilities) to estimate import limits from 
aggregated first-tier control areas into the study area. In this 
sense, sellers are modeling first-tier balancing authority areas as 
if they are the transmission operator/security coordinator 
(monitoring reliability) operating an OASIS for the aggregated 
first-tier footprint. We recognize that sellers are not the 
balancing authority area operators of first-tier balancing authority 
areas and in some instances, sellers may not be familiar with all 
aspects of their first-tier balancing authority areas' transmission 
system limits. However, sellers should be familiar with major 
constraints, path limits, and delivery problems in these neighboring 
transmission systems. If a seller participates in regional planning 
studies and day-to-day coordination with neighboring first-tier 
balancing authority areas then this will provide a reasonable basis 
for including transmission system constraints of first-tier 
balancing authority areas in SIL study calculations. In using OASIS 
practices the SIL study shall capture real-life physical limitations 
of first-tier balancing authority areas that impede power flowing 
from remote first-tier resources into the seller's study.
    \362\ Id. at P 77, 78.
    \363\ Network reservations include any grandfathered 
transmission rights applicable to the seller or its affiliated 
companies.
---------------------------------------------------------------------------

    355. The Commission will also continue to allow sensitivity 
studies, but the sensitivity studies must be filed in addition to, and 
not in lieu of, an SIL study. We clarify that sensitivity studies are 
intended to provide the seller with the ability to modify inputs to the 
SIL study such as generation dispatch, demand scaling, the addition of 
new transmission and generation facilities

[[Page 39948]]

(and the retirement of facilities), major outages, and demand 
response.\364\
---------------------------------------------------------------------------

    \364\ We note that several sellers from the Western 
Interconnection have relied on Western Electricity Coordinating 
Council (WECC) path ratings for their SIL studies. The Commission 
has accepted these ratings when sellers have demonstrated that they 
are simultaneously feasible and take into account any 
interdependencies between paths.
---------------------------------------------------------------------------

    356. The Commission agrees with Montana Counsel and clarifies for 
PPL Companies that a SIL study must reflect transmission capability no 
greater than the capability measures that were historically shown on 
the OASIS or that were historically used to measure transmission 
capability into markets unless there is a demonstrated change in 
transmission capability, and account for the actual practice of posting 
ATC to OASIS in order to capture a realistic approximation of first-
tier generation access to the seller's market. Further, and in response 
to EEI and Southern's comments, the Commission clarifies that when 
actual OASIS practices conflict with the instructions of Appendix E, 
sellers should follow OASIS practices and must provide adequate support 
in the form of documentation of these processes.
    357. We disagree with Duke's argument that a seller's (generation 
or load) scaling methods should not be limited to historical OASIS 
practices when conducting an SIL. Using historical practices provides 
an appropriate method to obtain a transparent and measurable analysis 
of a seller's actual balancing authority area transmission conditions 
and practices. Improper or theoretical scaling methods which do not 
represent a seller's actual transmission practices may have the effect 
of allowing more competing generation into the balancing authority area 
than could actually be accommodated. This in turn has the effect of 
reducing a seller's generation market share and perhaps causing the 
seller to inappropriately pass the market share screen (a false 
negative).\365\ In addition, relying on historical OASIS practices 
gives a seller the data needed to support its conclusions.
---------------------------------------------------------------------------

    \365 \ See, e.g., Pinnacle West Capital Corp., 117 FERC ] 61,316 
(2006).
---------------------------------------------------------------------------

    358. With regard to Duke and PPL's request that the Commission 
allow sellers to submit a flexible SIL study based on regional 
collaboration, the Commission finds that such an approach does not 
satisfy our concerns and may result in an unrealistic representation of 
the market.
    359. Southern states that to the extent a transmission provider 
does not customarily employ blind scaling, its use would not be 
consistent with historical practice.
    We agree and, as noted herein, the horizontal analysis and the SIL 
study are designed to study historical and realistic conditions during 
peak seasons. Accordingly, in this circumstance, sellers should follow 
their OASIS practices and must provide adequate support in the form of 
documentation of these processes.
    360. With regard to EEI's argument that the Commission should 
consider allowing expert judgment in predicting real-time scaling 
techniques that will likely be used in real-time market environments, 
the Commission requires the use of a study that captures historical 
transmission operating practices. The SIL study is not a prediction of 
import possibilities; rather, it is a simulation of historical 
conditions. We assume that such historical conditions are the result of 
``expert judgment'' used when determining generation dispatch and/or 
scaling techniques to make transmission capacity available during 
actual system conditions. Accordingly, this expert judgment is captured 
when conducting an SIL study that is based on historical operating 
practices.
    361. In response to PPL's comments that the SIL should not be 
limited by load in a balancing authority area, the Commission 
reiterates that the SIL study is a benchmark of historical conditions, 
including peak load. It is a study to determine how much competitive 
supply from remote resources can serve load in the study area. 
Increasing the load in the study area beyond historical peak levels 
makes the study less realistic and can bias the study.\366\ The 
Commission does, however, consider sensitivity studies on a case-by-
case basis, when submitted in addition to the SIL study and supported 
by record evidence. For example, in Puget Sound Energy, Inc.'s (Puget) 
updated market power analysis filing, Puget demonstrated that the 
simultaneous transmission import limit was greater than the peak load 
in its balancing authority area, and the Commission allowed Puget to 
use a simultaneous transmission import limit based on its peak 
load.\367\
---------------------------------------------------------------------------

    \366\ We note that there may be a circumstance where additional 
supplies could be imported above the market's study year peak load. 
If such a circumstance occurs, we will allow the seller to submit a 
sensitivity analysis in this regard and we will consider such an 
analysis on a case-by-case basis.
    \367\ Puget Sound Energy, Inc., 111 FERC ] 61,020 at P 13 
(2005).
---------------------------------------------------------------------------

    362. PPL also contends the simultaneous import capability should 
not be limited by load in a balancing authority area since generators 
within the balancing authority area may sell power within or outside 
the balancing authority area. Accordingly, PPL believes that the 
Commission should consider the market prices of surrounding regions. 
The Commission disagrees. We base the SIL on historical conditions that 
actually existed during the study periods. In this regard, PPL has 
provided no compelling reason for the Commission to abandon historical 
evidence in favor of a theoretical estimation of what could have 
occurred. We find that PPL's approach would make the studies more 
subjective and thus less accurate and more prone to dispute and 
controversy.
b. Use of Total Transfer Capability (TTC)
Comments
    363. Southern asserts that the Commission's assumption that all TTC 
values posted on OASIS platforms are non-simultaneous is not correct. 
Southern states that although many TTC values may be calculated on a 
point-to-point non-simultaneous basis, some TTC values are 
simultaneous, thus accounting for ``loop flow'' created by other paths. 
Southern contends that those transmission providers that post 
simultaneous TTC values on OASIS should have the flexibility to add 
these TTC values to calculate simultaneous transmission import 
capability for the control area. Southern believes that conflicts can 
occur between the generic methods presented in the Appendix E interim 
market screen order and actual OASIS practices used by transmission 
providers to post TTC.
Commission Determination
    364. Southern's suggestion that the Commission allow the use of 
simultaneous TTC values is consistent with the SIL study provided that 
these TTCs are the values that are used in operating the transmission 
system and posting availability on OASIS. The simultaneous TTCs \368\ 
must represent more than interface constraints at the balancing 
authority area border and must reflect all transmission limitations 
within the study area and limitations within first-tier areas. The 
source (first-tier remote resources) can only deliver power to load in 
the seller's balancing authority area if adequate transmission is 
available out of its first-tier area, adequate transmission is 
available at the seller's balancing authority area

[[Page 39949]]

interface, and transmission is internally available. Thus, the TTC must 
be appropriately adjusted for all applicable (as discussed below) firm 
transmission commitments held by affiliated companies that represent 
transfer capability not available to first-tier supply. Sellers 
submitting simultaneous TTC values must provide evidence that these 
values account for simultaneity, account for all internal transmission 
limitations, account for all external transmission limitations existing 
in first-tier areas, account for all transmission reliability margins, 
and are used in operating the transmission system and posting 
availability on OASIS.
---------------------------------------------------------------------------

    \368\ The simultaneous TTCs include seller's balancing authority 
area and aggregated first-tier areas.
---------------------------------------------------------------------------

c. Accounting for Transmission Reservations
Comments
    365. Duke and EEI propose that short-term firm reservations should 
not be subtracted from simultaneous import limits because longer firm 
reservation requests can displace control of these transmission 
holdings.\369\ EEI explains, ``it is inappropriate to net out 
transmission capacity that is not reserved to commit long-term 
generation resources to load. Short-term firm transmission 
reservations, some as short as one week in duration, provide 
flexibility to the market and will not necessarily persist for the 
duration, or even large portions, of the MBR authorization period. 
Therefore, they should not be used to reduce the estimate of 
simultaneous import capability.''\370\
---------------------------------------------------------------------------

    \369\ Duke at 26-29.
    \370\ EEI at 25-26.
---------------------------------------------------------------------------

    366. Southern agrees, referring to the nature of short-term 
reservations as ``transient and unpredictable.'' \371\ Southern states: 
``In most cases, short-term purchases by the applicant essentially 
allow the market to provide generation within the applicant's control 
area instead of the applicant utilizing its `owned' generation 
capacity. Alternatively, the associated import capability is released 
to the market. In either case, these short-term reservations should not 
be used to inflate artificially the applicant's market share in 
conjunction with a screen or DPT evaluation.'' \372\
---------------------------------------------------------------------------

    \371\ Southern at 36-37.
    \372\ Id. at 37.
---------------------------------------------------------------------------

    367. APPA/TAPS state that the Commission should revisit the 
treatment of firm transmission reservations held by third parties. In 
the July 8 Rehearing Order (at P 49), the Commission stated that the 
SIL study assumed that ``all reservations historically controlled by 
non-affiliates would have been used to compete to inject energy into 
the transmission provider's control area market if market power or 
scarcity was driving market prices above other regional prices.'' 
However, if the holder of the reservation is using the transfer 
capability to serve its own load, it will not be available to third 
parties to respond to a price increase on the part of the transmission 
provider/sellers. APPA/TAPS state that presumably the capacity 
resources associated with the import will be reflected in the capacity 
total of the party that controls the resource's output. Excluding the 
transfer capability associated with the resource will not result in a 
double-deduction. Rather, failing to exclude the transfer capability 
will result in a double-counting of competing supply. Thus, APPA/TAPS 
assert that the Commission should revise the treatment of transfer 
capability held by third parties on a firm basis.\373\
---------------------------------------------------------------------------

    \373\ APPA/TAPS at 53.
---------------------------------------------------------------------------

Commission Determination
    368. The Commission agrees with Duke, EEI and Southern that short-
term firm reservations can be unpredictable, driven by real time system 
conditions, and do not necessarily indicate that the associated 
transmission capacity is not available for competing supplies (or to 
import seller's supplies during the study periods). Accordingly, we 
conclude that, in calculating simultaneous transmission import limits, 
short-term firm reservations of 28 days or less in effect during the 
study periods need not be accounted for.\374\ While we find that firm 
transmission reservations less than or equal to 28 days in duration are 
usually unpredictable, we believe that firm transmission reservations 
of a longer duration are not related to the unpredictable nature of 
real time events and are based upon planned and predictable events. 
Therefore, the Commission will require sellers to account for firm and 
network transmission reservations having a duration of longer than 28 
days.\375\
---------------------------------------------------------------------------

    \374\ We understand that short-term firm reservations are often 
used for unpredictable events and real-time system conditions. We 
note that most unpredictable conditions that sellers hold short-term 
firm reservations for, including generator forced outages and 
weather events, are less than one month in duration. Accordingly, we 
will allow applicants to not account for short-term firm 
reservations of one month or less, and since the shortest month is 
28 days long, we are setting this limit at 28 days. Any firm 
reservation longer than 28 days in duration must continue to be 
accounted for in the SIL study.
    \375\ The simultaneous import limit study must account for 
short-term firm transmission rights including point-to-point on-
peak/off-peak transmission reservations (firm or network 
transmission commitments) which have been stacked, or successively 
arranged, into an aggregated point-to-point transmission reservation 
longer than 28 days.
---------------------------------------------------------------------------

    369. With regard to APPA/TAPSs' concern, we clarify that the 
seller's firm, network, and grandfathered transmission reservations 
longer than 28 days, including reservations for designated resources to 
serve retail load, shall be fully accounted for in the simultaneous 
import limit study. We further clarify that reservations held by third 
parties to import power into the seller's home area should be accounted 
for by allocating transmission import capability to those parties, and 
then allocating the remaining SIL pro rata.
d. Allocation of Transmission Imports Based on Pro Rata Shares of 
Seller's Uncommitted Generation Capacity
Comments
    370. Duke and EEI support the Commission proposal to allocate 
imports on a pro rata basis into a study area based on uncommitted 
capacity in surrounding areas.\376\
---------------------------------------------------------------------------

    \376\ Duke at 26-29, EEI at 25-26.
---------------------------------------------------------------------------

    371. However, Powerex expresses concern that pro rata allocation of 
uncommitted capacity is not a realistic representation of the physical 
capability of the system, since pro rata allocation assumes that the 
system can import up to the simultaneous import limit over any 
combination of transmission paths. Powerex argues that, in reality, 
some paths become constrained before others, so the allocation of 
import capability should take account of the physical limitations of 
the transmission system. Powerex asks that the Commission allow sellers 
to use allocation methods that are consistent with physical system 
limitations, where sellers provide documentation showing that the 
allocation methods used in the screens are realistic or 
conservative.\377\
---------------------------------------------------------------------------

    \377\ Powerex at 24-25.
---------------------------------------------------------------------------

    372. Morgan Stanley asks the Commission to clarify its proposal of 
allocating transmission imports pro rata between the seller and its 
competitors based on uncommitted capacity. Morgan Stanley wonders if 
the Commission made a typographical error and intended to propose an 
allocation based on committed capacity. Morgan Stanley believes only 
the transmission provider (seller) would have uncommitted 
capacity.\378\
---------------------------------------------------------------------------

    \378\ Morgan Stanley at 15.
---------------------------------------------------------------------------

Commission Determination
    373. The Commission agrees with Duke and EEI that the current 
practice of allocating simultaneous import

[[Page 39950]]

capability pro rata to sellers based on uncommitted capacity should be 
continued.\379\ However, some clarification may be helpful.
---------------------------------------------------------------------------

    \379\ Allocation of the simultaneous transmission import 
capability, into the seller's market, to affiliated and unaffiliated 
uncommitted first-tier generation is done in the indicative screen, 
after conducting the SIL study, in order to estimate uncommitted 
capacity market shares from first-tier balancing authority areas.
---------------------------------------------------------------------------

    374. Powerex raises concern over the pro rata allocation of 
uncommitted generation capacity and asserts that this is not a 
realistic representation of the physical capability of the system since 
pro rata allocation assumes that the system can import up to the 
simultaneous import limit over any combination of transmission paths. 
In this regard, we note that pro rata allocation of transmission 
capacity based on first-tier uncommitted generation capacity is an 
approximation and is consistent with the manner in which we conduct the 
SIL study. In particular, when determining the simultaneous import 
limit, first-tier balancing authority areas are combined into a single 
area. The import capability of the study area is the simultaneous 
transfer limit from the aggregated first-tier market area into the 
study area.\380\ We then allocate imports based on transmission 
capacity (limited by the physical capabilities of the transmission 
system as determined by the SIL study) pro rata based on sellers' 
first-tier uncommitted generation capacity.\381\ We recognize that such 
an approximation may not fit all cases. Accordingly, with regard to 
allocating transmission imports, sellers can submit additional 
sensitivity studies based on factors suggested by Powerex, and 
intervenors may rebut the allocations of import capability made by 
seller. The Commission will consider such arguments on a case-by-case 
basis.
---------------------------------------------------------------------------

    \380\ April 14 Order, 107 FERC ]61,018 at Appendix E.
    \381\ The SIL study also accounts for transmission reservations 
when determining the amount of imports available to reach the study 
area as discussed herein and in the April 14 and July 8 Orders.
---------------------------------------------------------------------------

    375. Morgan Stanley asks if the Commission made a typographical 
error and intended to propose an allocation based on committed capacity 
rather than uncommitted capacity. The Commission clarifies that pro 
rata allocation is used to assign shares of simultaneous transmission 
import capability to uncommitted generation capacity in the aggregated 
first-tier balancing authority areas to determine how much uncommitted 
generation capacity can enter the study area. Morgan Stanley appears to 
confuse our use of the term uncommitted capacity, apparently believing 
we are referring to uncommitted transmission capacity. That is not the 
case as we are referring to uncommitted generation capacity. The reason 
the use of uncommitted generation capacity is appropriate is because 
our screens analyze seller's relative uncommitted generation capacity 
rather than installed generation capacity or, as suggested by Morgan 
Stanley, committed generation capacity. In particular, the SIL study 
determines the amount of simultaneous transmission capacity available 
to be imported by competing supplies from remote resources in first-
tier markets. The supplies that are available to be imported and thus 
compete are necessarily ``uncommitted.'' Further, it is our experience 
that uncommitted generation capacity can be held by any number of 
market participants based on market conditions at a given time. In 
other words, we do not agree with an assumption that the transmission 
provider is likely to be the only market participant with uncommitted 
power supplies.
e. Miscellaneous Comments
Comments
    376. PG&E states that RTOs/ISOs having knowledge and control over 
the entire control area are best suited to perform SIL studies. PG&E 
requests that the Commission allow an exemption where, in the absence 
of an accepted SIL study by an RTO/ISO, the seller may substitute 
historical import levels in place of the SIL study. In addition, PG&E 
requests that the Commission confirm that sellers that pass screens for 
each relevant geographic market without considering imports need not 
provide a simultaneous import analysis.\382\
---------------------------------------------------------------------------

    \382\ PG&E at 11-12. PG&E also requests that the Commission 
clarify how to perform the simultaneous import limitation to avoid 
the need for repetitive studies. However, PG&E did not specify what 
clarification was sought in this regard.
---------------------------------------------------------------------------

    377. Powerex has concerns about how feasible it is for marketers to 
obtain non-public data from their transmission provider that is needed 
to conduct a screen (e.g., a SIL study) on their own. Powerex notes 
that Bonneville Power Administration (BPA) and Northwest Power Pool 
(NWPP) do not, as a practice, conduct and post simultaneous 
transmission import capability studies. Therefore, Powerex asserts that 
the Commission should maintain the current flexibility of allowing 
marketers to submit credible proxy study calculations based on publicly 
available information.\383\
---------------------------------------------------------------------------

    \383\ Powerex at 5-25.
---------------------------------------------------------------------------

Commission Determination
    378. The Commission will continue to require the SIL study for the 
indicative screens and DPTs in order to assure that restrictions 
regarding importing first-tier supply are captured for seasonal peak 
conditions. Benefits of using a uniform transmission import model 
include: Transparency, consistency, clarity, and reasonable assurance 
that system conditions have been adequately captured. As also stated 
above, the Commission provides sellers flexibility to provide 
sensitivity analyses by modifying inputs to the SIL study.
    379. In regard to PG&E's belief that RTOs/ISOs are best equipped to 
conduct SIL calculations, the Commission will continue to require 
transmission-providing sellers to perform the SIL studies as necessary. 
To the extent that an RTO/ISO conducts transmission studies and makes 
that information available, a seller may rely on the information 
obtained from its RTO/ISO to conduct its SIL study. Further, the 
Commission clarifies that to the extent the transmission-owning seller 
can demonstrate it passes the screens for each relevant geographic 
market without considering imports, it need not submit a SIL 
study.\384\
---------------------------------------------------------------------------

    \384\ April 14 Order, 107 FERC ] 61,018 at P 85.
---------------------------------------------------------------------------

    380. Powerex requests that it be able to submit proxies in place of 
a SIL study. The Commission notes that transmission-providing sellers 
are required to be the first to file SIL studies, which makes the 
required data available to non-transmission owning sellers for use in 
performing their generation market power analyses.\385\ However, as the 
Commission stated in the April 14 Order,

    \385\ July 8 Order, 108 FERC ] 61,026 at 46.

an applicant may provide a streamlined application to show that it 
passes our screens. Thus, with respect to simultaneous import 
capability, if an applicant can show that it passes our screens for 
each relevant geographic market without considering imports, no such 
simultaneous import analysis needs to be provided. Further, we 
recognize that certain applicants will not have the ability to 
perform a simultaneous import capability study. Accordingly, if an 
applicant demonstrates that it is unable to perform a simultaneous 
import study for the control area in which it is located, the 
applicant may propose to use a proxy amount for transmission limits. 
---------------------------------------------------------------------------
We will consider such proposals on a case-by-case basis.\386\

    \386\ April 14 Order, 107 FERC ] 61,018 at P 85.

    381. In this regard, we note that we have accepted proxy amounts 
for

[[Page 39951]]

transmission limits and will continue to consider such requests on a 
case-by-case basis.\387\
---------------------------------------------------------------------------

    \387\ See, e.g., Tampa Electric Co., 110 FERC ] 61,026 at P 32 
(2005) (using the largest ATC into the control area at the time the 
study is conducted is a conservative assumption for import 
capability and an acceptable proxy for the SIL study).
---------------------------------------------------------------------------

f. Required SIL Study for DPT Analysis
Comments
    382. EEI and Southern propose that the Commission not mandate SIL 
studies as the only method for calculating import limits for DPT 
analysis. EEI states that while such a study may be an appropriate tool 
for indicative screens, the DPT is a more comprehensive study and the 
Commission should allow for more precise, non-standardized approaches 
for calculating simultaneous import capability for use in the DPT.\388\ 
Southern states that the apparent purpose of Appendix E is to provide a 
somewhat standardized approach to assessing simultaneous import 
capability that goes hand-in-hand with the simplified tools used to 
develop a preliminary assessment of generation market power. It argues 
that where a seller presents a more thorough generation analysis 
pursuant to a DPT, it should be permitted to offer a more thorough 
analysis of transmission import capability.\389\
---------------------------------------------------------------------------

    \388\ EEI at 24-25.
    \389\ Southern at 4, 37-38.
---------------------------------------------------------------------------

    383. NRECA responds that the Commission should not allow sellers to 
substitute alternative measures of simultaneous import capability in 
the DPT. NRECA states that while a seller should be allowed to conduct 
a SIL study that is more refined than the one required of all sellers, 
``the applicant's alternative analysis should be submitted in addition 
to, and not in lieu of, the required analysis'' in the DPT.\390\ It 
argues that otherwise, each seller will do the analysis a bit 
differently so that the analysis will favor passing the tests. 
According to NRECA, the worst-case scenario is that there will be no 
standardized approach, which would exacerbate the existing problems 
created by inadequate access to the data underlying the sellers' market 
power analysis and the lack of standard reporting and increase the 
burdens on intervenors and the Commission staff in evaluating 
applications for market-based rates and market power updates. NRECA 
states that one advantage of requiring all sellers to use a standard 
analysis, in addition to whatever other analysis they may choose to 
offer, is that it can more effectively bring to light the problems now 
hidden from view in the seller's historical practices, resulting in 
increased transparency.
---------------------------------------------------------------------------

    \390\ NRECA reply comments at 24-25.
---------------------------------------------------------------------------

Commission Determination
    384. For the reasons stated herein regarding the need to as 
accurately as possible account for transmission limitations when 
considering power supplies that can be imported into the relevant 
market under study, the Commission adopts the requirement for use of 
the SIL study as a basis for transmission access for both the 
indicative screens and the DPT analysis.
    385. The lack of flexibility in creating a simultaneous 
transmission import limit has been identified by several commenters. 
However, the Commission believes it has provided sellers sufficient 
flexibility to adequately represent their process for making 
transmission available to unaffiliated supply. The Commission shares 
NRECA's concerns that opening the process to alternative study methods 
without a specified standard may result in deviations from reasonable 
depictions of transmission limits historically applied to first-tier 
suppliers and will likely bias such studies to the benefit of the 
seller.
    386. With regard to the DPT analysis, there are several primary 
reasons for the continued use of simultaneous transmission import limit 
studies: Uniformity of modeling affiliated and unaffiliated supply, 
consideration of simultaneity, consideration of seller and affiliate 
transmission commitments and reservations, consideration of all 
internal transmission limitations, consideration of all external 
transmission limitations existing in first-tier areas, consideration of 
the seller's (or the seller's transmission provider's) practices for 
posting ATC, and consideration of peak seasonal conditions. By 
requiring the SIL study in the DPT analysis, the Commission assures 
that all factors important in determining transmission access to the 
seller's market are taken into account.
13. Procedural Issues
Commission Proposal
    387. In the NOPR, the Commission noted that Order No. 662 \391\ 
addressed concerns that CEII claims in market-based rate filings are 
overbroad. In Order No. 662, the Commission stated that it is willing 
to consider on a case-by-case basis requests for extensions of time to 
prepare protests to market-based rate filings where an intervenor 
demonstrates that it needs additional time to obtain and analyze CEII. 
In Order No. 662, the Commission encouraged the parties in cases in 
which CEII is filed to promptly negotiate a protective order governing 
access to the CEII, or privately negotiate for the submitter to provide 
the data to interested parties pursuant to an appropriate non-
disclosure agreement. The Commission sought comments in the NOPR on 
whether CEII designations remain a concern since issuance of Order No. 
662.
---------------------------------------------------------------------------

    \391\ Critical Energy Infrastructure Information, Order No. 662, 
70 FR 37031 (June 28, 2005), FERC Stats. & Regs. Regulations 
Preambles 2001-2005 ] 31,189 (June 21, 2005).
---------------------------------------------------------------------------

    388. The Commission also sought comments regarding whether the 
comment period (generally 21 days from the date of filing) provided for 
parties to file responses to the indicative screens and DPT analyses is 
sufficient. The Commission asked what would be an appropriate comment 
period if it were to establish a longer period for submitting comments 
on indicative screen and DPT analyses.
Comments
    389. A number of commenters note that intervenors should be given 
adequate time to respond to CEII designations. APPA/TAPS suggest that 
the Commission provide a process to allow interested market 
participants to obtain CEII authorization in advance of a region's 
triennial updates. They submit that such authorization would apply to 
all sellers in the region where market-based rate authority is up for 
review and would necessitate that the requester file only one 
request.\392\ Montana Counsel states that intervenors should also be 
given adequate time to respond to confidentiality claims with regard to 
non-CEII data.\393\
---------------------------------------------------------------------------

    \392\ APPA/TAPS at 35-36.
    \393\ Montana Counsel at 23-24.
---------------------------------------------------------------------------

    390. A number of commenters support extending the comment period 
for market-based rate filings. Ameren supports a 30-day comment period 
on the basis that 30 days has proven to be a sufficient comment period 
for section 203 filings.\394\ Morgan Stanley recommends a 45-to 60-day 
comment period if the Commission adopts a regional approach for updated 
market power analyses.\395\ NRECA states that under a regional filing 
process, a 21-day comment period is inadequate when several updated 
market power analysis filings are reviewed at once, and instead 
advocates a 90-day comment period from the notice of the filing or from 
the

[[Page 39952]]

date of a completed filing if additional data is requested by the 
Commission.\396\
---------------------------------------------------------------------------

    \394\ Ameren at 8.
    \395\ Morgan Stanley at 14.
    \396\ NRECA at 29.
---------------------------------------------------------------------------

Commission Determination
    391. In this Final Rule, we adopt procedures under which 
intervenors in section 205 proceedings may obtain expedited access to 
CEII or other information for which privileged treatment is sought. A 
request for access to information for which CEII status or privilege 
treatment has been claimed generally takes a few weeks for the 
Commission to process under the standard process found in 18 CFR 
388.112 and 388.113.\397\ Such a delay in receiving such information 
may make it difficult for an intervenor to submit timely comments.
---------------------------------------------------------------------------

    \397\ This is due, in part, to the fact that the Commission's 
regulations require notice and an opportunity for the submitter to 
comment on the request. The Commission recently consolidated the 
notice and opportunity to comment provision in 18 CFR 388.112(d) 
with the notification prior to release found in 18 CFR 388.112(e). 
See Critical Energy Infrastructure Information, Order No. 683, FERC 
Stats. & Regs. ] 31,228 (2006).
---------------------------------------------------------------------------

    392. An expedited process does exist for section 203 filings. 
Section 33.9 of the Commission's regulations \398\ states that a seller 
seeking to protect any part of its application from public disclosure 
must also submit a proposed protective order. Parties may sign the 
proposed protective order and obtain CEII or privileged materials in a 
more timely manner, without having to spend time negotiating the terms 
of a protective order or waiting for the Commission to process the 
request through its standard request process.
---------------------------------------------------------------------------

    \398\ 18 CFR 33.9.
---------------------------------------------------------------------------

    393. In order to ensure that intervenors have access in a timely 
manner to relevant information for which privileged treatment is 
claimed, we will adopt language similar to Sec.  33.9 in this Final 
Rule, to be codified at 18 CFR 35.37(f). We intend that the proposed 
protective order will be self implementing and not require action by 
the Commission; once a party signs the proposed protective order and 
returns it to the party submitting protected material, the submitter is 
expected to provide the material promptly to the requester. We note 
that the Commission's Model Protective Order is available on the 
Commission's Internet site and may be used as a guide in preparing 
proposed protective orders.\399\ To expedite processing, the regulation 
will require that the seller provide the CEII or privileged material to 
the requester within five days after the protective order is signed and 
submitted to the seller.
---------------------------------------------------------------------------

    \399\ See http://www.ferc.gov/legal/admin-lit/model-protective-order.pdf
.

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

    394. With respect to APPA/TAPS's suggestion to make CEII 
authorization region-wide to coincide with region-wide analysis, we do 
not believe such a step is necessary or advisable at this time. Our 
goal with CEII has always been to limit access to those with a 
legitimate need for the information. We do not expect that all market 
participants in a region will want to comment on all updated market 
power analyses within that region. Moreover, we anticipate that our 
regulatory change requiring submission of a proposed protective order 
will go a long way to resolving past difficulties in obtaining non-
public information in a timely manner.
    395. With regard to the comment period for parties to file 
responses to updated indicative screens, we believe, as we discuss 
below in the section on Implementation, that extending the comment 
period for regional updated market power analyses will allow 
intervenors a better opportunity to review and comment on those 
filings, especially considering the large number of filings that will 
be submitted at one time. Hence, we will establish a 60-day comment 
period for updated market power analyses that are filed in accordance 
with the schedule in Appendix D.
    396. With regard to the comment period for initial applications and 
for DPT analyses ordered as part of a section 206 proceeding, the 
Commission will retain the current 21-day comment period. However, we 
remain willing to consider on a case-by-case basis requests for 
extensions of time beyond 21 days to submit comments on these filings.

B. Vertical Market Power

    397. In the NOPR, the Commission proposed to replace the existing 
four-prong analysis (generation market power, transmission market 
power, other barriers to entry, affiliate abuse/reciprocal dealing) 
with an analysis that focuses on horizontal market power and vertical 
market power. Accordingly, it proposed that issues relating to whether 
the seller and its affiliates have transmission market power or whether 
they can erect other barriers to entry be addressed together as part of 
the vertical market power part of the analysis.
Comments
    398. As a general matter, commenters expressed support for the 
proposed consolidation of the transmission market power and other 
barriers to entry prong into one vertical market power analysis.\400\ 
According to EPSA, analyzing vertical market dominance in one single 
prong could be a positive step, provided that the elements of the prong 
are explicitly specified and effectively enforced.\401\ No commenter 
opposed the Commission's proposal in this regard.
---------------------------------------------------------------------------

    \400\ See Duke at 30; Southern at 38-40; EPSA at 18-19.
    \401\ EPSA at 18-19.
---------------------------------------------------------------------------

Commission Determination
    399. In light of the reasons discussed in the NOPR and the comments 
received, the Commission will adopt the NOPR proposal to consolidate 
the transmission market power analysis and other barriers to entry 
analysis into one vertical market power analysis.
1. Transmission Market Power
Commission Proposal
    400. In the NOPR, the Commission noted that it recognized that 
Order No. 888 did not eliminate all potential to engage in undue 
discrimination and preference in the provision of transmission 
service,\402\ and that it had issued a Notice of Inquiry and a NOPR 
regarding whether reforms are necessary to the Order No. 888 pro forma 
OATT.\403\ The Commission concluded that any concerns regarding the 
adequacy of the OATT should be addressed in that proceeding and not in 
the MBR Rulemaking proceeding. Therefore, in the NOPR the Commission 
proposed to continue to find that, where a seller or any of its 
affiliates owns, operates or controls transmission facilities, a 
Commission-approved OATT, as modified as a result of the OATT Reform 
Rulemaking, will adequately mitigate transmission market power.
---------------------------------------------------------------------------

    \402\ In Order No. 2000, the Commission found that 
``opportunities for undue discrimination continue to exist that may 
not be remedied adequately by [the] functional unbundling [remedy of 
Order No. 888]* * *'' Regional Transmission Organizations, Order No. 
2000, FERC Stats. & Regs., Regulations Preambles July 1996-December 
2000 ] 31,089 at 31,105 (1999), order on reh'g, Order No. 2000-A, 
FERC Stats. & Regs., Regulations Preambles July 1996-December 2000 ] 
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).
    \403\ See Preventing Undue Discrimination and Preference in 
Transmission Service, 70 FR 55796 (Sept. 23, 2005), FERC Stats. & 
Regs., ] 35,553 (2005); Preventing Undue Discrimination and 
Preference in Transmission Service, Notice of Proposed Rulemaking, 
71 FR 32636 (Jun. 6, 2006), FERC Stats. & Regs. ] 32,603 (2006); 
Preventing Undue Discrimination and Preference in Transmission 
Service, Order No. 890, 72 FR 12266 (Mar. 15, 2007), FERC Stats. & 
Regs. ] 31,241 (2007), reh'g pending.
---------------------------------------------------------------------------

    401. In the NOPR, the Commission further stated that the finding 
that an


[[Continued on page 39953]]


From the Federal Register Online via GPO Access [wais.access.gpo.gov]
]                         
 
[[pp. 39953-40002]] Market-Based Rates for Wholesale Sales of Electric Energy, 
Capacity and Ancillary Services by Public Utilities

[[Continued from page 39952]]

[[Page 39953]]

OATT adequately mitigates transmission market power rests on the 
assumption that individual sellers comply with their OATTs. If they do 
not, violations of the OATT may be cause to revoke market-based rate 
authority or to subject the seller to other remedies the Commission may 
deem appropriate, such as disgorgement of profits or civil 
penalties.\404\ However, before the Commission will consider revoking 
an entity's market-based rate authority for a violation of the OATT, 
there must be a nexus between the OATT violation and the entity's 
market-based rate authority.
---------------------------------------------------------------------------

    \404\ NOPR at P 91 (citing The Washington Water Power Co., 83 
FERC ] 61,282 (1998)).
---------------------------------------------------------------------------

    402. In addition, the Commission proposed that, if it determines, 
as a result of a significant OATT violation, that the market-based rate 
authority of a transmission provider will be revoked within a 
particular market, each affiliate of the transmission provider that 
possesses market-based rate authority will have it revoked in that same 
market on the effective date of revocation of the transmission 
provider's market-based rate authority.\405\
---------------------------------------------------------------------------

    \405\ NOPR at P 91.
---------------------------------------------------------------------------

a. OATT Requirement
Comments
    403. Several commenters state that merely having an OATT on file 
does not sufficiently mitigate vertical market power and that a 
utility's interpretation and implementation of its OATT can effectively 
eviscerate market power protections.\406\ Some commenters do not 
believe that tariff changes alone will effectively mitigate vertical 
market power in the future and therefore request a post-implementation 
proceeding one year after the issuance of a final rule in the OATT 
Reform Rulemaking to explore the effectiveness of the updated OATT in 
assessing vertical market power.\407\
---------------------------------------------------------------------------

    \406\ See, e.g., Suez/Chevron at 6; Reliant at 8.
    \407\ Suez/Chevron at 6; EPSA at 20.
---------------------------------------------------------------------------

    404. EPSA states that the outcome of the OATT Reform Rulemaking 
will determine the strength and efficacy of the vertical market power 
screen and stresses the interrelationship of that proceeding to this 
proposed rule; EPSA continues to advocate that the reform of Order No. 
888 and the ability of the OATT to mitigate against market power 
effectively be evaluated on an ongoing basis.\408\
---------------------------------------------------------------------------

    \408\ EPSA reply comments at 2, 5.
---------------------------------------------------------------------------

    405. APPA/TAPS similarly state that, for purposes of the vertical 
market power analysis, it is too early to tell whether the OATT, as 
modified in the OATT Reform Rulemaking, will mitigate transmission 
market power.\409\ TDU Systems argue that the proposals governing 
transmission planning and expansion in the OATT Reform Rulemaking are 
inadequate to mitigate the vertical market power of transmission-owning 
public utilities.\410\
---------------------------------------------------------------------------

    \409\ APPA/TAPS at 6.
    \410\ TDU Systems at 24.
---------------------------------------------------------------------------

    406. The New York Commission states that the presence of an OATT 
may mitigate a seller's transmission market power, but only with 
respect to generator access to the transmission system. It submits that 
vertically integrated utilities may be able to exercise transmission 
market power in a manner that would not necessarily violate their 
OATTs, such as through outage scheduling (e.g., delaying repair and 
maintenance of transmission lines in a load pocket in which an 
affiliated generator is located), transmission investment (e.g., 
delaying or minimizing its investment in the bulk electric transmission 
system in a load pocket in which an affiliated generator is located), 
or voltage support (e.g., inadequate support of voltage requirements 
and being slow to correct voltage support shortcomings).\411\ EPSA 
agrees with the New York Commission that the Commission cannot assume 
that any transmission provider with a Commission-approved OATT on file 
has adequately mitigated transmission market power and that ``the 
Commission should require these utilities to demonstrate that they do 
not have the incentive or ability to engage in such behavior, before 
they are granted MBR status.'' \412\
---------------------------------------------------------------------------

    \411\ New York Commission at 2-4.
    \412\ EPSA reply comments at 5-6 (citing New York Commission at 
2-4).
---------------------------------------------------------------------------

    407. On the other hand, several commenters support the Commission's 
proposal to maintain the long-standing presumption that a Commission-
approved OATT will adequately mitigate transmission market power.\413\ 
EEI states that the comprehensive approach that the Commission has 
taken to reform the OATT in the OATT Reform Rulemaking is the best 
approach to assess the adequacy of the OATT to mitigate transmission 
market power. EEI states that the Commission should continue to find 
that a Commission-approved OATT, as modified as a result of the OATT 
Reform Rulemaking, adequately mitigates transmission market power.\414\
---------------------------------------------------------------------------

    \413\ Duke at 29-32; EEI at 44-45; Southern at 38-40; 
MidAmerican reply comments at 2.
    \414\ EEI reply comments at 31-35.
---------------------------------------------------------------------------

Commission Determination
    408. The Commission will adopt the NOPR proposal that, to the 
extent that a public utility with market-based rates, or any of its 
affiliates, owns, operates, or controls transmission facilities, the 
Commission will require that a Commission-approved OATT be on file 
before granting such seller market-based rate authorization. We 
recognize that the Commission has granted a number of entities waiver 
of the requirement to file an OATT where the filing entity satisfies 
the Commission's standards for the grant of such waivers.\415\ The 
Commission will continue to grant waiver of the OATT requirement on a 
case-by-case basis, and will continue to allow sellers to rely on the 
grant of such waiver to satisfy the vertical market power part of the 
analysis. If a seller that previously received waiver of the OATT 
requirement seeks to continue to rely on that waiver to satisfy the 
vertical market power part of the analysis, it must make an affirmative 
statement in its updated market power analysis that it previously 
received such a waiver, that such waiver remains appropriate, and the 
basis for that claim. In addressing our vertical market power concerns, 
a seller, including its affiliates, that does not own, operate or 
control transmission facilities must make an affirmative statement that 
neither it, nor any of its affiliates, owns, operates or controls any 
transmission facilities.
---------------------------------------------------------------------------

    \415\ Black Creek Hydro, Inc., 77 FERC ] 61,232 at 61,941 (1996) 
(granting waiver of Order No. 888 for public utilities that can show 
that they own, operate, or control only limited and discrete 
transmission facilities (facilities that do not form an integrated 
transmission grid), until such time as the public utility receives a 
request for transmission service).
---------------------------------------------------------------------------

    409. In the NOPR, we stated that concerns regarding the adequacy of 
the OATT should be addressed in the OATT Reform Rulemaking. The 
Commission received over 6,000 pages of comments relating to potential 
reforms to the pro forma OATT in that proceeding, and on February 16, 
2007 issued a Final Rule adopting numerous improvements to the pro 
forma OATT that will further limit opportunities for transmission 
providers to unduly discriminate against transmission customers. As a 
result, we do not address in this Final Rule specific reforms to the 
OATT. In addition, the Commission declined in Order No. 890 to 
establish a one-year review period for the reformed pro forma OATT. The 
Commission stated it will continue to actively monitor compliance with 
its orders and, as necessary, institute further proceedings

[[Page 39954]]

to meet its statutory obligation to remedy undue discrimination.\416\
---------------------------------------------------------------------------

    \416\ Order No. 890, FERC Stats. & Regs. ] 31,241 at P 42.
---------------------------------------------------------------------------

    410. In response to the concerns of the New York Commission and 
EPSA that vertically integrated utilities may exercise vertical market 
power without violating their OATTs through actions such as outage 
scheduling, investment decisions and inadequate voltage support, we 
note that the OATT does address such matters as the planning and 
expansion of facilities, the duty to provide firm and non-firm service 
and good utility practice. These provisions impose definite obligations 
on transmission providers. As additional examples, outage scheduling 
aimed at affecting market prices may constitute market manipulation, 
and inadequate voltage support may violate a reliability standard under 
FPA section 215. These provisions adequately address the concerns of 
the New York Commission and EPSA.
b. OATT Violations and MBR Revocation
Comments
    411. A number of commenters agree with the Commission that market-
based rate authority should not be revoked unless and until the 
Commission finds a direct nexus between the OATT violation and the 
entity's market-based rate authority.\417\ EEI states that the 
Commission should not presume that an OATT violation is sufficient 
cause to revoke a transmission provider's market-based rate authority 
because there is no basis for such a presumption.\418\ Instead, EEI 
argues that the Commission should carefully review all facts and 
circumstances before determining that an OATT violation was a willful 
exercise in undue discrimination intended to benefit a seller's sales 
at market-based rates.\419\
---------------------------------------------------------------------------

    \417\ EEI reply comments at 31-35; MidAmerican reply comments at 
2. See also Duke at 29 (OATT violation should be a material 
violation and related in some way to the seller exercising market 
power).
    \418\ EEI reply comments at 31-35.
    \419\ EEI reply comments at 34; PNM/Tucson at 10-12.
---------------------------------------------------------------------------

    412. EPSA asserts that any violation of an entity's OATT in order 
to favor its own sales or its affiliates would create a nexus to the 
entity's market-based rate authority. If the Commission does not 
clarify this point, EPSA requests explanation regarding what exactly 
would constitute a nexus between an OATT violation and an entity's 
market-based rates.\420\
---------------------------------------------------------------------------

    \420\ EPSA at 23-24.
---------------------------------------------------------------------------

    413. TDU Systems state that it is unclear what the nexus 
requirement entails. They propose that if the transmission provider or 
one of its affiliates has market-based rate authority, there should be 
a rebuttable presumption that a violation of the OATT has the requisite 
nexus to support revocation of the market-based rate authority of the 
transmission provider and its affiliates.\421\ TDU Systems state that 
it should be up to a seller to rebut that presumption.
---------------------------------------------------------------------------

    \421\ TDU Systems at 21-23.
---------------------------------------------------------------------------

    414. APPA/TAPS assert that the nexus standard adds an unnecessary 
and counter-productive test.\422\ APPA/TAPS submit that if an OATT 
violation denies, delays, or diminishes the availability of 
transmission service or raises its costs, that alone should suffice for 
consideration of revocation of market-based rate authority. They argue 
that whether the violation had a nexus to the seller's market-based 
rate sales may be irrelevant. APPA/TAPS state that a nexus requirement 
could divert the Commission and injured parties through needless 
disputes about whether the alleged violator used the OATT violation to 
enable a specific sale under its market-based rate tariff authority, 
ignoring the larger picture painted by the transmission provider's 
anticompetitive conduct and exercise of transmission market power. 
Thus, instead of the ``nexus'' standard, APPA/TAPS states that the 
Commission should require that the OATT violation be ``material,'' 
i.e., one that denies customers the just, reasonable and non-
discriminatory and comparable transmission service that is essential to 
mitigation of transmission market power.\423\
---------------------------------------------------------------------------

    \422\ APPA/TAPS at 81-82.
    \423\ Id. at 82.
---------------------------------------------------------------------------

    415. Reliant suggests that the Commission should strengthen its 
vertical market power analysis by looking at the extent to which a 
transmission provider has denied transmission access to competing 
suppliers and should seek justification for such denials.\424\ For 
those transmission providers seeking market-based rate authority, 
Reliant asserts that any suppliers unable to reach a customer as a 
result of an inappropriate denial should not be included as competing 
generation in the transmission provider's horizontal market power 
screens until the transmission provider remedies the problem.\425\
---------------------------------------------------------------------------

    \424\ See Reliant at 8-9.
    \425\ See id.
---------------------------------------------------------------------------

    416. Duke urges the Commission to clarify that a seller's market-
based rate authority should not be subject to limitation or revocation 
if it participates in an RTO that is the subject of an OATT violation. 
According to Duke, once the transmission owner transfers control over 
its facilities to an RTO, adherence to the OATT is in the control of 
the RTO, not the transmission owner.\426\
---------------------------------------------------------------------------

    \426\ Duke at 29-32.
---------------------------------------------------------------------------

Commission Determination
    417. We will 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 nexus between the specific facts relating to the OATT 
violation and the entity's market-based rate authority, and reiterate 
our statement in the NOPR that an OATT violation may subject the seller 
to other remedies the Commission may deem appropriate, such as 
disgorgement of profits or civil penalties.\427\ As stated in the NOPR, 
the finding that an OATT adequately mitigates transmission market power 
rests on the assumption that individual entities comply with the OATT 
and there may be OATT violations in circumstances that, after applying 
the factors in the Enforcement Policy Statement,\428\ merit revocation 
or limitation of market-based rate authority. We find, however, that it 
is inappropriate to revoke a seller's market-based rate authority for 
an OATT violation unless there is a nexus between the specific facts 
relating to the OATT violation and the seller's market-based rate 
authority. This will ensure that our actions are not arbitrary or 
capricious and that they are based on an adequate factual record. We 
will not, as TDU Systems suggest, adopt a rebuttable presumption that 
any OATT violation has the requisite nexus to support revocation of 
market-based rate authority. There is a wide range of types of OATT 
violations, including ones that may be inadvertent and ones that are 
neither intended to affect, nor in fact affect, the market-based rate 
sales of the transmission provider or its affiliates. We therefore 
believe adoption of a general rebuttable presumption of a nexus for any 
and all OATT violations is not justified.
---------------------------------------------------------------------------

    \427\ NOPR at P 91 (citing The Washington Water Power Company, 
83 FERC ] 61,282 (1998)).
    \428\ Enforcement of Statutes, Orders, Rules and Regulations, 
Policy Statement on Enforcement, 113 FERC ] 61,068 (2005) 
(Enforcement Policy Statement).
---------------------------------------------------------------------------

    418. Several commenters sought clarification regarding what would 
constitute a sufficient nexus between the specific facts relating to 
the OATT violation and the seller's market-based rate authority. 
Determining what

[[Page 39955]]

constitutes a sufficient factual nexus 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 ``material'' violation of the OATT would be 
sufficient. We disagree. While a seller's inconsequential OATT 
violation would not serve as a basis for revoking that entity's market-
based rate authority, our view is that revocation is warranted only 
when an OATT violation has occurred and the violation had a nexus to 
the market-based rate authority of the violator or its affiliates.
    419. 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 sufficient 
justification for 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. We also 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.
    420. We agree with Duke that a seller's market-based rate authority 
should not be subject to limitation or revocation if it participates in 
an RTO that is the subject of an OATT violation committed by the RTO. 
We note, however, that if the seller itself is involved in an OATT 
violation, the Commission will investigate the seller's actions where 
appropriate, and may revoke market-based rate authority even though the 
seller is in an RTO.
    421. With regard to Reliant's suggestion that the Commission should 
examine the extent to which a transmission provider has denied 
transmission access to competing suppliers as part of its vertical 
market power analysis, we will allow intervenors on a case-by-case 
basis to file evidence if they believe they have been denied 
transmission access in violation of the OATT. Depending on specific 
facts, such denials could constitute an OATT violation and could 
warrant remedies such as a reduction of competing supplies for purposes 
of the horizontal analysis.
c. Revocation of Affiliates' MBR Authority
Comments
    422. Some commenters oppose the proposal to revoke the market-based 
rate authority of all affiliates of a transmission provider within a 
particular market, regardless of whether they were involved in the 
transmission provider's violation of its OATT. These commenters argue 
that the proposal to revoke all affiliates' market-based rate authority 
ignores the principles of the Commission's code of conduct and 
standards of conduct, including provisions restricting the sharing of 
market information and requiring separation of functions.\429\ They 
argue that, in light of the separation of a company's marketing 
function and transmission function under the standards of conduct, a 
company's market-based rates should not be revoked because of an OATT 
violation by an affiliated transmission owner unless there has also 
been a violation of the standards of conduct, and there is a nexus 
between the standards of conduct violation and the OATT non-
compliance.\430\ They assert that, unless there is a violation of the 
standards of conduct, merchants will have no involvement in the actions 
of transmission providers.\431\
---------------------------------------------------------------------------

    \429\ See Ameren at 8-11; PNM/Tucson at 10-12; EEI reply 
comments at 33-35; Avista at 12-13; EEI at 54; Indianapolis P&L at 
6-7.
    \430\ See PG&E at 3, 12-14; Xcel at 2 and 16.
    \431\ PG&E at 13.
---------------------------------------------------------------------------

    423. Xcel submits that, before imposing a penalty that would 
effectively penalize the merchant function, the Commission should 
require a demonstration that a utility's transmission function violated 
the OATT so as to knowingly benefit the activities of its merchant 
function.\432\ Xcel and Allegheny Energy state that the Commission 
should not penalize the merchant side of an entity when the OATT 
violation by the transmission provider causes no harm, was not the 
result of deliberate manipulative conduct, was not part of a pattern of 
misconduct, or did not involve senior management of the transmission 
provider.\433\ Similarly, Indianapolis P&L advocates punishment of a 
marketing or generation-only affiliate only to the extent such 
affiliate colludes or conspires with such OATT mis-administration or if 
such an affiliate financially benefits from such an act.\434\
---------------------------------------------------------------------------

    \432\ Xcel at 16-17. See also Avista at 12-13; PNM/Tucson at 10-
12.
    \433\ Allegheny Energy at 9-10; Xcel at 16-17.
    \434\ Indianapolis P&L at 6-7.
---------------------------------------------------------------------------

Commission Determination
    424. In response to concerns raised by commenters, we do not adopt 
the 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 the 
transmission provider's 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.
    425. This issue generally will arise when a transmission provider 
merits revocation of its market-based rate authority as a result of an 
OATT violation. We have long held that the existence of an OATT is 
deemed to mitigate vertical market power by a transmission provider and 
its affiliates in a particular market. An OATT violation by a 
transmission provider that merits revocation of the transmission 
provider's market-based rate authority in a particular market will, at 
a minimum, raise the question whether the transmission provider's 
affiliates continue to qualify for market-based rates in that market 
under the standards that we have established.\435\

[[Page 39956]]

As a result, we believe that it is appropriate to establish a 
rebuttable presumption that if we find that a transmission provider 
should lose its market-based rate authority in a particular market, all 
affiliates of the transmission provider should also lose their market-
based rate authority in the same market.
---------------------------------------------------------------------------

    \435\ 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 Company, et al., 103 FERC ] 61,182 (2003) (settlement 
of, among other issues, a practice whereby 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 Corporation, et al., 104 FERC ]61,125 (2003) (settlement 
between Enforcement staff and a transmission provider (and others in 
the corporate family) that provided a unique type of transmission 
service for its affiliate that was neither made available to non-
affiliates nor included in its FERC tariff); Tucson Electric Power 
Company, 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 Company, et al., 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 Company, 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).
---------------------------------------------------------------------------

    426. 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 
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, 
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, for example, whether (1) The affiliate 
knew of, participated in, or was an accomplice to the OATT violation, 
(2) the affiliate assisted the transmission provider in exercising 
market power, or (3) the affiliate benefited from the violation.
    427. Consistent with our approach to revocation of a transmission 
provider's market-based rates, the Commission clarifies that a decision 
to revoke the market-based rate authority of the transmission 
provider's affiliates in the affected market will also be based on a 
finding that the transmission provider's violation of its OATT has a 
nexus to the market-based rate authority of those affiliates.
2. Other Barriers to Entry
Commission Proposal
    428. The Commission proposed in the NOPR that, in order for a 
seller to demonstrate that it satisfies the Commission's vertical 
market power concerns, it must demonstrate that neither it nor its 
affiliates can erect other barriers to entry (i.e., barriers other than 
transmission). In this regard, the Commission proposed to continue to 
require a seller to provide a description of its affiliation, ownership 
or control of inputs to electric power production (e.g., fuel supplies 
within the relevant control area); ownership or control of gas storage 
or intrastate transportation or distribution of inputs to electric 
power production; and ownership or control of sites for new generation 
capacity development. The Commission also proposed to require sellers 
to make an affirmative statement that they have not erected barriers to 
entry into the relevant market and that they cannot do so.
    429. In addition, the Commission proposed to provide additional 
regulatory certainty by clarifying which inputs to electric power 
production the Commission will consider as other barriers to entry in 
its vertical market power review, and sought comments on this proposal. 
Specifically, the Commission proposed that the analysis continue to 
include the consideration of ownership or control of sites for 
development of generation in the relevant market, fuel inputs such as 
coal facilities in the relevant market, and the transportation, storage 
or distribution of inputs to electric power production such as 
intrastate gas storage and distribution systems, and rail cars/barges 
for the transportation of coal.
    430. The Commission also clarified that sellers need not address 
interstate transportation of natural gas supplies because such 
transportation is regulated by this Commission.\436\ The Commission 
explained that its open access regulations adequately prevent sellers 
from withholding interstate pipeline capacity. In addition, interstate 
pipeline capacity held by firm shippers that is not utilized or 
released is available from the pipeline on an interruptible basis. As 
to the commodity, the Commission noted that Congress has found the 
natural gas market competitive.\437\
---------------------------------------------------------------------------

    \436\ NOPR at P 93 (citing Pipeline Service Obligations and 
Revisions to Regulations Governing Self-Implementing Transportation 
Under Part 284 of the Commission's Regulations, Order No. 636, 57 FR 
13267 (Apr. 16, 1992), FERC Stats. & Regs. Regulations Preambles 
January 1991-June 1996 ] 30,939 (Apr. 8, 1992)).
    \437\ NOPR at P 93 (citing Natural Gas Wellhead Decontrol Act of 
1989, Pub. L. 101-60, 103 Stat. 157 (1989); Natural Gas Policy Act 
of 1978, section 601(a)(1), 15 U.S.C. 3431 (deregulating the 
wellhead price of natural gas)).
---------------------------------------------------------------------------

    431. The Commission also sought comment on whether ownership or 
control of other inputs to electric power production should be 
considered as potential barriers to entry and, if so, what criteria the 
Commission should use to evaluate evidence that is presented.
Comments
    432. Several commenters state that the Commission's other barriers 
to entry criteria are long-standing, well established and thus no 
expansion of current policy is necessary.\438\ They submit that the 
requirement that the analysis include the consideration of ownership or 
control of sites for development of generation in the relevant market, 
fuel inputs such as coal supplies in the relevant market, and the 
transportation, storage or distribution of inputs to electric power 
production such as intrastate gas storage and distribution systems, and 
rail cars/barges for the transportation of coal, is broad and provides 
sufficient information for the Commission to assess the seller's 
potential to erect barriers to entry. They assert that this 
information, coupled with the proposal to require sellers to make an 
affirmative statement that they have not erected barriers to entry into 
the relevant market and that they cannot do so, provides the Commission 
with appropriate information.\439\
---------------------------------------------------------------------------

    \438\ Allegheny Energy at 9-10; Southern at 38-40; EEI at 44-45.
    \439\ See, e.g., New Jersey Board at 3.
---------------------------------------------------------------------------

    433. APPA/TAPS suggest that the proposed entry barriers affirmation 
should be signed and affirmed by a senior corporate official.\440\ 
However, APPA/TAPS state that the Commission should not codify the 
specific entry barriers that it will consider given the ever-changing 
nature of electricity markets.\441\ They submit that while 
illustrations of entry barriers can provide guidance to sellers and 
market participants, the Commission should not limit the kinds of entry 
barriers it will consider.
---------------------------------------------------------------------------

    \440\ APPA/TAPS at 6, 85.
    \441\ APPA/TAPS at 6, 84-85.
---------------------------------------------------------------------------

    434. Sempra states that, to the extent the new analytic framework 
(the consolidation of the former transmission market power and other 
barriers to entry factors into the vertical market power analysis) 
would recognize existing

[[Page 39957]]

precedent and not work to place additional burdens on market-based rate 
sellers, Sempra would support it.\442\
---------------------------------------------------------------------------

    \442\ Sempra at 6-7.
---------------------------------------------------------------------------

    435. Several sellers support continuation of the Commission's 
policy that sellers need not address natural gas and its interstate 
transportation as part of their vertical market power analysis.\443\ In 
contrast, a commenter states that the Commission should not make a 
blanket exemption for sellers or their affiliates who own or control 
natural gas pipeline capacity. Notwithstanding the Commission's 
statement that natural gas interstate pipelines are regulated by the 
Commission and that the regulations adequately prevent sellers from 
withholding capacity, this commenter argues that the natural gas open 
access rules do not adequately mitigate vertical market power in all 
situations. It encourages the Commission to require sellers with 
significant firm interstate pipeline capacity rights to demonstrate 
that they do not have vertical market power.\444\
---------------------------------------------------------------------------

    \443\ See Constellation at 25; Duke at 30; PG&E at 13; Sempra at 
6.
    \444\ Drs. Broehm and Fox-Penner at 14-15.
---------------------------------------------------------------------------

    436. APPA/TAPS state that the Commission should clarify that it 
will consider control over interstate natural gas transportation if the 
issue is raised in a market-based rate proceeding.\445\ APPA/TAPS state 
that even if sellers do not have to address interstate gas 
transportation as part of the vertical market power test, intervenors 
should not be precluded from raising concerns and introducing evidence 
regarding a seller's position in the interstate natural gas 
transportation market as a potential entry barrier and APPA/TAPS seek 
clarification in this regard.\446\
---------------------------------------------------------------------------

    \445\ APPA/TAPS at 82-85.
    \446\ APPA/TAPS at 6.
---------------------------------------------------------------------------

    437. Several commenters state that the markets for the other inputs 
to generation factor (e.g., fuel supply other than natural gas, 
transportation and storage) are workably competitive and provide few 
opportunities for a seller to raise entry barriers. They therefore 
suggest that the Commission create a rebuttable presumption that the 
markets for other factor inputs such as coal, oil and distillate 
commodity markets, the transportation and storage of these fuels, sites 
for new plants, etc., are workably competitive. They urge that, absent 
a showing to the contrary, ownership or control of such assets need not 
be analyzed.\447\ In this regard, Duke states that the Commission 
should allow sellers to make the representation that they cannot erect 
such barriers, while allowing other parties to introduce evidence 
challenging such an assertion.\448\
---------------------------------------------------------------------------

    \447\ See, e.g., Duke at 30-32; Constellation at 23-27.
    \448\ Duke at 30-32.
---------------------------------------------------------------------------

    438. PG&E states that, similar to the rules for interstate 
transportation of natural gas supplies (under which Commission open 
access regulations adequately prevent sellers from withholding 
interstate gas pipeline capacity), State regulation of access to gas 
storage, natural gas pipelines, or natural gas distribution should be a 
basis for finding that an entity with ownership or control of such 
assets cannot erect barriers to entry or otherwise hold or exercise 
vertical market power in the generation market.\449\
---------------------------------------------------------------------------

    \449\ See PG&E at 3, 13-14.
---------------------------------------------------------------------------

    439. SoCal Edison urges the Commission to clarify that, with regard 
to sites for building generation, mere ownership of real estate does 
not reasonably support an inference of a barrier to entry, and that 
sellers are not required, in the first instance, to make any 
affirmative demonstration of the absence of potential that their real 
estate holdings might constitute a theoretical barrier to entry. 
Rather, the Commission should clarify that it would pursue such inquiry 
only to the extent colorable issues are raised by way of protest or 
intervention.\450\ Sempra states the Commission should modify the 
regulatory text in three respects. First, the Commission should 
explicitly exclude from the definition of ``inputs to electric power 
production'' in proposed Sec.  35.36(a)(4) interstate transportation of 
natural gas supplies (both ownership/control of facilities as well as 
ownership/control of capacity) and the gas commodity itself. Second, 
the Commission should also exclude from the definition of ``inputs to 
electric power production'' intrastate natural gas facilities or 
distribution facilities, particularly where such facilities are 
operated under pervasive State regulations and in accordance with open 
access principles. Third, the Commission should make clear in this 
provision and at Sec.  35.27(e) of its proposed regulations (pertaining 
to a seller's vertical market power analysis), that the only ``inputs'' 
that need to be addressed are those present in the seller's relevant 
geographic market(s).\451\
---------------------------------------------------------------------------

    \450\ SoCal Edison at 2, 19.
    \451\ Sempra at 6.
---------------------------------------------------------------------------

Commission Determination
    440. As discussed above, the Commission will adopt the NOPR 
proposal to consider a seller's ability to erect other barriers to 
entry as part of the vertical market power analysis, but we will modify 
the requirements when addressing other barriers to entry. We also 
provide clarification below regarding the information that a seller 
must provide with respect to other barriers to entry (including which 
inputs to electric power production the Commission will consider as 
other barriers to entry) and we modify the proposed regulatory text in 
that regard.
    441. In this rule, the Commission draws a distinction between two 
categories of inputs to electric power production: One consisting of 
natural gas supply, interstate natural gas transportation (which 
includes interstate natural gas storage), oil supply, and oil 
transportation, and another consisting of intrastate natural gas 
transportation, intrastate natural gas storage or distribution 
facilities; sites for generation capacity development; and sources of 
coal supplies and the transportation of coal supplies such as barges 
and rail cars.
    442. With regard to the first category, based upon the comments 
received and further consideration, the Commission will not require a 
description or affirmative statement with regard to ownership or 
control of, or affiliation with an entity that owns or controls, 
natural gas and oil supply, including interstate natural gas 
transportation and oil transportation.
    443. In the case of natural gas, prices for wellhead sales were 
decontrolled by Congress.\452\ Further, the Commission has granted 
other sellers blanket authority to make sales at market rates. In the 
case of transportation of natural gas, pipelines operate pursuant to 
the open and non-discriminatory requirements of Part 284 of the 
Commission's regulations.\453\ These regulations mandate that all 
available pipeline capacity be posted on the pipelines' Web site, and 
that available capacity cannot be withheld from a

[[Page 39958]]

shipper willing to pay the maximum approved tariff rate.
---------------------------------------------------------------------------

    \452\ INGAA v. FERC, 285 F.3d 18 (D.C. Cir. 2002); Natural Gas 
Decontrol Act of 1989, H.R. Rep. No. 101-29, 101st Cong., 1st Sess., 
at 6 (1989).
    \453\ See, e.g., Pipeline Service Obligations and Revisions to 
Regulations Governing Self-Implementing Transportation Under Part 
284 of the Commission's Regulations, Order No. 636, 57 FR 13267 
(Apr. 16, 1992), FERC Stats. & Regs. Regulations Preambles January 
1991-June 1996 ] 30,939 (Apr. 8, 1992); Regulation of Short-Term 
Natural Gas Transportation Services and Regulation of Interstate 
Natural Gas Transportation Services, Order No. 637, FERC Stats. & 
Regs. Regulations Preambles July 1996-December 2000 ] 31,091 (Feb. 
9, 2000); order on reh'g, Order No. 637-A, FERC Stats. & Regs. 
Regulations Preambles July 1996-December 2000) ] 31,099 (May 19, 
2000); reh'g denied, Order No. 637-B, 92 FERC ] 61,062 (2000); aff'd 
in part and denied in part.
---------------------------------------------------------------------------

    444. Similarly, we note that oil pipelines are common carriers 
under the Interstate Commerce Act, specifically under section 1(4), and 
are required to provide transportation service ``upon reasonable 
request therefore'' \454\ and that Congress has not chosen to regulate 
sales of oil.
---------------------------------------------------------------------------

    \454\ 49 App. U.S.C. 1(4).
---------------------------------------------------------------------------

    445. In response to APPA/TAPS' request for clarification, we note 
that as an initial matter, to the extent intervenors are concerned 
about a seller's market power from ownership or control of interstate 
natural gas transportation, this would be actionable first in a 
complaint proceeding under section 5 of the Natural Gas Act before 
turning to market-based rate consequences.
    446. With regard to the second category, in light of the comments 
received, and upon further consideration, the Commission adopts a 
rebuttable presumption that sellers cannot erect barriers to entry with 
regard to the ownership or control of, or affiliation with any entity 
that owns or controls, intrastate natural gas transportation, 
intrastate natural gas storage or distribution facilities; sites for 
generation capacity development; and sources of coal supplies and the 
transportation of coal supplies such as barges and rail cars.\455\ To 
date, the Commission has not found such ownership, control or 
affiliation to be a potential barrier to entry warranting further 
analysis in the context of market-based rate proceedings. However, 
unlike the first category of inputs, the Commission does not have 
sufficient evidence to remove these inputs from the analysis entirely. 
Accordingly, we will rebuttably presume that ownership or control of, 
or affiliation with an entity that owns or controls, intrastate natural 
gas transportation, intrastate natural gas storage or distribution 
facilities; sites for generation capacity development; and sources of 
coal supplies and the transportation of coal supplies such as barges 
and rail cars do not allow a seller to raise entry barriers, but will 
allow intervenors to demonstrate otherwise. We note that this 
rebuttable presumption only applies if the seller describes and attests 
to these inputs to electric power production, as described herein.
---------------------------------------------------------------------------

    \455\ We modify the definition of ``inputs to electric power 
production'' in 18 CFR 35.36(a)(4) to reflect this clarification.
---------------------------------------------------------------------------

    447. With regard to this second category of inputs to electric 
power production, we will require a seller to provide a description of 
its ownership or control of, or affiliation with an entity that owns or 
controls, intrastate natural gas transportation, storage or 
distribution facilities; sites for generation capacity development; and 
sources of coal supplies and the transportation of coal supplies such 
as barges and rail cars. The Commission will require sellers to provide 
this description and to make an affirmative statement, with some 
modifications to the affirmative statement from what was proposed in 
the NOPR. Instead of requiring sellers to make an affirmative statement 
that they have not erected barriers to entry into the relevant market, 
we will require sellers to make an affirmative statement that they have 
not erected barriers to entry into the relevant market and will not 
erect barriers to entry into the relevant market. We clarify that the 
obligation in this regard applies both to the seller and its 
affiliates, but is limited to the geographic market(s) in which the 
seller is located.
    448. We therefore modify the proposed regulations to require a 
seller to provide a description of its ownership or control of, or 
affiliation with an entity that owns or controls, intrastate natural 
gas transportation, intrastate natural gas storage or distribution 
facilities; sites for generation capacity development; sources of coal 
supplies and the transportation of coal supplies such as barges and 
rail cars, to ensure that this information is included in the record of 
each market-based rate proceeding. In addition, a seller is required to 
make an affirmative statement that it has not erected barriers to entry 
into the relevant market and will not erect barriers to entry into the 
relevant market.
    449. While some commenters raise concerns that codification of 
these possible barriers may inappropriately limit the analysis of a 
seller's potential to erect other barriers to entry, we clarify that we 
are codifying what showing a seller must make in order to receive 
authority to make sales of electric power at market-based rates. By so 
doing, we are not preventing intervenors from raising other barriers to 
entry concerns for consideration on a case-by-case basis. This approach 
will allow unique or newly developed barriers to entry to be brought 
before the Commission.
    450. We will not adopt APPA/TAPS' proposal that the affirmation be 
signed and affirmed by a senior corporate officer. Section 35.37(b) of 
the Commission's regulations requires sellers to ``provide accurate and 
factual information and not submit false or misleading information, or 
omit material information, in any communication with the Commission * * 
*''. \456\ The Commission has ample authority to enforce its 
regulations, and therefore does not believe that it is necessary in 
these circumstances to require the affirmative statement to be signed 
by a senior corporate official.
---------------------------------------------------------------------------

    \456\ 18 CFR 35.41(b) (formerly 18 CFR 35.37(b)).
---------------------------------------------------------------------------

    451. The changes made to the evaluation of other barriers to entry, 
as described above, should not be more burdensome on market-based rate 
sellers than that which is currently in place. For the most part, the 
Commission is maintaining its current policy, with some variation and 
additional guidance on what is required. The policy adopted in this 
Final Rule should provide sellers with additional clarity regarding 
what needs to be addressed as a potential other barrier to entry and 
the way in which to address it.
3. Barriers Erected or Controlled by Other Than The Seller
Comments
    452. APPA/TAPS state that entry conditions and barriers, regardless 
of origin, need to be considered in both the horizontal and vertical 
market power tests.\457\ APPA/TAPS state that the Commission should not 
focus solely on entry barriers erected by the seller itself and that 
the Commission must be receptive to claims that entry barriers in the 
seller's market provide or enhance market power, even if the seller 
itself did not erect the barriers.\458\ Another commenter states that 
the Commission should maintain a separate evaluation on other barriers 
to entry that are not caused by a seller, thus requiring a seller to 
address barrier to entry issues to the relevant market, even if those 
barriers are not caused by a seller or its affiliates.
---------------------------------------------------------------------------

    \457\ APPA/TAPS at 6.
    \458\ APPA/TAPS at 82-84.
---------------------------------------------------------------------------

Commission Determination
    453. The Commission finds that it is not reasonable to routinely 
require sellers to make a showing regarding potential barriers to entry 
that others might erect and that are beyond the seller's control. 
However, we will allow intervenors to present evidence in this regard, 
and by this means we will be able to assess the existence of barriers 
to entry beyond the seller's control but which may affect the seller's 
ability to exercise market power. Should a potential barrier in the 
relevant market

[[Page 39959]]

be raised by an intervenor, the Commission will address such claims on 
a case-by-case basis.
4. Planning and Expansion Efforts
    454. In the NOPR, the Commission noted that several commenters had 
suggested that a transmission planning and expansion process can 
ameliorate vertical market power, and, accordingly, the Commission was 
seeking comment on the issues of transmission planning and expansion in 
the notice of proposed rulemaking in the OATT Reform Rulemaking. The 
Commission sought comment in the NOPR on whether the planning and 
expansion efforts in the OATT Reform Rulemaking would address 
commenters' concerns here.
Comments
    455. APPA/TAPS state that there will be a continuing need to 
address transmission market power issues, even after adoption of a 
revised pro forma OATT, because the improvements in transmission 
planning and expansion will not be immediately felt.\459\ EPSA states 
that it advocates robust, independent and mandatory regional planning 
as a means to combat vertical market power and ensure competitive 
markets.\460\
---------------------------------------------------------------------------

    \459\ APPA/TAPS at 80-85.
    \460\ EPSA at 27.
---------------------------------------------------------------------------

    456. TDU Systems recommend that the Commission revoke a 
transmission provider's market-based rate authority if it fails to 
build transmission to accommodate the needs of its transmission 
customers demonstrated through an open, joint planning process.\461\ 
TDU Systems submit that willful failure to plan, maintain and expand 
the transmission system to meet transmission customers' needs is an 
abuse of vertical market power and creates structural barriers to 
competition.
---------------------------------------------------------------------------

    \461\ TDU Systems at 21-23.
---------------------------------------------------------------------------

    457. ELCON states that while it is encouraged by proposals in the 
OATT Reform Rulemaking, it recommends that transmission market power be 
the subject of a new rulemaking.\462\ Similarly, EPSA asserts that a 
technical conference to develop the barriers to entry portion of the 
screens would help ensure an open, accessible, and robust competitive 
market.\463\
---------------------------------------------------------------------------

    \462\ ELCON at 5-6.
    \463\ EPSA at 28.
---------------------------------------------------------------------------

Commission Determination
    458. We find that our reforms to the pro forma OATT to require 
coordinated transmission planning on a local and regional level address 
the concerns raised by commenters. While we recognize that the 
transmission planning reforms in Order No. 890 are still in the process 
of being implemented, failure to plan, maintain and expand the 
transmission system in accordance with the applicable, Commission-
approved OATT has always been, and will continue to be, an OATT 
violation. Order No. 890 provides for revocation of an entity's, and 
possibly that of its affiliates, market-based rate authority in 
response to an OATT violation upon a finding of a specific factual 
nexus between the violation and the entity's market-based rate 
authority.\464\ Should such a violation occur, the Commission will 
address it in that context. The Commission does not find that the need 
exists to convene a technical conference in this regard. The OATT 
Reform Rulemaking dealt extensively with this issue and the Commission 
finds that it has been adequately addressed in Order No. 890.
---------------------------------------------------------------------------

    \464\ Order No. 890, FERC Stats. & Regs. ] 31,241 at P 1743, 
1747.
---------------------------------------------------------------------------

5. Monopsony Power
    459. In the NOPR, the Commission sought comment on whether the 
exercise of buyer's market power by the transmission provider should be 
considered a potential barrier to entry and, if so, what criteria the 
Commission should use to evaluate evidence that is presented.
Comments
    460. Allegheny states that the NOPR provided no explanation for why 
a transmission provider's buyer's market power should be relevant to 
the analysis.\465\ EEI argues that the Commission should not consider 
buyer's market power as a barrier to entry because it is not relevant 
to the analysis. According to EEI, the market-based rate analysis 
considers the ability of the applicant to exercise market power as a 
seller, not a buyer, which is consistent with the Commission's 
authority under section 205 of the FPA, which regulates the sale of 
electricity. EEI asserts that states generally have jurisdiction over 
the purchase of electricity by franchised utilities.\466\
---------------------------------------------------------------------------

    \465\ Allegheny Energy at 10.
    \466\ EEI at 43.
---------------------------------------------------------------------------

    461. EPSA argues that if a utility holds a dominant purchasing 
position in the wholesale marketplace that allows it to exert excessive 
and discretionary buying power (of both supply and supply generation 
facilities), the exercise of market power will then lie with the buyer, 
not the seller. This problem is exacerbated when such a purchasing 
utility also owns, controls or dispatches its own proprietary supply 
and the relevant transmission system.
    462. EPSA states that some would argue that the Commission cannot 
order economic dispatch or competitive solicitation because the FPA 
grants the Commission jurisdiction over sales, not purchases. However, 
EPSA submits that the Commission would not be mandating purchases, but 
eliminating the exercise of market power which directly raises the 
prices for wholesale sales. In so doing, the Commission would be using 
its tools under sections 205 and 206 of the FPA to ensure just and 
reasonable wholesale rates by allowing competitive alternatives to 
enter the market and protecting consumers from practices that will 
result in excessive rates and charges. EPSA argues that the Commission 
must develop a transparent, methodical process for assessing this 
segment of the vertical market power analysis. EPSA submits that load 
serving entities that are transmission providers must, in addition to 
providing enhanced transmission services, facilitate accessible long-
term markets through all-source competitive procurement processes, 
preferably via state created and supervised means, with independent 
third party oversight. It asserts that the Commission must achieve and 
ensure these goals through a transparent, well-developed process. EPSA 
requests that the Commission convene a technical conference in order to 
fully develop that process and ensure that barriers to entry are 
properly mitigated.\467\
---------------------------------------------------------------------------

    \467\ EPSA at 26-27.
---------------------------------------------------------------------------

Commission Determination
    463. EPSA's proposal not only raises jurisdictional issues, but 
EPSA has failed to provide specific instances in which the exercise of 
monopsony power has taken place and has provided no guidance as to how 
buyer market power should be measured (even assuming the Commission has 
jurisdiction to address it). The Commission does not believe it is 
appropriate to attempt to address these difficult issues without 
specific evidence of monopsony power and a clear delineation of the 
State-Federal jurisdiction issues that would arise in the context of a 
specific seller and specific set of circumstances. For the same reason, 
we will not grant EPSA's request to convene a technical conference to 
address such issues generically. Until EPSA or others provide such 
information concerning a particular seller in either a market-based

[[Page 39960]]

rate proceeding or a complaint, we defer judgment on the many difficult 
issues raised by EPSA.

C. Affiliate Abuse

1. General Affiliate Terms and Conditions
a. Codifying Affiliate Restrictions in Commission Regulations
Commission Proposal
    464. In the NOPR the Commission proposed to discontinue referring 
to affiliate abuse as a separate ``prong'' of the market-based rate 
analysis and instead proposed to codify in the regulations at 18 CFR 
part 35, subpart H, an explicit requirement that any seller with 
market-based rate authority must comply with the affiliate power sales 
restrictions and other affiliate restrictions. The Commission proposed 
to address affiliate abuse by requiring that the conditions set forth 
in the proposed regulations be satisfied on an ongoing basis as a 
condition of obtaining and retaining market-based rate authority. The 
Commission indicated that a seller seeking to obtain or retain market-
based rate authority will be obligated to provide a detailed 
description of its corporate structure so that the Commission can be 
assured that the Commission's requirements are being applied correctly. 
In particular, the Commission proposed that sellers with franchised 
service territories be required to make a showing regarding whether 
they serve captive customers and to identify all ``non-regulated'' 
power sales affiliates, such as affiliated marketers and 
generators.\468\
---------------------------------------------------------------------------

    \468\ In the NOPR, the Commission proposed to use the term 
``non-regulated power sales affiliate.'' As discussed below, this 
Final Rule uses the term ``market-regulated power sales affiliate'' 
instead. ``Market-regulated'' power sales affiliates, for purposes 
of this rule, refers to sellers that sell at market-based rates 
rather than cost-based rates. If such sellers are public utilities, 
technically, they are not unregulated since they must receive 
market-based rate authority from the Commission and are subject to 
ongoing oversight by the Commission. See discussion infra.
---------------------------------------------------------------------------

    465. The Commission further proposed that, as a condition of 
receiving market-based rate authority, sellers must adopt the MBR 
tariff (included as Appendix A to the NOPR) which includes a provision 
requiring the seller to comply with, among other things, the affiliate 
restrictions in the regulations. The Commission noted that failure to 
satisfy the conditions set forth in the affiliate restrictions will 
constitute a tariff violation. The Commission sought comment on these 
proposals
Comments
    466. As a general matter, commenters support the Commission's 
proposal to codify the affiliate restrictions in the Commission's 
regulations.\469\ No comments were received opposing the proposal to 
codify affiliate restrictions in the Commission's regulations.
---------------------------------------------------------------------------

    \469\ See generally APPA/TAPS at 7; 85-86.
---------------------------------------------------------------------------

Commission Determination
    467. The Commission will adopt the proposal in the NOPR to 
discontinue considering affiliate abuse as a separate ``prong'' of the 
market-based rate analysis and instead codify in the Commission's 
regulations in Sec.  35.39 an explicit requirement that any seller with 
market-based rate authority must comply with the affiliate 
restrictions. This will address affiliate abuse by requiring that the 
conditions set forth in the regulations be satisfied on an ongoing 
basis as a condition of obtaining and retaining market-based rate 
authority. Included in the regulations will be a provision expressly 
prohibiting power sales between a franchised public utility with 
captive customers and any market-regulated power sales affiliates 
without first receiving Commission authorization for the transaction 
under section 205 of the FPA. Also included in the regulations will be 
the requirements that have previously been known as the market-based 
rate ``code of conduct,'' as those requirements have been revised in 
this Final Rule.
    468. Additionally, although we do not adopt the proposal to require 
that, as a condition of receiving market-based rate authority, sellers 
must adopt the MBR tariff (included as Appendix A to the NOPR), we do 
adopt a set of standard tariff provisions that we will require each 
seller to include in its market-based rate tariff, including a 
provision requiring the seller to comply with, among other things, the 
affiliate restrictions in the regulations. We further adopt the 
proposal that failure to satisfy the conditions set forth in the 
affiliate restrictions will constitute a tariff violation.
b. Definition of ``Captive Customers''
Commission Proposal
    469. The Commission stated in the NOPR that, among other things, in 
the Commission's Final Rule on transactions subject to section 203 of 
the FPA, the Commission defined the term ``captive customers'' to mean 
``any wholesale or retail electric energy customers served under cost-
based regulation.''\470\ The Commission sought comment on whether the 
same definition should be used for purposes of this rule.
---------------------------------------------------------------------------

    \470\ Transactions Subject to FPA section 203, Order No. 669-A, 
71 FR 28422 (May 16, 2006), FERC Stats. & Regs. ] 31,214 (2006). See 
also Repeal of the Public Utility Holding Company Act of 1935 and 
Enactment of the Public Utility Holding Company Act of 2005, Order 
No. 667-A, 71 FR 28446 (May 16, 2006), FERC Stats. & Regs. ] 31, 213 
(2006).
---------------------------------------------------------------------------

Comments
    470. While a number of commenters support the Commission's proposal 
to codify the affiliate abuse ``prong'' in the Commission's 
regulations,\471\ they comment that the proposed affiliate abuse 
restrictions do not do enough to protect retail customers from 
affiliate abuse.\472\ NASUCA argues that affiliate abuse restrictions 
should be applicable to any affiliate with any retail customers, 
whether or not the retail affiliate is a ``franchised'' utility, 
whether or not it has a State-imposed ``service obligation,'' and 
whether or not its customers are characterized as ``captive.'' NASUCA 
submits that the Commission should not rely on a State's adoption of a 
retail access regime for any determination that a customer is not 
captive. Further, although NASUCA comments that the Commission's 
proposed definition for ``captive customers'' is an improvement from 
the text of the proposed regulation (which contains no definition of 
``captive customers''), NASUCA suggests it could also invite 
distinctions turning on the meaning of ``cost-based regulation'' that 
might cause future uncertainty in some circumstances and a 
corresponding loss of customer protection.\473\
---------------------------------------------------------------------------

    \471\ New Jersey Board at 3.
    \472\ NASUCA at 20-30.
    \473\ NASUCA at 20-30.
---------------------------------------------------------------------------

    471. New Jersey Board argues that when customers lack realistic 
alternatives to purchasing power from their local utility, regardless 
of a legal right to competitive power suppliers, such customers are 
still captive. New Jersey Board states that most customers in retail 
choice states still rely on the provider-of-last-resort for electric 
service and, thus, are still captive customers.\474\ New Jersey Board 
comments that, due to the relatively young retail choice and 
deregulation programs in many states, ``it would be premature to 
declare electric retail choice to be vibrant enough to leave consumer 
protection from affiliate abuses completely to the marketplace.'' \475\ 
New Jersey Board states that, even where there are a few

[[Page 39961]]

providers that comprise the market, such oligopolies often exhibit the 
same lack of competition and high prices as are seen in a monopoly 
market. Thus, affiliate abuse would remain a concern where utilities 
would be granted market-based rate authority.\476\
---------------------------------------------------------------------------

    \474\ New Jersey Board reply comments at 3-4.
    \475\ Id. at 5.
    \476\ Id.
---------------------------------------------------------------------------

    472. AARP similarly comments that the proposed definition of 
``captive customers'' fails to capture the potential for adverse 
impacts on retail customers of ``default'' suppliers and thus, the 
coverage of the Commission's affiliate restrictions should be expanded 
to prevent customers from bearing the costs of non-regulated marketing 
affiliates of the public utility they rely on for reliable 
service.\477\
---------------------------------------------------------------------------

    \477\ AARP at 10-11.
---------------------------------------------------------------------------

    473. ELCON suggests that ``captive customers'' should be defined as 
any end-users that do not have real competitive opportunities.\478\ It 
recommends that the Commission adopt a case-specific approach to 
identifying captive customers to account for the failure of retail 
competition in many restructured states.
---------------------------------------------------------------------------

    \478\ ELCON at 2, 7-8.
---------------------------------------------------------------------------

    474. A number of other commenters argue that the proposed 
definition of ``captive customers'' is too broad \479\ and would 
improperly include customers with competitive alternatives. They state 
that the Commission should clarify that ``captive customers'' does not 
include customers in states with retail choice.\480\ Duke recommends 
that the Commission define ``captive customer'' as ``any electric 
energy customer that cannot choose an alternative energy supplier.'' 
\481\ Duke adds that initial commenters, such as ELCON, provide no 
support for their assertion that state retail access programs do not 
generate effective competition and that most provider-of-last-resort 
customers are actually captive.
---------------------------------------------------------------------------

    \479\ Ameren at 11-14; Allegheny at 12-13; EEI at 44; 
FirstEnergy at 13; Duke at 4, 32; and Duquesne at 4.
    \480\ Constellation argues that customers are not to be 
considered ``captive'' and a seller is therefore not considered a 
franchised public utility when a retail choice program is in place 
for the public utility's retail customers. Constellation at 4.
    \481\ Duke at 32-36. Duke reply comments at 22-23.
---------------------------------------------------------------------------

    475. Ameren comments that while there are sellers with market-based 
rate authority that have no captive wholesale customers for energy, but 
do have a cost-based rate schedule for reactive power supply, the fact 
that a seller has wholesale customers under a single cost-based rate 
for reactive power should not render the entity a seller with ``captive 
customers'' and therefore, subject to the affiliate restrictions.\482\ 
It states that such a seller would have no ability to transfer benefits 
from its ``captive customers'' (customers taking reactive power 
services at cost-based rates) to subsidize its unregulated market-based 
rate sales, given the different products at issue and the restrictions 
of the cost-based rates for reactive power.
---------------------------------------------------------------------------

    \482\ Ameren at 12.
---------------------------------------------------------------------------

    476. APPA/TAPS submit that the definition of ``captive customers'' 
should include wholesale transmission customers captive to the 
transmission provider's system.\483\ APPA/TAPS state that affiliate 
abuse not only raises costs to wholesale customers, it can also harm 
competition such as through cross-subsidization that provides the 
seller with an unfair competitive advantage. Therefore, APPA/TAPS state 
that wholesale transmission customers captive to the transmission 
provider's system are particularly vulnerable to this kind of 
competitive harm and should be included in the definition of ``captive 
customers'' in the regulations.\484\
---------------------------------------------------------------------------

    \483\ APPA/TAPS at 7, 86-87.
    \484\ Id. at 86-87.
---------------------------------------------------------------------------

    477. EEI responds to APPA/TAPS' comment by stating that it is 
``completely unnecessary'' to include transmission dependent utilities 
in the definition of captive customers since Order No. 888 already 
provides sufficient protections for transmission customers. 
Additionally, EEI replies that transmission dependent utilities are 
like customers with retail choice who have chosen to stay under cost-
based rates while other transmission customers have broader options. 
EEI responds that the Commission does not currently consider such 
customers captive and there is no reason to change this policy.\485\
---------------------------------------------------------------------------

    \485\ EEI reply comments at 35-36.
---------------------------------------------------------------------------

Commission Determination
    478. The Commission adopts the NOPR proposal to define ``captive 
customers'' as ``any wholesale or retail electric energy customers 
served under cost-based regulation.''
    479. The Commission clarifies in response to several comments that 
the definition of ``captive customers'' does not include those 
customers who have retail choice, i.e. the ability to select a retail 
supplier based on the rates, terms and conditions of service offered. 
Retail customers who choose to be served under cost-based rates but 
have the ability, by virtue of State law, to choose one retail supplier 
over another, are not considered to be under ``cost-based regulation'' 
and therefore are not ``captive.''
    480. As the Commission has explained, retail customers in retail 
choice states who choose to buy power from their local utility at cost-
based rates as part of that utility's provider-of-last-resort 
obligation are not considered captive customers because, although they 
may choose not to do so, they have the ability to take service from a 
different supplier whose rates are set by the marketplace. In other 
words, they are not served under cost-based regulation, since that term 
indicates a regulatory regime in which retail choice is not 
available.\486\ On the other hand, in a regulatory regime in which 
retail customers have no ability to choose a supplier, they are 
considered captive because they must purchase from the local utility 
pursuant to cost-based rates set by a State or local regulatory 
authority.\487\ Therefore, with this clarification, the Commission will 
adopt the definition of ``captive customers'' proposed in the NOPR and 
clarifies, that, as the Commission did in Order No. 669-A, we will 
include the definition of captive customers in the regulations. 
Regarding wholesale customers, sellers should continue to explain why, 
if they have wholesale customers, those customers are not captive.
---------------------------------------------------------------------------

    \486\ Duquesne Light Holdings, Inc., 117 FERC ] 61,326 at P 38 
(2006).
    \487\ Where a utility has captive retail customers, but 
industrial customers have retail choice, we would consider that 
utility to have captive customers because the retail residential 
customers are captive.
---------------------------------------------------------------------------

    481. We note that it is not the role of this Commission to evaluate 
the success or failure of a State's retail choice program including 
whether sufficient choices are available for customers inclined to 
choose a different supplier. In this regard, the states are best 
equipped to make such a determination and, if necessary, modify or 
otherwise revise their retail access programs as they deem appropriate. 
Further, to the extent a retail customer in a retail choice state 
elects to be served by its local utility under provider-of-last-resort 
obligations, the State or local rate setting authority, in determining 
just and reasonable cost-based retail rates, would in most 
circumstances be able to review the prudence of affiliate purchased 
power costs and disallow pass-through of costs incurred as a result of 
an affiliate undue preference.
    482. We also decline to include transmission customers in the 
definition of ``captive customers'' for purposes of market-based rates. 
We agree with EEI that the Commission's open access

[[Page 39962]]

policies protect transmission customers from the exercise of vertical 
market power. In this regard, we note that the Commission recently 
issued Order No. 890, which revised the pro forma OATT to ensure that 
it achieves its original purpose of remedying undue discrimination. 
Order No. 890 provided greater clarity regarding the requirements of 
the pro forma OATT and greater transparency in the rules applicable to 
the planning and use of the transmission system, in order to reduce 
opportunities for the exercise of undue discrimination, make undue 
discrimination easier to detect, and facilitate the Commission's 
enforcement of the tariff.
    483. In response to Ameren's comments that a seller with wholesale 
customers under a single cost-based rate for reactive power should not 
be considered a seller with ``captive customers'' subject to the 
affiliate restrictions, we agree that such customers are not captive 
for purposes of market-based rates. The concerns underlying the 
affiliate restrictions do not apply to sales of reactive power because 
those sales are typically either made to transmission providers so that 
the transmission provider can satisfy its obligation to provide 
reactive power or made by the transmission provider under its 
applicable OATT.
c. Definition of ``Non-Regulated Power Sales Affiliate''
Commission Proposal
    484. Proposed Sec.  35.36(a)(6) defined ``non-regulated power sales 
affiliate'' as ``any non-traditional power seller affiliate, including 
a power marketer, exempt wholesale generator, qualifying facility or 
other power seller affiliate, whose power sales are not regulated on a 
cost basis under the FPA.''
Comments
    485. A number of commenters seek clarification and modification of 
the Commission's proposed definition of ``non-regulated power sales 
affiliate.''
    486. Southern requests clarification that a franchised public 
utility does not become a non-regulated power sales affiliate simply 
because it may make some wholesale sales under market-based rate 
authority.
    487. SoCal Edison argues that the Commission offers no explanation 
for including Qualifying Facilities (QFs) in the definition of ``non-
regulated power sales affiliate.'' It states that the proposed 
definition of non-regulated power sales affiliate would subject QFs 
that may not have market-based rate authority to the code of conduct. 
It states that the NOPR proposal would constitute a departure from 
traditional PURPA implementation and from the Commission's recently 
revised regulations reaffirming that QF contracts created pursuant to a 
statutory regulatory authority's implementation of PURPA are exempt 
from review under sections 205 and 206 of the FPA.\488\ PG&E asserts 
that the Commission should clarify the meaning of ``non-regulated power 
sales affiliate'' so that it does not encompass all affiliates such as 
parent companies or the natural gas LDC function of the regulated, 
franchised utility.\489\
---------------------------------------------------------------------------

    \488\ SoCal Edison at 4-6.
    \489\ PG&E at 14-21.
---------------------------------------------------------------------------

    488. Xcel states that it is not clear whether the following result 
was intended, but the definition arguably could cover a ``traditional'' 
utility with a franchised retail service territory that had converted 
all of its wholesale sales from cost-based to market-based rates. 
According to Xcel, not all utilities will be selling at cost-based 
rates at wholesale, even though they may still be doing so at retail in 
franchised service territories.\490\ Xcel does not believe that it 
would be reasonable to exclude from the definition of ``non-regulated 
power sales affiliate'' a utility that serves retail customers under a 
franchised service territory. Xcel also comments that the Commission 
should allow a waiver provision for utilities' subsidiaries or 
affiliates to be treated under the Commission's affiliate sales rules 
as affiliated utilities rather than as ``non-regulated power sales 
affiliates.'' \491\ Xcel believes that the proposed definition would 
generally serve to demarcate affiliates that should be treated as 
regulated from those that should be treated as non-regulated under the 
Commission's affiliate rules but states that it is not desirable or 
beneficial to draw a completely bright line between the two. Xcel 
states that some flexibility may be beneficial for both utilities and 
their customers and the Commission should not foreclose innovative 
structures by adopting hard and fast rules.\492\
---------------------------------------------------------------------------

    \490\ Xcel at 15.
    \491\ Id.
    \492\ Id. at 16.
---------------------------------------------------------------------------

    489. NASUCA also suggests revisions to this definition, out of 
concern that several of the terms used (non-regulated, non-traditional, 
regulated on a cost basis) are vague, inaccurate and unnecessary.\493\ 
NASUCA suggests that the term be renamed ``power sales affiliate with 
market-based rates'' and defined as ``any power seller affiliate 
utility, including a power marketer, exempt wholesale generator, 
qualifying facility or other power seller affiliate, with market-based 
rates authorized under these rules or Commission orders.'' \494\
---------------------------------------------------------------------------

    \493\ NASUCA at 30.
    \494\ Id. at 30.
---------------------------------------------------------------------------

Commission Determination
    490. The Commission will modify the definition of ``non-regulated 
power sales affiliate,'' and change the term to ``market-regulated 
power sales affiliate.'' \495\ In response to various commenters, we 
clarify that this definition is intended to apply only to non-
franchised power sales affiliates (whose power sales are not regulated 
on a cost basis under the FPA, e.g., affiliates whose power sales are 
made at market-based rates) of franchised public utilities. 
Additionally, while we recognize that we have used the term ``non-
regulated'' in the past, we believe that ``market-regulated'' is a more 
appropriate description for the entities we intend to capture in this 
definition. Accordingly, in this Final Rule, we revise the definition 
of ``market-regulated power sales affiliate'' to mean ``any power 
seller affiliate other than a franchised public utility, including a 
power marketer, exempt wholesale generator, qualifying facility or 
other power seller affiliate, whose power sales are regulated in whole 
or in part at market-based rates.'' Because the revised definition 
includes only non-franchised public utilities, it does not apply to a 
franchised public utility that makes some sales at market-based 
rates.\496\
---------------------------------------------------------------------------

    \495\ NOPR at Proposed Regulations at 18 CFR 35.36(a)(6). We 
adopt this regulation at 18 CFR 35.36(a)(7).
    \496\ However, under the standards of conduct, a wholesale 
merchant function that engages in such sales must function 
independently of the utility's transmission function. 18 CFR 
358(d)(3) and 18 CFR 358.4(a)(1).
---------------------------------------------------------------------------

    491. Xcel posits a somewhat different scenario under which it 
believes that a franchised public utility would fall within the 
definition of ``non-regulated power sales affiliate,'' namely, if such 
utility makes no wholesale sales that are regulated on a cost basis 
(making only wholesale sales at market-based rates) but serves retail 
customers under a franchised service territory. With the revision to 
the definition of ``market-regulated power sales affiliate'' that we 
adopt here, such a utility would not fall within the definition of 
``market-regulated power sales affiliate'' since it has a franchised 
service territory.
    492. In addition, we note that the Commission has historically 
placed affiliate restrictions only on the

[[Page 39963]]

relationship between a franchised public utility with captive customers 
and any affiliated market-regulated power sales affiliate. 
Nevertheless, we believe that there may be circumstances in which it 
also would be appropriate to impose similar restrictions on the 
relationship of two affiliated franchised public utilities where one of 
the affiliates has captive customers and one does not have captive 
customers. In such a case, there is a potential for the transfer of 
benefits from the captive customers of the first franchised utility to 
the benefit of the second franchised utility and ultimately to the 
joint stockholders of the two affiliated franchised public utilities. 
Commenters in the instant proceeding did not address the potential for 
affiliate abuse in this situation (i.e., between a franchised public 
utility with captive customers and an affiliated franchised public 
utility without captive customers). Accordingly, we do not generically 
impose the affiliate restrictions on such relationships but will 
evaluate whether to impose the affiliate restrictions in such 
situations on a case-by-case basis.
    493. However, to avoid confusion between references to a 
``franchised public utility with captive customers'' and a ``franchised 
public utility without captive customers'' we will revise the 
definition of ``franchised public utility'' in Sec.  35.36(a)(5) to 
remove the reference to captive customers. Accordingly, ``franchised 
public utility'' will be defined as ``a public utility with a 
franchised service obligation under State law.'' Further, we will 
revise other sections of the affiliate restrictions to specifically use 
the term ``franchised public utility with captive customers'' to 
clarify when the affiliate restrictions apply.
    494. Additionally, not all qualifying facilities are necessarily 
included in the proposed definition of ``market-regulated power sales 
affiliate.'' Only those qualifying facilities whose market-based rate 
sales fall under the Commission's jurisdiction would fall within the 
definition of ``market-regulated power sales affiliate.'' To the extent 
that some of a qualifying facility's sales are regulated under the FPA, 
even if other sales are regulated by the states, such a qualifying 
facility would be considered a market-regulated power sales affiliate 
by virtue of its FPA jurisdictional sales.
    495. Additionally, the Commission clarifies that the definition of 
``market-regulated power sales affiliate'' does not encompass all 
affiliates such as parent companies or the natural gas LDC function of 
the regulated franchised utility; rather, it only includes non-
franchised, power sales affiliates (sellers) that sell power in whole 
or in part at market based rates, and not an affiliated service company 
or others who are not authorized to make sales of power.
d. Other Definitions

    In the NOPR, the Commission proposed to adopt a restriction on 
affiliate sales of electric energy, whereby no wholesale sale of 
electric energy could be made between a public utility seller with a 
franchised service territory and a non-regulated power sales 
affiliate without first receiving Commission authorization under FPA 
section 205. This restriction would be a condition of obtaining and 
retaining market-based rate authority, and a failure to satisfy that 
condition would be a violation of the seller's market-based rate 
tariff.\497\
---------------------------------------------------------------------------

    \497\ NOPR at P 108.
---------------------------------------------------------------------------

Comments
    496. Constellation proposes that the language in the proposed 
affiliate sales restriction provision be amended to use the defined 
term ``franchised public utility'' by replacing the phrase ``public 
utility Seller with a franchised service territory'' with ``Seller that 
is a franchised public utility.'' Constellation submits that this 
change would make clear that the affiliate restrictions apply only if 
the seller is affiliated with a public utility that has captive 
customers, which it states appears to be the Commission's intent.\498\
---------------------------------------------------------------------------

    \498\ Constellation at 13-17.
---------------------------------------------------------------------------

    497. FirstEnergy proposes that a definition of franchised service 
territory be added to the regulations to clarify that the affiliate 
sales restriction would only apply to transactions involving public 
utilities with captive retail customers, and would not apply in areas 
in which there is retail choice.\499\
---------------------------------------------------------------------------

    \499\ See, e.g., FirstEnergy at 12-13.
---------------------------------------------------------------------------

Commission Determination
    498. The Commission's intent was that the affiliate sales 
restriction in proposed Sec.  35.39(a) (now Sec.  35.39(b)) would apply 
where a utility with a franchised service territory with captive 
customers proposes to make wholesale sales at market-based rates to a 
market-regulated power sales affiliate, or vice versa. Accordingly, we 
will revise Sec.  35.39(a) (now Sec.  35.39(b)) to replace ``public 
utility Seller with a franchised service territory'' with ``franchised 
public utility with captive customers.'' In light of this 
clarification, we do not believe it necessary to add a definition of 
franchised service territory to the regulations, as proposed by 
FirstEnergy.
e. Treating Merging Companies as Affiliates
Commission Proposal
    499. In the NOPR, the Commission noted that, for purposes of 
affiliate abuse, companies proposing to merge are considered affiliates 
under their market-based rate tariffs while their proposed merger is 
pending, and sought comments regarding at what point the Commission 
should consider two non-affiliates as merging partners.\500\
---------------------------------------------------------------------------

    \500\ NOPR at P 116.
---------------------------------------------------------------------------

Comments
    500. PG&E comments that affiliate sales regulations should not 
apply to contracts that pre-date the announcement of a merger. PG&E 
states that the Commission should allow merging companies sufficient 
time (e.g., 30 days) after the announcement of a merger before 
enforcing the affiliate sales regulations in order to give the merging 
companies time to acquire the necessary information and documents to 
prevent a company from being held responsible for activities of the 
merging company that it has no knowledge of or control over.\501\
---------------------------------------------------------------------------

    \501\ PG&E at 14-21.
---------------------------------------------------------------------------

Commission Determination
    501. The Commission will continue to require that, for purposes of 
affiliate abuse, companies proposing to merge will be treated as 
affiliates under their market-based rate tariffs while their proposed 
merger is pending.\502\ The Commission will adopt the proposal to use 
the date a merger is announced as the triggering event for considering 
two non-affiliates as merging partners. In this regard, we reject 
PG&E's proposal that the Commission allow an additional 30 days after 
an announced merger to begin treating, for the purpose of affiliate 
abuse, merging partners as affiliates. With the extensive discussions, 
negotiations and review that precede the formal announcement of plans 
to merge, there is sufficient time for companies to acquire the 
necessary information and documents related to the proposed merger, 
particularly given that utilities are on notice of our policy in this 
regard.
---------------------------------------------------------------------------

    \502\ Cinergy, Inc., 74 FERC ] 61,281 (1996); Consolidated 
Edison Energy, Inc., 83 FERC ] 61,236 at 62,034 (1998); Central and 
South West Services, Inc., 82 FERC ] 61,101 at 61,103 (1998); 
Delmarva Power & Light Company, 76 FERC ] 61,331 at 62,582 (1996) 
(``[T]he self-interest of two merger partners converge sufficiently, 
even before they complete the merger, to compromise the market 
discipline inherent in arm's-length bargaining that serves as the 
primary protection against reciprocal dealing.'').
---------------------------------------------------------------------------

    502. The Commission clarifies that the requirement that merging 
companies

[[Page 39964]]

be treated as affiliates while the proposed merger is pending only 
applies prospectively from the date the merger is announced and does 
not apply to any contracts entered into that pre-date the announcement 
of the merger.\503\ However, in the case of an umbrella agreement that 
pre-dates the announcement of the merger, any transactions under such 
umbrella agreement that are entered into on or after the date the 
merger is announced would be subject to the affiliate restrictions. 
Further, if an announced merger does not go forward, the affiliate 
restrictions will cease to apply as of the date the announcement is 
made that the merger will not go forward.
---------------------------------------------------------------------------

    \503\ This is consistent with the standards of conduct, which 
require transmission providers to post information concerning 
potential merger partners as affiliates within seven days after the 
potential merger is announced. 18 CFR 358.4(b)(3)(v).
---------------------------------------------------------------------------

f. Treating Energy/Asset Managers as Affiliates
Commission Proposal
    503. In the NOPR, the Commission proposed that unaffiliated 
entities that engage in energy/asset management of generation on behalf 
of a franchised public utility with captive customers be bound by the 
same affiliate restrictions as those imposed on the franchised public 
utility and the non-regulated power sales affiliates.\504\ The 
Commission recognized that there has been an increased range of 
activities engaged in by asset or energy managers.\505\ The Commission 
noted that although asset managers can provide valuable services and 
benefit consumers and the marketplace, such relationships also could 
result in transactions harmful to captive customers.\506\ Accordingly, 
the Commission proposed that an entity managing generation for the 
franchised public utility should be subject to the same affiliate 
restrictions as the franchised public utility (e.g., restrictions on 
affiliate sales and information sharing). The Commission referenced a 
settlement in which Enforcement staff alleged that an affiliated power 
marketer acting as an asset manager for three generation-owning 
affiliates violated Sec.  214 of the FPA.\507\ As a result, if a 
company is managing generation assets for the franchised public 
utility, such entity would be subject to the same information sharing 
provision as the franchised public utility with regard to information 
shared with non-regulated affiliates, such as power marketers and power 
producers.\508\ Similarly, asset managers of a non-regulated 
affiliate's generation assets would be subject to the same affiliate 
restrictions as the market-regulated power sales affiliate, including 
the information sharing provision.\509\
---------------------------------------------------------------------------

    \504\ NOPR at P 117, 130, 131.
    \505\ Id. at P 124 citing Kevin Heslin, A few thoughts on the 
industry: Ideas from session at Globalcon, Energy User News, July 1, 
2002, at 12 (Noting that prior to deregulation, ``an energy manager 
had relatively straightforward tasks: Understanding applicable 
tariffs, evaluating the possible installation of energy conservation 
measures (ECMs), and considering whether to install on-site 
generation'' but that ``now, an energy manager has to be conversant 
with a far greater number of issues'' such as complex legal issues 
and financial instruments like derivatives.)
    \506\ Id.
    \507\ Id. at P 124 (citing Cleco Corp., 104 FERC 61,125 (2003) 
(Cleco)).
    \508\ NOPR at P 130.
    \509\ Id. at P 131.
---------------------------------------------------------------------------

Comments
    504. Morgan Stanley comments that unaffiliated asset and energy 
managers should not be treated as affiliates of owners of the managed 
portfolios and that it would be overly inclusive for the Commission to 
adopt a presumption of control that would treat the energy manager as a 
franchised utility for purposes of the affiliate abuse rules.\510\ 
Financial Companies argue that the Commission should not apply the 
affiliate abuse restrictions generically to all unaffiliated energy 
managers that provide management services to a franchised utility or 
its affiliates. Rather, the Commission should evaluate applicability of 
the affiliate abuse restrictions on a case-by-case basis.\511\
---------------------------------------------------------------------------

    \510\ Morgan Stanley at 9.
    \511\ Financial Companies at 11-12.
---------------------------------------------------------------------------

    505. Allegheny claims that the Commission failed to consider the 
costs to customers, which are likely to be substantial through the loss 
of efficiencies by treating asset managers as affiliates.\512\ 
Allegheny claims that there will be higher costs because: (1) The 
affiliated asset manager will need to pass added costs on to the 
franchised utility; (2) if the affiliated asset manager cannot pass on 
costs, it may no longer provide the service and the utility may need to 
set up duplicative asset management capability, resulting in higher 
costs; or (3) the franchised utility will need to hire a third-party 
asset manager, presumably more expensive.\513\ Constellation makes a 
similar argument about the substantial costs and reduction of 
efficiencies by discouraging energy/asset management agreements.\514\
---------------------------------------------------------------------------

    \512\ Allegheny at 14-15.
    \513\ Allegheny at 15.
    \514\ Constellation at 6.
---------------------------------------------------------------------------

    506. EPSA states that it opposes the Commission's proposal to treat 
asset managers as affiliates. It submits that asset managers are not 
legally affiliates of the companies with which they have a contract. If 
the basis for the proposal to treat asset managers as affiliates is for 
transparency purposes, EPSA says that all such contracts and 
transactions with asset managers are already reportable under the 
change in status final rule.\515\
---------------------------------------------------------------------------

    \515\ EPSA at 28-32.
---------------------------------------------------------------------------

    507. Alliance Power Marketing argues that by imposing affiliate 
abuse restrictions on entities acting on behalf of a regulated public 
utility or its non-regulated affiliates, the Commission seeks to alter 
the fundamental principle of responsibility and liability of the 
regulated entity by making the third-party also directly accountable, 
thus blurring the lines of accountability. Furthermore, a critical 
element in applying affiliate abuse restrictions to entities' action on 
behalf of generation owners lies in having a stake in the outcome 
rather than just considering some direct or indirect control. Alliance 
Power Marketing asserts that evaluating control over the outcome as the 
threshold for asset managers could sweep up many entities, such as 
RTOs/ISOs, governmental and cooperative entities, that could have 
jurisdictional and practical ramifications.\516\
---------------------------------------------------------------------------

    \516\ Alliance Power Marketing at 17-37.
---------------------------------------------------------------------------

    508. A number of other commenters oppose the Commission's proposal 
to treat unaffiliated energy/asset managers as part of the franchised 
public utility. They argue that the current code of conduct already 
provides the protections sought by such a proposal and the Commission 
fails to explain the need for such expanded regulation.\517\ 
Furthermore, they submit that such proposal does not consider the 
additional costs to consumers through lost efficiencies.\518\
---------------------------------------------------------------------------

    \517\ Allegheny Energy Companies at 10-16; PG&E at 14-21.
    \518\ Allegheny Energy Companies at 10-16.
---------------------------------------------------------------------------

    509. PG&E argues that the Commission proposal to consider 
``entities acting on behalf of and for the benefit of [the utility/
affiliate]'' as part of the utility/affiliate itself is unnecessary and 
overly broad.\519\
---------------------------------------------------------------------------

    \519\ PG&E at 14-21.
---------------------------------------------------------------------------

    510. Indianapolis P&L does not oppose the Commission's proposal to 
treat asset managers as affiliates for the limited purposes of the code 
of conduct, standards of conduct or inter-affiliate transaction issues, 
but it states that the Commission should not treat unaffiliated asset 
managers as affiliates when determining how much generating

[[Page 39965]]

capacity should be attributed to a generation asset owner.\520\
---------------------------------------------------------------------------

    \520\ Indianapolis P&L at 7-10.
---------------------------------------------------------------------------

    511. Financial Companies and Morgan Stanley both state in their 
reply comments that the Commission should not impose affiliate 
restrictions on unaffiliated energy managers, as the Commission 
provides no basis for such requirement \521\ and no evidence that 
energy managers can engage in cross-subsidization of unregulated 
affiliates.\522\
---------------------------------------------------------------------------

    \521\ Morgan Stanley reply comments at 14.
    \522\ Financial Companies reply comments at 6.
---------------------------------------------------------------------------

Commission Determination
    512. From the various comments submitted it is apparent that our 
proposal has created confusion as to our intent with regard to the 
treatment of energy/asset managers under the proposed affiliate 
restrictions. Accordingly, we clarify and simplify our approach, as 
discussed below.
    513. The Commission is concerned that there exists the potential 
for a franchised public utility with captive customers to interact with 
a market-regulated power sales affiliate in ways that transfer benefits 
to the affiliate and its stockholders to the detriment of the captive 
customers. Therefore, the Commission has adopted certain affiliate 
restrictions to protect the captive customers and, in this Final Rule, 
is codifying those restrictions in our regulations. To that end, we 
make clear that such utilities may not use anyone, including energy/
asset managers, to circumvent the affiliate restrictions (e.g., 
independent functioning and information sharing prohibitions). 
Accordingly, we adopt and codify in our regulations at Sec.  
35.39(c)(1) and 35.39(g) an explicit prohibition on using third-party 
entities to circumvent otherwise applicable affiliate restrictions.
    514. We note that energy/asset managers provide a variety of 
services for franchised public utilities and market-regulated power 
sales affiliates, including, but not limited to, operating generation 
plants (sometimes under tolling agreements), acting as billing agents, 
bundling transmission and power for customers, and scheduling 
transactions. However, regardless of the relationships and duties of an 
energy/asset manager to a franchised public utility or its non-
regulated affiliate, the energy/asset manager may not act as a conduit 
to circumvent the affiliate restrictions.\523\
---------------------------------------------------------------------------

    \523\ The Commission is adopting 18 CFR 35.39(g) which prohibits 
a franchised public utility with captive customers and a market-
regulated power sales affiliate from using anyone as a conduit to 
circumvent any of the affiliate restrictions, including the 
affiliate sales restriction and the information sharing provision.
---------------------------------------------------------------------------

    515. This approach is consistent with past Commission orders that 
have identified the potential that affiliated exempt wholesale 
generators or qualifying facilities could serve as a conduit for 
providing below-cost services to an affiliated power marketer at the 
expense of captive customers of the public utility operating companies 
and imposed restrictions to prevent this.\524\
---------------------------------------------------------------------------

    \524\ Southern Company Services, Inc., 72 FERC ] 61,324 at 
62,408 (1995).
---------------------------------------------------------------------------

    516. Although several commenters assert that the costs of asset 
management will increase as a result of requiring asset managers to 
observe the affiliate restrictions, they did not provide any examples 
of why the costs would increase. The Commission notes that under this 
Final Rule, all asset managers are not required to observe the 
affiliate restrictions, only those asset managers which control or 
market generation of the franchised public utility with captive 
customers or a market-regulated power sales affiliate of a franchised 
public utility with captive customers. In those instances, the need to 
protect captive customers outweighs any generalized assertions of 
increased cost.
    517. We note that to the extent that a franchised public utility 
with captive customers and one or more of its non-regulated marketing 
affiliates obtains the services of the same energy/asset manager, such 
an arrangement would create opportunities to harm captive customers 
depending on how the energy/asset manager is structured. For example, 
without internal separation between the energy/asset managers' 
regulated and non-regulated businesses, there would exist opportunities 
to harm captive customers.
g. Cooperatives
Comments
    518. Suez/Chevron asks the Commission to clarify that 
jurisdictional utilities organized as cooperatives are not exempt from 
the affiliate abuse rules and that all jurisdictional public utilities 
with captive customers, including utilities organized as cooperatives, 
must comply with the affiliate abuse rules.\525\
---------------------------------------------------------------------------

    \525\ Suez/Chevron at 10-12.
---------------------------------------------------------------------------

    519. El Paso E&P argues that it would appear that the proposed 
affiliate restrictions would apply to power sales at market-based rates 
made by G&T cooperatives to their State-regulated member distribution 
cooperatives. It states that based on the definition of a ``franchised 
public utility'' as ``a public utility with a franchised service 
obligation under State law and that has captive customers,'' 
distribution cooperatives that are granted franchised service 
territories by State regulatory agencies would be included in this 
definition. El Paso E&P asserts that a G&T cooperative with authority 
to sell power at market-based rates would be defined as a non-regulated 
power seller and, accordingly, sales made by a G&T cooperative at 
market-based rates to its affiliated member distribution cooperatives 
would, under the proposed regulations, be required to comply with the 
requirements of the rule. \526\
---------------------------------------------------------------------------

    \526\ El Paso E&P at 4-9.
---------------------------------------------------------------------------

    520. However, El Paso E&P argues that the Commission has previously 
stated that affiliate abuse is not a concern for cooperatives owned by 
other cooperatives because the cooperatives' ratepayers are its 
members. El Paso E&P alleges that the Commission has never sufficiently 
explained the basis for its prior statements. According to El Paso E&P, 
the Commission's prior statements are based on the findings in Hinson 
Power \527\ that lack of concern with the potential for affiliate abuse 
is premised on the absence of captive customers that would be subject 
to the exercise of market power. El Paso submits that the fact that 
ratepayers of the distribution cooperative are also members of such 
cooperatives should not alleviate the Commission's concern about 
potential affiliate abuse issues. El Paso E&P claims that industrial 
customers of distribution cooperatives with franchised service 
territories are captive to service from the generation and transmission 
and distribution cooperatives that serve them and are in need of 
protection from the Commission to ensure that they are charged just and 
reasonable rates.\528\
---------------------------------------------------------------------------

    \527\ Hinson Power Company, 72 FERC ] 61,190 (1995).
    \528\ El Paso E&P at 4-9.
---------------------------------------------------------------------------

    521. NRECA submits that El Paso misreads the proposed regulations 
by classifying distribution cooperatives as a ``public utility Seller'' 
under the proposed regulations and NRECA comments that it is not aware 
of any distribution cooperatives that would be classified as ``public 
utility Sellers'' thus triggering the restriction on affiliate sales 
without first receiving Commission approval. NRECA states that nearly 
all distribution cooperatives are not regulated as public utilities 
under the FPA because they either have Rural Electrification Act (REA) 
financing or sell less than 4 million

[[Page 39966]]

MWh per year and thus do not qualify as a ``public utility'' under 
section 201(f) of the FPA. Furthermore, NRECA comments that very few 
distribution cooperatives sell any electricity for resale. Thus, they 
would not need to obtain market-based rate authority under section 205 
even if they were not relieved of that obligation by section 
201(f).\529\ NRECA also comments that the Commission has explained the 
reasoning behind not requiring cooperatives to comply with the 
affiliate abuse requirements by stating that ``in the case of a 
cooperative, the cooperative's members are both the ratepayers and the 
shareholders, and thus there is no potential danger of shifting 
benefits from one to another.'' \530\
---------------------------------------------------------------------------

    \529\ NRECA supplemental reply comments at 5-6.
    \530\ NRECA supplemental reply comments at 9.
---------------------------------------------------------------------------

    522. El Paso E&P responds that NRECA incorrectly interprets the 
scope of the proposed affiliate restriction and that NRECA ignores the 
definition of ``franchised public utility'' as ``a public utility with 
a franchised service obligation under State law and that has captive 
customers.'' El Paso E&P submits that this definition clearly includes 
distribution cooperatives. El Paso E&P further replies that the fact 
that distribution cooperatives are not ``public utilities'' regulated 
by the Commission is irrelevant because the Commission is not proposing 
to regulate sales by such distribution cooperatives. Rather, it is 
proposing to regulate wholesale sales by the generation and 
transmission cooperatives to their member distribution cooperatives. 
Therefore, El Paso E&P argues, the Commission should clarify the 
regulations to ensure that generation and transmission cooperatives are 
covered under the affiliate restrictions.\531\
---------------------------------------------------------------------------

    \531\ El Paso E&P answer to reply comments at 2-3.
---------------------------------------------------------------------------

    523. El Paso E&P also responds that NRECA's attempt to divorce a 
generation and transmission cooperative's market-based rate sales to 
its distribution cooperative members from the distribution 
cooperative's sales to captive customers ignores the cooperative 
structure. It states that a generation and transmission cooperative is 
comprised of its member distribution cooperatives and both the 
generation and transmission and distribution cooperatives act in 
concert in connection with sales to industrial customers.\532\ El Paso 
E&P also submits that NRECA's argument suggests that the Commission has 
no jurisdiction over sales to State-regulated franchised public 
utilities that are not cooperatives.\533\ According to El Paso E&P, the 
captive customers of distribution cooperatives are in need of the same 
protection from the Commission notwithstanding that the distribution 
cooperatives are regulated by the states.\534\
---------------------------------------------------------------------------

    \532\ Id. at 3.
    \533\ Id.
    \534\ Id. at 4.
---------------------------------------------------------------------------

    524. El Paso E&P also states that wholesale electric sales approved 
by the Commission must be passed through at the retail level. Thus, El 
Paso E&P states that it is not sufficient to suggest that the 
Commission need not be concerned because the distribution cooperatives' 
rates are subject to State regulation.\535\ Finally, El Paso E&P 
responds that NRECA cannot seek the protection of this Commission when 
its members are purchasers of power, and then claim its members should 
be exempt from scrutiny when they are sellers to captive customers such 
as El Paso E&P. It asserts that captive customers of generation and 
transmission and their member distribution cooperatives are in need of 
protection.\536\
---------------------------------------------------------------------------

    \535\ Id.
    \536\ Id. at 5.
---------------------------------------------------------------------------

Commission Determination
    525. FPA section 201(f) specifically exempts from the Commission's 
regulation under Part II of the FPA, except as specifically provided, 
electric cooperatives that receive REA financing or sell less than 4 
million megawatt hours of electricity per year.\537\ Thus, such 
electric cooperatives are not considered public utilities under the FPA 
and our market-based rate regulations do not apply to those electric 
cooperatives. Further, with respect to distribution-only cooperatives, 
they either do not meet the ``public utility'' definition because they 
do not own or operate facilities used for wholesale sales or 
transmission in interstate commerce or, if they do own or operate such 
facilities, they are exempted from Part II regulation by virtue of FPA 
section 201(f). In this regard, we note that NRECA states that it is 
unaware of any distribution cooperatives in the United States that 
would be ``public utility Sellers'' under the proposed 
regulations.\538\ Such a cooperative would not be subject to the 
affiliate restrictions in the proposed regulations at Sec.  35.39.
---------------------------------------------------------------------------

    \537\ 16 U.S.C. 824(e)-(f) (2006).
    \538\ NRECA reply comments at 5.
---------------------------------------------------------------------------

    526. For electric cooperatives that are public utility sellers and 
not exempted from public utility regulation by FPA section 201(f), as 
discussed above, the Commission will continue to treat such electric 
cooperatives as not subject to the Commission's affiliate abuse 
restrictions, based on a finding that transactions of an electric 
cooperative with its members do not present dangers of affiliate abuse 
through self-dealing. Even if an electric cooperative is not 
statutorily exempted from our regulation under Part II of the FPA, we 
conclude that a waiver of Sec.  35.39 is appropriate. As the Commission 
has previously explained, ``affiliate abuse takes place when the 
affiliated public utility and the affiliated power marketer transact in 
ways that result in a transfer of benefits from the affiliated public 
utility (and its ratepayers) to the affiliated power marketer (and its 
shareholders).'' \539\ However, as the Commission has previously stated 
in many market-based rate orders over the years,\540\ where a 
cooperative is involved, the cooperative's members are both the 
ratepayers and the shareholders. Any profits earned by the cooperative 
will enure to the benefit of the cooperative's ratepayers. Therefore, 
we have found that there is no potential danger of shifting benefits 
from the ratepayers to the shareholders.\541\
---------------------------------------------------------------------------

    \539\ Heartland Energy Services, Inc., 68 FERC ] 61,223 at 
62,062 (1994).
    \540\ Hinson Power Company, 72 FERC ] 61,190 (1995). See also, 
e.g., People's Electric Corp., 84 FERC ] 61,215 at 62,042 (1998) 
(application raised no issues of affiliate abuse because the seller 
was operated by a cooperative whose ratepayers were also its 
owners); Old Dominion Electric Cooperative, 81 FERC ] 61,044 at 
61,236 (1997).
    \541\ Old Dominion Electric Cooperative, 81 FERC ] 61,044 at 
61,236 (1997).
---------------------------------------------------------------------------

    527. Finally, we agree with NRECA's argument that the issue that El 
Paso E&P discusses in its comments is not a concern that can be 
addressed through affiliate restrictions in market-based rates, but is 
rather more of a concern of discrimination in the allocation of 
benefits and burdens among retail ratepayers. The Commission does not 
possess jurisdiction to review a distribution cooperative's retail 
rates; that issue falls under State law. Moreover, El Paso E&P's 
argument that wholesale electric sales approved by the Commission must 
be passed through at the retail level is misplaced. As the courts have 
previously held, State commissions are not precluded from reviewing the 
prudence of a company's purchasing decisions, and may disallow pass-
through of wholesale purchase costs unless the purchaser had no legal 
right to refuse to make a particular purchase.\542\
---------------------------------------------------------------------------

    \542\ Arkansas Power & Light Co. v. Missouri Public Service 
Commission, 829 F.2d 1444 at 1451-52 (8th Cir. 1987). See also Pike 
County Light & Power v. Pennsylvania Public Utility Commission, 465 
A.2d 735 at 737-78 (1983); Nantahala Power & Light Co. v. Thornburg, 
476 U.S. 953 at 965-67 (1986); Mississippi Power & Light Co. v. 
Mississippi ex rel. Moore, 487 U.S. 354 at 369 (1988).

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

[[Page 39967]]

    528. Therefore, for the reasons stated above, the Commission will 
continue to follow its current precedent and find that electric 
cooperatives that are public utility sellers and not exempted from 
public utility regulation by FPA Sec.  201(f) are not subject to the 
Commission's affiliate abuse requirements.
2. Power Sales Restrictions
Commission Proposal
    529. In the NOPR the Commission proposed to continue the policy of 
reviewing power sales transactions between regulated and ``non-
regulated'' affiliates under section 205 of the FPA. This policy means, 
among other things, that a general grant of market-based rate authority 
does not apply to affiliate sales between a regulated and a non-
regulated affiliate, absent express authorization by the Commission.
    530. The Commission proposed to amend the regulations to include a 
provision expressly prohibiting power sales between a franchised public 
utility \543\ and any of its non-regulated power sales affiliates 
without first receiving authorization for the transaction under section 
205 of the FPA.
---------------------------------------------------------------------------

    \543\ As proposed in the NOPR, the term ``franchised public 
utility'' was defined as ``a public utility with a franchised 
service obligation under state law and that has captive customers.'' 
As set forth below, to avoid confusion between references to a 
franchised public utility with captive customers and one without, we 
revise the proposed regulations to delete the reference to customers 
in the definition and to specifically use the term ``franchised 
public utility with captive customers'' to clarify when the 
affiliate restrictions apply.
---------------------------------------------------------------------------

    531. Additionally, although it did not propose to codify the 
requirement in the regulatory text, the Commission proposed that 
sellers seeking authorization to engage in affiliate transactions will 
continue to be obligated to provide evidence as to whether there are 
captive customers that would trigger the application of the affiliate 
restrictions. The Commission stated that if the Commission finds, based 
on the evidence provided by the seller, that the seller has no captive 
customers, the affiliate restrictions in the regulations would not 
apply.
    532. The Commission proposed to continue its prior approach for 
determining what types of affiliate sales transactions are permissible 
and the criteria that should be used to make those decisions, including 
evaluation of the Allegheny and Edgar criteria.\544\ Although it did 
not propose to codify a safe harbor provision in the regulations, the 
Commission noted that when affiliates participate in a competitive 
solicitation process, application of the Allegheny criteria would 
constitute a safe harbor that affiliate abuse conditions are satisfied 
in a transaction between a franchised public utility and its 
affiliates. The Commission emphasized, however, that using a 
competitive solicitation is not the only way to address concerns that 
an affiliate transaction does not pose undue preference concerns.\545\
---------------------------------------------------------------------------

    \544\ Boston Edison Company Re: Edgar Electric Energy Co., 55 
FERC ] 61,382 (1991) (Edgar), describing three types of evidence 
that can be used to show that an affiliate power sales transaction 
is above suspicion ensuring that the market is not distorted and 
captive ratepayers are protected: (1) Evidence of direct head-to-
head competition between the affiliate and competing unaffiliated 
suppliers in a formal solicitation or informal negotiation process; 
(2) evidence of the prices non-affiliated buyers were willing to pay 
for similar services from the affiliate; or (3) benchmark evidence 
that shows the prices, terms, and conditions of sales made by non-
affiliated sellers. Allegheny Energy Supply Company, LLC, 108 FERC ] 
61,082 (2004) (Allegheny), stating four guidelines that help the 
Commission determine if a competitive solicitation process satisfies 
the Edgar criteria: (1) It is transparent; (2) products are well 
defined; (3) bids are evaluated comparably with no advantage to 
affiliates; and (4) it is designed and evaluated by an independent 
entity.
    \545\ Although our focus and discussion in this rule is 
affiliate abuse with respect to affiliates that sell at market-based 
rates, affiliate concerns also arise with respect to affiliate sales 
at cost-based rates. See, e.g., Duke Energy Corp. and Cinergy Corp., 
113 FERC ] 61,297 at P 113-116 (2005), reh'g denied, 118 FERC ] 
61,077 (2007).
---------------------------------------------------------------------------

    533. The Commission said it continues to believe that tying the 
price of an affiliate transaction to an established, relevant market 
price or index such as in an RTO or ISO is acceptable benchmark 
evidence and mitigates affiliate abuse concerns so long as that 
benchmark price or index reflects the market price where the affiliate 
transaction occurs. The Commission proposed to allow affiliate 
transactions based on a non-RTO price index only if the index fulfills 
the requirements of the November 19 Price Index Order \546\ for 
eligibility for use in jurisdictional tariffs. The Commission sought 
comment on whether evidence other than competitive solicitations, RTO 
price or non-RTO price indices, or benchmarks described in the NOPR 
should be accepted in an application for authority to engage in market-
based affiliate power sales. In addition, the Commission proposed to 
consider two merging partners as affiliates as of the date a merger is 
announced, and sought comments on this proposal (or whether to use the 
date the Sec.  203 application is filed with the Commission, or another 
time). The Commission also proposed that unaffiliated entities that 
engage in energy/asset management of generation on behalf of a 
franchised public utility or non-regulated utility be bound to comply 
with the same affiliate restrictions as those imposed on the franchised 
public utility and the non-regulated power sales affiliate.
---------------------------------------------------------------------------

    \546\ Order Regarding Future Monitoring of Voluntary Price 
Formation, Use of Price Indices In Jurisdictional Tariffs, and 
Closing Certain Tariff Dockets, 109 FERC ] 61,184 (2004) (November 
19 Price Index Order).
---------------------------------------------------------------------------

    534. The Commission said it continues to believe that tying the 
price of an affiliate transaction to an established, relevant market 
price or index such as in an RTO or ISO is acceptable benchmark 
evidence and mitigates affiliate abuse concerns so long as that 
benchmark price or index reflects the market price where the affiliate 
transaction occurs. The Commission proposed to allow affiliate 
transactions based on a non-RTO price index only if the index fulfills 
the requirements of the November 19 Price Index Order \547\ for 
eligibility for use in jurisdictional tariffs. The Commission sought 
comment on whether evidence other than competitive solicitations, RTO 
price or non-RTO price indices, or benchmarks described in the NOPR 
should be accepted in an application for authority to engage in market-
based affiliate power sales. In addition, the Commission proposed to 
consider two merging partners as affiliates as of the date a merger is 
announced, and sought comments on this proposal (or whether to use the 
date the Sec.  203 application is filed with the Commission, or another 
time). The Commission also proposed that unaffiliated entities that 
engage in energy/asset management of generation on behalf of a 
franchised public utility or non-regulated utility be bound to comply 
with the same affiliate restrictions as those imposed on the franchised 
public utility and the non-regulated power sales affiliate.
---------------------------------------------------------------------------

    \547\ Id.
---------------------------------------------------------------------------

Comments
    535. Industrial Customers urge the Commission to recognize that 
when an affiliate transaction has been subject to a State-approved 
process, separate section 205 approvals for such transactions should 
not be required. If, however, the Commission does maintain the section 
205 approval, ``the imprimatur of State commission approval should 
create a rebuttable presumption that the transaction is just and 
reasonable.'' \548\ NASUCA comments that the Commission should not 
assume the reasonableness of all affiliate sales under contracts with

[[Page 39968]]

prices linked to spot markets or other auction results.\549\
---------------------------------------------------------------------------

    \548\ Industrial Customers at 16-18.
    \549\ NASUCA at 20-29.
---------------------------------------------------------------------------

    536. Other commenters urge the Commission to clarify that, while 
requests for proposals consistent with the Allegheny and Edgar 
standards and affiliate sales based on market index prices constitute a 
safe harbor for affiliate abuse, those should not be the only safe 
harbors.\550\ The Commission should state it is willing to consider 
other information and evidence, including affiliate sales reviewed and 
authorized by a State regulatory agency, as safe harbors as well.\551\
---------------------------------------------------------------------------

    \550\ Indianapolis P&L at 7-10.
    \551\ FirstEnergy at 12-27.
---------------------------------------------------------------------------

    537. New Jersey Board disagrees with comments that the Commission 
should consider State approval of affiliate sales as a safe harbor and 
responds that the Commission should assure that affiliate abuse does 
not take place and not ignore affiliate sales based on actions and 
oversight by State commissions.\552\
---------------------------------------------------------------------------

    \552\ New Jersey Board reply comments at 6.
---------------------------------------------------------------------------

    538. State AGs and Advocates oppose the Commission's proposal to 
find affiliate sales of wholesale power just and reasonable if such 
sales are made through an auction that reflects certain guidelines such 
as those set forth in Edgar and Allegheny. Instead, State AGs and 
Consumer Advocates state that the Commission should develop behavioral 
market power tests that apply to all market structures and that each 
auction should be assessed separately and evaluated on the merits of 
the proposal.\553\
---------------------------------------------------------------------------

    \553\ State AGs and Advocates reply comments at 12-13.
---------------------------------------------------------------------------

    539. Industrial Customers oppose the Commission's proposal to rely 
on an RTO/ISO benchmark price or index to mitigate affiliate abuse 
concerns and argues that tying an affiliate transaction to a price 
index should not allow utilities to escape scrutiny.\554\
---------------------------------------------------------------------------

    \554\ Industrial Customers at 16-18.
---------------------------------------------------------------------------

Commission Determination
    540. The Commission adopts the proposal to continue its approach 
for determining what types of affiliate transactions are permissible 
and the criteria used to make those decisions. Although we are not 
codifying a safe harbor in our regulations, when affiliates participate 
in a competitive solicitation process for power sales, we will consider 
proper application of the Allegheny guidelines to constitute a safe 
harbor that the affiliate abuse concerns are satisfied in a transaction 
between a franchised public utility with captive customers and its non-
regulated power sales affiliate. The Commission will consider proposed 
competitive solicitations on a case-by-case basis. We again emphasize 
that using a competitive solicitation by applying the Allegheny and 
Edgar guidelines is not the only way an affiliate transaction can 
address our concerns that the transaction does not pose undue 
preference concerns. We will consider other approaches on a case-by-
case basis. Also, to the extent a seller is not bound by the affiliate 
restrictions because neither the seller nor the buyer has captive 
customers, we find that the Edgar principles do not apply and the 
seller does not need to make a filing with regard to a proposed 
competitive solicitation.\555\
---------------------------------------------------------------------------

    \555\ Southern California Edison Co., 109 FERC ] 61,086 at P 35 
(2004) (noting that Commission's concern in cases involving sales to 
affiliates has been the potential for cross-subsidization at the 
expense of the public utility's captive customers).
---------------------------------------------------------------------------

    541. A number of commenters urge the Commission to find that a 
State-approved solicitation process creates a rebuttable presumption 
that an affiliate transaction satisfies the Commission's affiliate 
abuse concerns. The Commission will consider a State-approved process 
as evidence in its consideration as to whether our affiliate abuse 
concerns have been adequately addressed, but the Commission will not 
treat a State-approved process as creating a rebuttable presumption 
that our affiliate abuse concerns have been addressed. In this regard, 
the Commission has a responsibility under section 205 of the FPA to 
ensure that all jurisdictional rates charged are just and reasonable 
and not unduly discriminatory or preferential. While a State-approved 
solicitation process may provide evidence that the wholesale rates 
proposed as a result of that process are just and reasonable and do not 
involve any undue discrimination or preference, we do not believe it is 
appropriate to create a rebuttable presumption.
    542. Further, the Commission will continue to allow an established, 
relevant market price or index such as in an RTO or ISO to be used as a 
benchmark for the reasonableness of the price of an affiliate 
transaction. In this regard, we disagree with commenters that relying 
on such prices or indices allows utilities to escape Commission 
scrutiny. Such an index is acceptable benchmark evidence and mitigates 
affiliate abuse concerns so long as that benchmark price or index 
reflects the market price where the affiliate transaction occurs (i.e., 
is a relevant index).\556\ The Commission previously stated that the 
added protections in structured markets with central commitment and 
dispatch and market monitoring and mitigation (such as RTOs/ISOs) 
generally result in a market where prices are transparent.\557\
---------------------------------------------------------------------------

    \556\ Brownsville, 111 FERC ] 61,398 at P 10 (2005). See also 
Portland General Elec. Co., 96 FERC ] 61,093 at 61,378 (2001); 
FirstEnergy Trading, 88 FERC ] 61,067 at 61,156 (1999).
    \557\ April 14 Order, 107 FERC ] 61,018 at P 189.
---------------------------------------------------------------------------

    543. In addition, while the Commission has found in the past that 
certain non-RTO price indices are acceptable indicators of market 
prices, we continue to recognize that price indices at thinly traded 
points can be subject to manipulation and are otherwise not good 
measures of market prices as discussed in the Price Index Policy 
Statement \558\ and November 19 Price Index Order. Therefore, the 
Commission will allow affiliate transactions based on a non-RTO price 
index only if the index fulfills the requirements of the November 19 
Price Index Order for eligibility for use in jurisdictional tariffs and 
reflects the market price where the affiliate transaction occurs (i.e., 
is a relevant index).\559\
---------------------------------------------------------------------------

    \558\ Policy Statement on Natural Gas and Electric Price 
Indices, 104 FERC ] 61,121 (2003) (Price Index Policy Statement).
    \559\ November 19 Price Index Order, 109 FERC ] 61,184 at P 40-
69.
---------------------------------------------------------------------------

3. Market-Based Rate Affiliate Restrictions (Formerly Code of Conduct) 
for Affiliate Transactions Involving Power Sales and Brokering, Non-
Power Goods and Services and Information Sharing
Commission Proposal
    544. The Commission stated in the NOPR that it continues to believe 
that a code of conduct is necessary to protect captive customers from 
the potential for affiliate abuse. In light of the repeal of the Public 
Utility Holding Company Act of 1935 \560\ and the fact that holding 
company systems may have franchised public utility members with captive 
customers as well as numerous non-regulated power sales affiliates that 
engage in non-power goods and services transactions with each other, 
the Commission stated that it is important to have in place 
restrictions that preclude transferring captive customer benefits to 
stockholders through a company's non-regulated power sales business. 
Therefore, the Commission stated its belief that it is appropriate to 
condition all market-based rate authorizations, including 
authorizations

[[Page 39969]]

for sellers within holding companies, on the seller abiding by a code 
of conduct for sales of non-power goods and services and services 
between power sales affiliates. In addition, the Commission stated that 
greater uniformity and consistency in the codes of conduct is 
appropriate and, therefore, proposed to adopt a uniform code of conduct 
to govern the relationship between franchised public utilities with 
captive customers and their ``non-regulated'' affiliates, i.e., 
affiliates whose power sales are not regulated on a cost basis under 
the FPA. The Commission proposed to codify such affiliate restrictions 
in the regulations and to require that, as a condition of receiving 
market-based rate authority, franchised public utility sellers with 
captive customers comply with these restrictions. The Commission 
proposed that the failure to satisfy the conditions set forth in the 
affiliate restrictions will constitute a tariff violation.
---------------------------------------------------------------------------

    \560\ 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. 
Regulations Preambles 2001-2005 ] 31,197 (2005).
---------------------------------------------------------------------------

    545. The Commission sought comments on this proposal and on whether 
the specific affiliate restrictions proposed in the NOPR are sufficient 
to protect captive customers. In particular, the Commission sought 
comments on what changes, if any, should be adopted.
a. Uniform Code of Conduct/Affiliate Restrictions--Generally
Comments
    546. Some commenters support codifying the code of conduct 
affiliate restrictions in the regulations and comment that it will lead 
to consistent codes of conduct across all sellers, thus creating 
greater transparency, and will aid the Commission's enforcement 
efforts.\561\ ELCON argues that the ability of large utility holding 
companies with one foot in ``competition'' and one foot in 
``regulation'' creates a myriad of potential problems.\562\ Several 
State agencies and consumer commenters generally support the proposal 
to codify uniform code of conduct restrictions in the Commission's 
regulations.\563\ NASUCA comments that the separation of function 
requirements should apply to any affiliate with retail customers, not 
just to affiliates who are franchised public utilities.\564\
---------------------------------------------------------------------------

    \561\ ELCON and EPSA support codifying a uniform code of 
conduct. ELCON at 2 and EPSA at 28.
    \562\ ELCON at 3.
    \563\ Id. at 6-10, New Jersey Board at 2, and NRECA at 11.
    \564\ NASUCA at 20-29.
---------------------------------------------------------------------------

    547. FP&L, however, does not believe it is unduly preferential to 
have different codes of conduct.\565\ Indianapolis P&L argues that a 
single tariff/code of conduct does not make sense for diversified 
energy companies with geographically widespread operations.\566\
---------------------------------------------------------------------------

    \565\ FP&L at 3.
    \566\ Indianapolis P&L at 12.
---------------------------------------------------------------------------

    548. FP&L states that the Commission should include in the 
regulatory text the statement that the affiliate restrictions are 
waived where a seller demonstrates that there are no captive 
customers.\567\ EEI states that utilities already found not to have 
captive customers because of retail choice should be grandfathered and 
should not have to request waiver of the code of conduct again.\568\
---------------------------------------------------------------------------

    \567\ FP&L at 5-6.
    \568\ EEI at 43; EEI reply comments at 35.
---------------------------------------------------------------------------

Commission Determination
    549. The Commission will adopt the proposed affiliate restrictions 
with certain modifications and clarifications. These restrictions 
govern the separation of functions, the sharing of market information, 
sales of non-power goods or services, and power brokering. The 
Commission will require that, as a condition of receiving and retaining 
market-based rate authority, sellers comply with these affiliate 
restrictions unless otherwise permitted by Commission rule or order. As 
discussed herein, these affiliate restrictions govern the relationship 
between franchised public utilities with captive customers and their 
``market-regulated'' affiliates, i.e., affiliates whose power sales are 
regulated in whole or in part on a market-based rate basis.
    550. Failure to satisfy the conditions set forth in the affiliate 
restrictions will constitute a violation of the market-based rate 
tariff. As discussed in greater detail below, the Commission agrees 
with many of the commenters that the requirements and exceptions in the 
affiliate restrictions should follow those requirements and exceptions 
codified in the standards of conduct, where applicable.\569\ The 
Commission believes that modeling these restrictions and the exceptions 
to those restrictions on the standards of conduct will lead to greater 
consistency and transparency and a greater understanding of permissible 
activities.
---------------------------------------------------------------------------

    \569\ On November 17, 2006, the D.C. Circuit vacated the Order 
No. 2004 standards of conduct orders as they related to natural gas 
pipelines and remanded the orders to the Commission. National Fuel 
Gas Supply Corporation v. FERC, 468 F.3d 831 (D.C. Cir. 2006). The 
court found that the rulemaking record did not support the 
Commission's attempt to extend the standards of conduct beyond 
pipelines' relationships with their marketing affiliates to also 
govern pipelines' relationships with numerous non-marketing 
affiliates, such as producers, gatherers, and local distribution 
companies (which Order No. 2004 defined as ``energy affiliates''). 
In response to this decision, the Commission issued an interim rule 
on January 9, 2007 reinstating those provisions of Order No. 2004 
that were not specifically appealed to the D.C. Circuit. Standards 
of Conduct for Transmission Providers, Order No. 690, 72 FR 2427 
(Jan. 19, 2007); FERC Stats. & Regs. ] 31,237 (Jan. 9, 2007); order 
on reh'g, Standards of Conduct for Transmission Providers, Order No. 
690-A, 72 FR 14235 (Mar. 27, 2007); FERC Stats. & Regs. ] 31,243 
(2007). On January 18, 2007, the Commission issued a Notice of 
Proposed Rulemaking proposing to make the changes in the Interim 
Rule permanent and seeking comment on whether the restrictions 
covering relationships between electric transmission providers and 
non-marketing affiliates that are engaged in energy transactions 
should be retained. Standards of Conduct for Transmission Providers, 
Notice of Proposed Rulemaking, 72 FR 3958 (Jan. 29, 2007), FERC 
Stats. & Regs. ] 32,611 (2007).
---------------------------------------------------------------------------

    551. The Commission clarifies that any sellers that have previously 
demonstrated and been found not to have captive customers, and 
therefore have received a waiver of the market-based rate code of 
conduct requirement in whole or in part, will not be required to 
request another waiver of the associated affiliate restrictions. 
However, those sellers are still under the obligation to report to the 
Commission any changes in status that may affect the basis on which the 
Commission relied in granting their waiver, consistent with the 
requirements of Order No. 652.\570\ Additionally, those sellers also 
will be required to meet the requirements necessary to maintain their 
market-based rate authority when they file their regularly scheduled 
updated market power analyses. As a result, they will be required to 
demonstrate that they continue to lack captive customers in order to 
support a continued waiver of the affiliate restrictions in the 
regulations. Sellers will also need to explain why any wholesale 
customers are not captive, as explained above.
---------------------------------------------------------------------------

    \570\ Reporting Requirement For Changes in Status For Public 
Utilities with Market-Based Rate Authority, Order No. 652, 70 FR 
8253 (Feb. 18, 2005), FERC Stats. & Regs., Regulations Preambles 
January 2001-December 2005 ] 31,175, order on reh'g, Order No. 652-
A, 111 FERC ] 61,413 (2005).
---------------------------------------------------------------------------

    552. In response to FP&L and EEI, because we clarify in this Final 
Rule that, where a seller demonstrates and the Commission agrees that 
it has no captive customers, the affiliate restrictions will not apply, 
the Commission does not believe it is necessary to include in the 
regulatory text a provision stating that the affiliate restrictions are 
waived where a seller demonstrates and the Commission agrees that it 
has no captive customers.

[[Page 39970]]

b. Exceptions to the Independent Functioning Requirement
Commission Proposal Regarding Separation of Employees and Shared 
Employees
    553. In the NOPR, the Commission proposed regulatory language in 
Sec.  35.39(b)(2) (now Sec.  35.39(c)(2)) codifying the independent 
functioning requirement. Specifically, the Commission stated, to the 
maximum extent practical, the employees of a non-regulated power sales 
affiliate will operate separately from the employees of any affiliated 
franchised public utility.
    554. The Commission did not propose to include any exceptions to 
the independent functioning requirements. However, the Commission 
invited commenters to propose additions to, substitutions for or 
elimination of the proposed affiliate restrictions.\571\
---------------------------------------------------------------------------

    \571\ NOPR at P 132.
---------------------------------------------------------------------------

Comments
    555. A number of commenters request that the Commission modify the 
affiliate restrictions to adopt some of the requirements and exceptions 
consistent with those codified in Order No. 2004, such as allowing the 
sharing of senior officers and members of the board of directors, field 
and maintenance employees and support employees. According to EPSA, the 
affiliate restrictions should provide specifically for permissible 
sharing of officers (not just sharing of support personnel) between a 
franchised public utility and a non-regulated power sales affiliate. 
EPSA notes that Order No. 2004 allows for shared officers as long as 
they do not direct, organize or execute day-to-day business 
transactions.\572\
---------------------------------------------------------------------------

    \572\ EPSA at 31.
---------------------------------------------------------------------------

    556. Duke comments that treatment of shared employees under the 
affiliate restrictions should follow the obligations adopted in the 
standards of conduct. For example, Duke urges the Commission to allow 
the sharing of officers and directors.\573\ Additionally, Avista states 
that the proposed affiliate restrictions should distinguish between 
operational and non-operational employees.\574\
---------------------------------------------------------------------------

    \573\ Duke at 43. See also EPSA at 31; FirstEnergy at 26.
    \574\ Avista at 7-10.
---------------------------------------------------------------------------

    557. PG&E urges the Commission to clarify which employees cannot be 
shared. PG&E states that prohibiting employees involved in general 
operation of generation facilities, who lack control over generation 
availability, from being shared would be overly broad and unduly 
restrictive.\575\ PPL similarly requests clarification of which 
employees would be deemed ``shared employees'' under the affiliate 
restrictions.\576\
---------------------------------------------------------------------------

    \575\ PG&E at 14-21.
    \576\ PPL reply comments at 21-22.
---------------------------------------------------------------------------

    558. NiSource requests that the Commission create an exception to 
allow the sharing between operational employees of the franchised 
public utility and its non-regulated sales affiliates of any 
information necessary to maintain the safe and reliable operation of 
the bulk power system, similar to the exception in the standards of 
conduct at Sec.  358.5(b)(8) of the Commission's regulations.\577\
---------------------------------------------------------------------------

    \577\ NiSource at 1.
---------------------------------------------------------------------------

    559. EEI and FirstEnergy also request that the independent 
functioning requirement and information sharing restrictions in the 
proposed affiliate restrictions should have an exception for sharing 
employees and market information for emergency circumstances affecting 
system reliability.\578\
---------------------------------------------------------------------------

    \578\ EEI at 44; FirstEnergy at 22.
---------------------------------------------------------------------------

    560. On the other hand, Morgan Stanley urges the Commission not to 
adopt a blanket exception to the affiliate restrictions for emergency 
situations because the commenters' proposal regarding what constitutes 
an ``emergency'' is vague and leaves too much discretion to the 
individual sellers. Additionally, Morgan Stanley explains that 
communications with an affiliate during an emergency may not adequately 
address an emergency; sharing information with all sellers in the 
market would provide a better foundation to deal with any 
emergency.\579\
---------------------------------------------------------------------------

    \579\ Morgan Stanley reply comments at 7-8.
---------------------------------------------------------------------------

Commission Determination
    561. The Commission will revise the independent functioning 
requirement of the affiliate restrictions to include exceptions 
relating to permissibly shared senior officers and members of boards of 
directors, shared support personnel, and shared field and maintenance 
personnel. With regard to permissibly shared individuals, the 
Commission will impose a ``no-conduit rule'' similar to that in the 
standards of conduct.\580\ Under the no conduit rule, to be codified at 
Sec.  35.39(g), a permissibly shared employee is prohibited from acting 
as a conduit for disclosing market information to employees, officers 
or directors that are not shared.
---------------------------------------------------------------------------

    \580\ 18 CFR 358.4(a)(5) (shared senior officers and directors); 
18 CFR 358.5(b)(7) (general ``no conduit'' rule covering employees).
---------------------------------------------------------------------------

    562. The Commission agrees that a franchised public utility with 
captive customers and its market-regulated power sales affiliates 
should be permitted to share senior officers and members of the board 
of directors to conduct corporate governance functions, and to take 
advantage of the efficiencies of corporate integration.\581\ Therefore, 
the Commission is adopting an exception at Sec.  35.39(c)(2)(d) that 
permits a franchised public utility with captive customers and its 
market-regulated power sales affiliate to share senior officers and 
members of the board of directors. Specifically, a franchised public 
utility with captive customers and its market-regulated power sales 
affiliate may share senior officers and members of boards of directors 
provided that these individuals do not participate in directing, 
operating or executing generation or market functions.\582\ In 
addition, to prevent permissibly shared senior officers or members of 
the board of directors from using their preferential access to market 
information to harm captive customers, consistent with the no-conduit 
rule codified at Sec.  35.39(g), the permissibly shared senior officers 
and directors may not act as a conduit to provide market information to 
non-shared employees of the franchised public utility with captive 
customers or its market-regulated power sales affiliates.
---------------------------------------------------------------------------

    \581\ Order No. 2004-A at P 134.
    \582\ See 18 CFR 358.4(a)(5).
---------------------------------------------------------------------------

    563. The Commission also agrees that it is appropriate to codify an 
exception that permits the sharing of support employees between the 
franchised public utility with captive customers and its market-
regulated power sales affiliates comparable to the standards of conduct 
exception, likewise subject to the no-conduit rule.\583\
---------------------------------------------------------------------------

    \583\ Order No. 2004 at P 99-101.
---------------------------------------------------------------------------

    564. The Commission rejects Duke's request that the Commission 
include a non-exhaustive list of examples of permissible shared support 
employees within the body of Sec.  35.39. However, we clarify that the 
types of permissibly shared support employees under the standards of 
conduct are the types of permissibly shared support employees that will 
be allowed under the affiliate restrictions in Sec.  35.39(c)(2)(c). 
Such employees include those in legal, accounting, human resources, 
travel and information technology.\584\ Because permissibly shared 
employees may have access to market information, they are

[[Page 39971]]

prohibited from acting as a conduit to provide market information to 
employees of the franchised public utility with captive customers and 
the market-regulated power sales affiliates that are not permitted to 
be shared.
---------------------------------------------------------------------------

    \584\ Id. at P 96.
---------------------------------------------------------------------------

    565. The Commission also agrees to codify an exception to the 
independent functioning requirement to allow franchised public 
utilities with captive customers and their market-regulated power sales 
affiliates to share field and maintenance employees. Field and 
maintenance employees perform purely manual, technical or mechanical 
duties that are supportive in nature and do not have planning or direct 
operational responsibilities. Such employees would likely be part of 
shared work crews to do repair or maintenance work on facilities or 
equipment. Examples of activities that may be performed by shared field 
and maintenance employees are reading meters, replacing parts in 
generators, restringing transmission lines, snow removal or maintaining 
roadways. The key is that these employees do not also perform 
operational duties.\585\ A field or maintenance employee cannot be 
shared if that employee also engages in marketing activities, makes 
decisions that would affect marketing activities, or controls 
generation. We also consider the immediate supervisors of field and 
maintenance employees as permissibly shared employees so long as they 
cannot control operations, e.g. restrict or shut down generation 
facilities.\586\
---------------------------------------------------------------------------

    \585\ Id. at P 145-146.
    \586\ See id. at P 145-46. As discussed later, such actions 
would be permitted in emergency circumstance affecting system 
reliability.
---------------------------------------------------------------------------

    566. The Commission agrees with commenters that allowing the 
sharing of field and maintenance employees between a franchised public 
utility with captive customers and its market-regulated power sales 
affiliates is unlikely to harm captive customers, provided that those 
shared employees do not act as a conduit for sharing market information 
with employees of the franchised public utility with captive customers 
or market-regulated power sales affiliates. The permissibly shared 
field and maintenance employees are required to observe the no-conduit 
rule.
    567. The Commission disagrees with NiSource that a broad exception 
to the independent functioning and information sharing requirement is 
needed for the reliable operation of the bulk power system. Such an 
exception would be so broad that it would swallow the rule and create 
too many opportunities for shared employees to take actions to harm 
captive customers based upon their decision making authority and 
control over the bulk power system. The Commission will consider 
requests for waiver of the affiliate restriction requirements to 
address the specific circumstances of the operation of a bulk power 
system and notes that, subsequent to NiSource's comments, the 
Commission granted a partial waiver of the code of conduct requirements 
for the situation described in NiSource's comments.\587\
---------------------------------------------------------------------------

    \587\ Northern Indiana Public Service Company and Whiting Clean 
Energy, Inc., 116 FERC ] 61,248 (2006). Northern Indiana Public 
Service Company (NIPSCO) sought a waiver of the code of conduct so 
that it could perform its duties as a balancing authority. 
Specifically, NIPSCO wanted the ability to have access to real-time 
information regarding the amount of energy being delivered to NIPSCO 
from its affiliate, Whiting Clean Energy, Inc., (Whiting). The 
Commission granted a partial waiver limited to Whiting providing 
NIPSCO with the real-time information NIPSCO needed to carry out its 
responsibilities as a balancing authority in accordance with the 
requirements of the North American Electric Reliability Council 
(NERC), NERC approved regional reliability organization and the 
Midwest Independent Transmission System Operator, Inc. Id. at P 13. 
The Commission also reminded NIPSCO that its employees were 
prohibited from being a conduit for improperly sharing Whiting's 
generation information. Id.
---------------------------------------------------------------------------

    568. While the Commission does not agree with NiSource's proposal 
for a broad exception to the affiliate restrictions for everyday 
operations of the bulk power system, the Commission does agree with EEI 
and FirstEnergy that the affiliate restrictions should contain an 
exception related to emergency circumstances affecting system 
reliability. As such, the Commission will adopt an exception to the 
independent functioning requirement and the information sharing 
restrictions for emergency circumstances affecting system reliability 
comparable to the exception in the standards of conduct.\588\ The 
exception will apply to both the independent functioning requirements 
and the information sharing restrictions. The Commission will modify 
proposed Sec.  35.39(d) (to be codified at Sec.  35.39(c)(2)(b)) to add 
a provision that states that, notwithstanding any other restrictions in 
this section, in emergency circumstances affecting system reliability, 
a market-regulated power sales affiliate and the franchised public 
utility with captive customers may take the necessary steps to keep the 
bulk power system in operation. The relaxation of the requirements 
during system emergencies is intended to ensure that the franchised 
public utility with captive customers and market-regulated power sales 
affiliate(s) can maintain reliability of the power grid. However, the 
market-regulated power sales affiliate or the franchised public utility 
must report to the Commission and disclose to the public on its Web 
site each emergency that resulted in any deviation from the 
restrictions of Sec.  35.39(c)(2)(b), within 24 hours of such 
deviation. Reports to the Commission of emergency deviations under the 
affiliate restrictions in Sec.  35.39(c)(2)(b) will be made using the 
``EY'' docket prefix.
---------------------------------------------------------------------------

    \588\ 18 CFR 358.4(a)(2).
---------------------------------------------------------------------------

    569. The Commission and the public will be able to monitor the 
frequency of these emergency deviations through the reporting 
requirement. Members of the public can seek redress from the Commission 
if they feel that the exception has been abused or used improperly.
c. Information Sharing Restrictions
Commission Proposal
    570. In the NOPR, the Commission proposed regulatory language to 
codify the information sharing restrictions. Specifically, the 
Commission proposed that the regulations provide that all market 
information sharing between a franchised public utility and a non-
regulated power sales affiliate will be disclosed simultaneously to the 
public. This includes, but is not limited to any communication 
concerning power or transmission business, present or future, positive 
or negative, concrete or potential.\589\
---------------------------------------------------------------------------

    \589\ See NOPR at P 121, 129.
---------------------------------------------------------------------------

Comments
    571. Ameren supports codification of the information sharing 
restrictions, but recommends that proposed Sec.  35.39(c) be revised to 
allow permissibly shared senior officers and directors to receive 
market information so long as they do not act as a conduit to 
improperly share such information, akin to the standards of conduct.
    572. Avista argues that the Commission should allow officers to be 
shared by affiliates, subject to the no-conduit rule.\590\ EEI argues 
that for corporate governance and accountability purposes, there should 
be an exception to the information sharing prohibitions for shared 
senior officers, subject to the no conduit rule.\591\
---------------------------------------------------------------------------

    \590\ Avista at 2.
    \591\ EEI at 44.
---------------------------------------------------------------------------

    573. EPSA also asks the Commission to provide a specific time 
period for the length of time that posted information needs to remain 
on the Web site.\592 \
---------------------------------------------------------------------------

    \592\ EPSA at 31-32.
---------------------------------------------------------------------------

    574. PPL comments that the Commission should clarify which 
situations would permit deviations from the code of conduct regarding

[[Page 39972]]

information sharing. Specifically, it suggests that the Commission 
adopt, for the affiliate restrictions, the standards of conduct 
exception that permits the sharing of information to comply with 
Nuclear Regulatory Commission (NRC) requirements.\593\
---------------------------------------------------------------------------

    \593\ PPL reply comments at 21-22 citing Interpretive Order 
Relating to the Standards of Conduct, 114 FERC ] 61,155 (2006), 
order on request for additional clarification, 115 FERC ] 61,202 
(2006).
---------------------------------------------------------------------------

    575. A number of commenters argue that the Commission should not 
adopt the two-way information sharing prohibition in the uniform code 
of conduct because they disagree that a communication from the non-
regulated power sales affiliate to the franchised public utility could 
potentially harm captive customers.\594 \
---------------------------------------------------------------------------

    \594\ Allegheny Energy Companies' Comments at 3; Duke at 37-40; 
PG&E at 20, FirstEnergy at 23 and FP&L at 4.
---------------------------------------------------------------------------

    576. Duke notes that while the two-way restriction is consistent 
with the default code of conduct that the Commission has used since 
1999, the Commission has approved many codes of conduct that contain 
one-way restrictions (i.e., codes that restrict a franchised public 
utility from sharing marketing information with its non-regulated power 
sales affiliates, but do not place a similar restriction on a non-
regulated power marketer from sharing market information with its 
affiliated franchised utility). Duke says the Commission has failed to 
explain the elimination of previously-approved one-way 
restrictions.\595\ It submits that the one-way code of conduct is 
sufficient to address affiliate abuse concerns and that the two-way 
code of conduct requirement will impose substantial costs on market-
based rate sellers with no discernible benefits.\596\ According to 
Duke, a number of market participants have made important 
organizational and commercial decisions based on current policies and 
precedents allowing one-way communications. In the absence of any basis 
for reversing that policy, Duke submits that the Commission should 
reconsider its proposal to mandate two-way information sharing 
restrictions.
---------------------------------------------------------------------------

    \595\ Duke at 38.
    \596\ Duke reply comments at 20-21.
---------------------------------------------------------------------------

    577. In addition, Duke argues that only two commenters, EPSA and 
ELCON, expressed even generalized support for a standardized code of 
conduct containing the two-way code restriction, but did not address 
the underlying policy issues of why or how a traditional utility's 
regulated customers could be harmed if their unregulated affiliate were 
to share market information with the utility.\597 \
---------------------------------------------------------------------------

    \597\ Id. at 20.
---------------------------------------------------------------------------

    578. According to FP&L, the proposed two-way information sharing 
restriction does not provide any additional protection for captive 
customers. Rather, such a restriction may place artificial and 
unnecessary barriers on a company's ability to conduct business.\598\ 
According to FP&L, the two-way restriction proposed in Sec.  35.39(c) 
(to be codified at Sec.  35.39(d)) concerning the communication of all 
market information between a franchised public utility and its non-
regulated power sales affiliates is unnecessary if sales of capacity 
and energy between those entities are prohibited under the specific 
terms of the market-based rate tariff. It submits that, if the 
Commission nevertheless concludes that a two-way restriction on 
communications should be adopted, then the final regulations should 
provide an exception if, in the market-based rate tariff, the non-
regulated power sales affiliates have restricted sales to, and 
purchases from, their franchised public utility affiliate without 
having received advance Commission approval pursuant to a separate 
filing under section 205 of the FPA.\599 \
---------------------------------------------------------------------------

    \598\ FP&L at 4.
    \599\ Id. at 4-5.
---------------------------------------------------------------------------

    579. Similarly, EEI argues that the Commission has not explained 
how the two-way information sharing prohibition protects captive 
customers.\600 \
---------------------------------------------------------------------------

    \600\ EEI at 45.
---------------------------------------------------------------------------

Commission Determination
    580. The Commission will revise the information sharing 
prohibitions to adopt certain exceptions. As discussed earlier with 
regard to the independent functioning requirement, we are creating 
exceptions to permit shared senior officers and members of a board of 
directors, as well as to permit shared field and maintenance employees. 
Permissibly shared employees may share all types of market information. 
However, the information sharing provision, like all the affiliate 
restrictions, is subject to the ``no-conduit'' rule that we codify in 
the regulations. The no-conduit rule allows permissibly shared 
employees to receive market information so long as they are not 
conduits for sharing that information with employees that are not 
permissibly shared. In addition, as also discussed earlier in the 
independent functioning section, market information may be shared to 
address emergency circumstances affecting system reliability in order 
to keep the bulk power system in operation, provided that the 
subsequent reporting provisions are followed.
    581. In response to PPL Companies' concern as to communications 
relating to nuclear power plants, the Commission clarifies that the 
types of communications permitted under the standards of conduct for 
nuclear safety and regulatory requirements are also permitted under the 
affiliate restrictions.\601\ Specifically, the Commission permitted 
transmission providers to communicate with affiliated and nonaffiliated 
nuclear power plants to enable the nuclear power plants to comply with 
the requirements of the NRC as described in the NRC's February 1, 2006 
Generic Letter 2006-002, Grid Reliability and the Impact on Plant Risk 
and the Operability of Offsite Power.\602\
---------------------------------------------------------------------------

    \601\ Interpretive Order Relating to the Standards of Conduct, 
114 FERC ] 61,155 (2006), order on request for additional 
clarification, 115 FERC ] 61,202 (2006).
    \602\ Nuclear Regulatory Commission's Generic Letter 2006-002, 
Grid Reliability and the Impact on Plant Risk and the Operability of 
Offsite Power. February 1, 2006. OMB Control No.: 3150-0011. 
Transmission providers may share with affiliates information to 
operate and maintain the transmission system and information 
required to maintain interconnected facilities. However, 
transmission providers may not share transmission or marketing 
information that would give a transmission provider's marketing or 
energy affiliates undue preference over a transmission provider's 
non-affiliated customers in energy markets. 114 FERC ] 61,155 
(2006).
---------------------------------------------------------------------------

    582. In response to EPSA's request regarding the specific time 
period that posted material needs to remain on the Web site, the 
Commission concludes that it is appropriate to use the requirements set 
forth regarding OASIS postings in 18 CFR 37.7(b). Specifically, the 
material must be posted for 90 days and then be retained and made 
available upon request for download for five years from the date when 
first posted. The archived material must be available in the same 
electronic form used as when it was originally posted.
    583. The Commission will adopt the two-way information sharing 
restriction in proposed Sec.  35.39(c) (now Sec.  35.39(d)). The 
purpose of the affiliate restrictions in Sec.  35.39 is to ensure that 
franchised public utility sellers with captive customers will not be 
able to engage in affiliate abuse to the detriment of those captive 
customers. One way the Commission achieves this is by restricting the 
sharing of information between a franchised public utility with captive 
customers and a market-regulated power sales affiliate. The Commission 
has long required a seller

[[Page 39973]]

to address any potential affiliate abuse concerns before receiving 
Commission authorization to sell at market-based rates. The Commission 
has previously held that ``[t]here are many ways for the affiliated 
public utility and the affiliated power marketer to exchange 
information that would exacerbate affiliate abuse concerns.'' \603\ 
Therefore, the Commission required that the sellers ``ensure that 
market information is not shared among affiliates.'' \604\
---------------------------------------------------------------------------

    \603\ Heartland Energy Services, Inc., 68 FERC ] 61,223 (1994).
    \604\ Id.
---------------------------------------------------------------------------

    584. The Commission later reaffirmed this in stating the general 
standards under which it reviews applications for market-based rate 
authority, including a demonstration by an affiliate that ``there are 
adequate procedures in place to ensure that market information is not 
shared between it and the affiliate public utility.'' \605\
---------------------------------------------------------------------------

    \605\ LG&E Power Marketing, Inc., 68 FERC ] 61,247 (1994).
---------------------------------------------------------------------------

    585. With regard to Duke's suggestion that we have failed to 
explain the elimination of the one-way restriction, we will provide the 
following example of our concern in this regard.
    586. One example of how of improper sharing of information could 
harm captive customers is a circumstance where both a franchised public 
utility and its market-regulated power sales affiliate are considering 
whether to bid into an RFP to provide power. If the market-regulated 
power sales affiliate has absolute freedom to inform its franchised 
public utility affiliate that it intends to bid into the RFP, including 
but not limited to the price and quantity it intends to offer, the 
franchised public utility affiliate has the ability and incentive to 
use that information to benefit its stockholders at the expense of its 
captive customers (e.g., by either not bidding into the RFP or doing so 
at a price above that of its affiliate).
    587. While we recognize that some sellers may need to adjust their 
activities to comply with the two-way information restriction, we do 
not believe that such adjustments will impose significant costs upon 
those sellers. Furthermore, as explained above, we believe that the 
two-way information sharing restriction will provide captive customers 
a more complete protection from affiliate abuse. We find that any 
potential cost to sellers is outweighed by the increased protection a 
two-way information sharing restriction provides to captive customers.
    588. Therefore, to ensure that all captive customers are protected 
from the potential for affiliate abuse, the Commission will adopt the 
proposed two-way information restriction in Sec.  35.39(d). Any sellers 
whose activities are currently governed by a code of conduct with a 
one-way information restriction will be deemed to have adopted a two-
way information restriction as of the effective date of this Final 
Rule.
    589. The Commission restates that the affiliate restrictions only 
apply when captive customers exist; therefore, if the Commission has 
found that there are no captive customers, then, consistent with Sec.  
35.39(b) through (g), the affiliate restrictions, including the 
prohibition on information sharing, will not apply.
d. Definition of ``Market Information''
Comments
    590. Progress Energy urges the Commission to clarify the definition 
of the term ``market information'' which it argues is arbitrarily broad 
and may include public as well as non-public market information.\606\ 
SoCal Edison states that the Commission should only prohibit the 
sharing of non-public market information among a utility and its 
market-regulated power sales affiliates, as outlined in the standards 
of conduct.\607\ EPSA also asserts that the Commission should clarify 
that the simultaneous posting requirement should apply to the 
communication of all non-public market information (not all market 
information). It notes that Order No. 2004 specifically applies to non-
public transmission information, not all transmission information.
---------------------------------------------------------------------------

    \606\ Progress Energy at 36-37.
    \607\ SoCal Edison at 3-6.
---------------------------------------------------------------------------

Commission Determination
    591. The Commission previously explained that ``market 
information'' includes information on sales or purchases that will not 
be made (as well as purchases and sales that will be made), as well as 
any information concerning a utility's power or transmission business--
broker-related or not, past, present or future, positive or negative, 
concrete or potential, significant or slight.\608\ In an effort to 
provide additional clarity and regulatory certainty, we will provide 
further guidance and adopt and codify in Sec.  35.36(a)(8) the 
following definition of market information: ``market information means 
non-public information related to the electric energy and power 
business including, but not limited to, information regarding sales, 
cost of production, generator outages, generator heat rates, 
unconsummated transactions, or historical generator volumes. Market 
information includes information from either affiliates or non-
affiliates.''
---------------------------------------------------------------------------

    \608\ UtiliCorp United, Inc., 75 FERC ] 61,168 (1996).
---------------------------------------------------------------------------

    592. The Commission clarifies that the definition does not prohibit 
the disclosure of publicly available information. We find that, because 
of its very nature of being publicly available to all entities, 
restrictions on sharing publicly available information are unnecessary. 
In addition, the definition does not prohibit the sharing of 
transmission information. The standards of conduct already prevent 
improper disclosures of non-public transmission information by a 
transmission provider to its marketing and energy affiliates, which 
would include both the franchised public utility with captive customers 
and the market-regulated power sales affiliate.\609\
---------------------------------------------------------------------------

    \609\ 18 CFR 358.5(a) and (b) (2006).
---------------------------------------------------------------------------

    593. Further, as we have indicated, a principal purpose of the 
affiliate restrictions is to ensure that the interaction between a 
franchised public utility and its market-regulated affiliate does not 
result in harm to the franchised public utility's captive customers. 
Therefore, we clarify that, as a general matter, the definition of 
``market information'' includes information that, if shared between a 
franchised public utility and a market-regulated affiliate, may result 
in a detriment to the franchised public utility's captive customers. 
Therefore, market information includes, but is not limited to, 
information concerning sales and purchases that will not be made such 
as in circumstances where parties have discussed a potential contract 
but no agreement has been reached. In contrast, market information does 
not include information that would not result in an advantage to the 
recipient that could be used to the detriment of the franchised public 
utility's captive customers. For example, a franchised public utility 
with captive customers and its market-regulated power sales affiliate 
may share information related to the relocation of the franchised 
public utility's headquarters, business opportunities outside the 
United States, general turbine safety information and internal 
procedures for general maintenance activities (other than scheduling). 
We clarify that the definition of ``market information'' includes, but 
is not limited to, written, printed, verbal, audiovisual, or graphic 
information.
    594. We are adding language to the information sharing restriction 
of Sec.  35.39(d)(1) to make clear that disclosures of market 
information are

[[Page 39974]]

prohibited, unless simultaneously disclosed to the public, if the 
information could be used to the detriment of captive customers. For 
example, if a franchised public utility with captive customers conducts 
negotiations with an unaffiliated generator to acquire power, but does 
not reach an agreement, the franchised public utility with captive 
customers is prohibited from sharing with its market-regulated power 
sales affiliate any non-public information it acquired through the 
unsuccessful negotiations unless such information is simultaneously 
disclosed to the public. Information relating to any other entities' 
electric energy or power business is also subject to the sharing of 
market information restriction if such information could be used to the 
detriment of captive customers. Also subject to the information sharing 
restriction is information regarding brokering activities, past sales 
and purchase activities, and the availability or price of inputs to 
generation such as natural gas supply if such information could be used 
to the detriment of captive customers. For example, a franchised public 
utility with captive customers is restricted from disclosing to its 
market-regulated power sales affiliate any non-public information about 
a non-affiliated generator's upcoming maintenance or outage schedules 
or information about the non-affiliated generator's historical 
generation volumes, unless such information is simultaneously disclosed 
to the public. In addition, neither the franchised public utility with 
captive customers nor its market-regulated power sales affiliate may 
tell the other that it intends to sell power to a third party, 
including but not limited to the price and quantity it intends to 
offer, unless such information is simultaneously disclosed to the 
public. Similarly, a market-regulated power sales affiliate is likewise 
restricted from telling its franchised public utility affiliate with 
captive customers about any other business opportunity that it is 
considering or is undertaking, unless such information is 
simultaneously disclosed to the public.
e. Sales of Non-Power Goods or Services
Commission Proposal
    595. In the NOPR, the Commission proposed regulatory language to 
codify the requirements governing sales of non-power goods or services. 
The Commission proposed that sales of any non-power goods or services 
by a franchised public utility to a market-regulated power sales 
affiliates will be at the higher of cost or market price, and that 
sales of any non-power goods or services by a market-regulated power 
sales affiliate to an affiliated franchised public utility will not be 
at a price above market.
Comments
    596. PG&E argues that, while charging the high of cost or market 
price may be appropriate for sales of goods, it is ``inoperable and 
inappropriate'' for sales of services because market prices for sales 
of service by a third party may be hard to ascertain due to limited 
providers and that prices from a third party provider will not take 
into account efficiencies resulting from a utility and its affiliate 
sharing services.\610\ PG&E further comments that charging the higher 
of cost or market, as proposed, may increase costs for both the utility 
and the affiliate by discouraging the efficient sharing of services. 
Therefore, PG&E proposes that instead of charging the higher of cost or 
market price for non-power services, the Commission should allow a 
proxy for the market price such as the fully-loaded cost plus a 
reasonable profit, e.g., five percent.\611\
---------------------------------------------------------------------------

    \610\ PG&E at 20-21.
    \611\ Id. at 21.
---------------------------------------------------------------------------

Commission Determination
    597. The Commission will adopt the NOPR proposal to codify the 
requirement that sales of non-power goods and services by a franchised 
public utility with captive customers to a market-regulated power sales 
affiliate be at the higher of cost or market price, unless otherwise 
authorized by the Commission. This requirement, along with other 
requirements in the affiliate restrictions, protect a franchised public 
utility's captive customers against inappropriate cross-subsidization 
of market-regulated power sales affiliates by ensuring that the utility 
with captive customers does not recover too little for goods and 
services that the utility provides to a market-regulated power sales 
affiliate.\612\ We also adopt the NOPR proposal to codify the 
requirement that sales of any non-power goods or services by a market-
regulated power sales affiliate to an affiliated franchised public 
utility with captive customers will not be at a price above market, 
unless otherwise authorized by the Commission. This requirement 
protects a utility's captive customers against inappropriate cross-
subsidization of market-regulated power sales affiliates by ensuring 
that the utility with captive customers does not pay too much for goods 
and services that the utility receives from a market-regulated power 
sales affiliate.
---------------------------------------------------------------------------

    \612\ See generally National Grid plc and Keyspan Corp., 117 
FERC ] 61,080 at P 65-66 (2006), reh'g pending.
---------------------------------------------------------------------------

    598. We note that PG&E fails to provide the Commission with any 
specific examples of non-power services for which there is no 
corresponding third-party provider. Therefore, we are not persuaded by 
PG&E that there is a need or a benefit to changing our precedent on 
this issue. We will adopt the affiliate restrictions as proposed and 
require that sales of non-power goods or services by a franchised 
public utility with captive customers to a market-regulated power sales 
affiliate be at the higher of cost or market price. Nevertheless, we 
will address on a case-by-case basis arguments that charging the higher 
of cost or market for certain sales of non-power services may not be 
appropriate in a particular case.
f. Service Companies or Parent Companies Acting on Behalf of and for 
the Benefit of a Franchised Public Utility
Commission Proposal
    599. The Commission proposed in the NOPR to treat companies that 
are acting on behalf of and for the benefit of franchised public 
utilities with captive customers, for purposes of the affiliate 
provisions, as that franchised public utility. Likewise, in the case of 
non-regulated affiliates, the proposed affiliate provisions treat 
companies that are acting on behalf of and for the benefit of non-
regulated affiliates, for purposes of the affiliate provisions, as the 
non-regulated affiliates.\613 \
---------------------------------------------------------------------------

    \613\ NOPR at 83-84.
---------------------------------------------------------------------------

Comments
    600. EEI asks the Commission to clarify that the code of conduct 
(affiliate restrictions) provisions to be codified in the regulations 
do not preclude the use of service companies that manage assets for 
both regulated and unregulated affiliates.\614\ EEI submits that the 
language of proposed Sec.  35.39(b) (now Sec.  35.39(c)) uses 
``entities acting on behalf of and for the benefit of a franchised 
pubic utility (such as entities managing the electric generation assets 
of the franchised public utility)'' whereas the NOPR text reads 
``entities acting on behalf of and for the benefit of a franchised 
public utility (such as service companies and entities managing the 
generation assets of the franchised pubic utility).'' EEI argues that 
the treatment of service companies as part of the franchised public 
utility in the preamble to the NOPR is different from the language in 
the proposed

[[Page 39975]]

regulation and makes the Commission's intent unclear. It submits that 
many companies use service companies to provide support activities to 
the franchised utility and non-regulated affiliates consistent with the 
no-conduit rule. EEI asks the Commission to clarify that the 
standardization of the code of conduct is not intended to change this 
practice. PG&E claims that under a plain reading of the proposed 
regulation, a parent company that acts on behalf of either the utility 
or the affiliate will be considered a part of the utility or affiliate, 
and communication with either entity will be restricted under proposed 
Sec.  35.39(c) (now Sec.  35.39(d)).\615\ It argues that the Commission 
should only consider a holding company or parent company as an 
affiliate subject to the information sharing prohibitions if it engages 
in energy transactions on its own behalf.\616\
---------------------------------------------------------------------------

    \614\ EEI at 45-46.
    \615\ PG&E at 16-17.
    \616\ PG&E at 17.
---------------------------------------------------------------------------

    601. Southern states that it is unclear how the Commission intends 
to address and apply the requirements of separation of functions and 
information sharing in the context of public utility holding companies 
that have system pooling agreements.\617\ Southern recommends the 
Commission refine the definition of ``non-regulated power sales 
affiliate'' at least insofar as that term is used in the proposed 
separation of functions and information sharing provisions to exclude 
pooled system affiliates of traditional franchised utilities where 
affiliate interactions and sharing of benefits and burdens of pooled 
operations are addressed under an arrangement filed and approved under 
section 205.\618\
---------------------------------------------------------------------------

    \617\ Southern at 49.
    \618\ Southern at 50.
---------------------------------------------------------------------------

    602. EEI requests that the Commission clarify that, in 
circumstances where sales between affiliates have been made in 
connection with an approved system agreement, such agreements continue 
to govern.\619\ Southern requests that the Final Rule clarify that 
affiliated operating companies may continue to operate on a pooled 
basis.\620\ Southern states that traditional centralized service 
company affiliates providing system pooling support services under 
filed and approved system agreements should not be treated as non-
regulated power sales affiliates.\621\
---------------------------------------------------------------------------

    \619\ EEI at 46-49.
    \620\ Southern at 44-52. Southern also asks that the Commission 
revise the affiliate abuse regulations to include a definition of 
``pooled system affiliates'' and clarify that the definition of non-
regulated power sales affiliate excludes ``pooled system 
affiliates'' of traditional franchised utilities. Southern states 
that any definition of ``pooled system affiliates'' should address 
both existing arrangements (that have been reviewed and approved by 
the Commission) and prospective arrangements.
    \621\ Southern at 48-52.
---------------------------------------------------------------------------

Commission Determination
    603. The Commission clarifies that it did not intend to include 
service companies as ``entities acting on behalf of and for the benefit 
of a franchised public utility'' for purposes of the separation of 
functions provision in Sec.  35.39(b) (now Sec.  35.39(c)) to the 
extent that such service companies do not engage in generation or 
marketing activities.\622\ Although service companies not engaged in 
generation or marketing activities are not included in the coverage of 
Sec.  35.39(e), they may not act as a conduit for providing non-public 
market information between a franchised public utility and a market-
regulated power sales affiliate. However, unless otherwise permitted by 
Commission rule or order, service companies cannot be used to direct, 
organize or execute generation or marketing activities for both the 
franchised public utility and the market-regulated power sales 
affiliate(s). In response to Southern's and EEI's request to clarify 
that affiliated operating companies may continue to operate as a pool 
or pursuant to an approved system agreement, nothing in this Final Rule 
precludes pool operation pursuant to filed tariffs or agreements 
approved by the Commission and nothing in this rule changes filed 
system agreements approved by the Commission. To the extent that 
individual companies enter into new pooling or system agreements, the 
Commission will continue to review those agreements on a case-by-case 
basis to ensure that, among other things, affiliate transactions meet 
the requirements of section 205 of the FPA and otherwise satisfy our 
affiliate abuse concerns.
---------------------------------------------------------------------------

    \622\ As proposed in the NOPR, the separation of functions 
provision provided that ``entities acting on behalf of and for the 
benefit of a franchised public utility (such as entities managing 
the generation assets of the franchised public utility) are 
considered part of the franchised public utility.'' In this Final 
Rule, we modify the parenthetical in that provision to state: 
``(such as entities controlling or marketing power from the 
electrical generation assets of the franchised public utility).'' 
See 18 CFR 35.39(c)(1).
---------------------------------------------------------------------------

D. Mitigation

    604. In the NOPR, the Commission sought comment on whether the 
default mitigation adopted in the April 14 Order is appropriate as 
currently structured. The Commission's current default mitigation rates 
are as follows: (1) Sales of power of one week or less will be priced 
at the seller's incremental cost plus a 10 percent adder; (2) sales of 
power of more than one week but less than one year (sometimes referred 
to as ``mid-term sales'') will be priced at an embedded cost ``up to'' 
rate reflecting the costs of the unit or units expected to provide the 
service; and (3) new contracts for sales of power for one year or more 
will be priced at a rate not to exceed the embedded cost of service, 
and the contract will be filed with the Commission for review and 
approved prior to the commencement of service.\623\
---------------------------------------------------------------------------

    \623\ April 14 Order, 107 FERC ] 61,018 at P 151; see also NOPR 
at P 22, 137.
---------------------------------------------------------------------------

    605. In the NOPR, the Commission sought comment on the following 
four issues that have arisen in implementing cost-based mitigation: (i) 
The rate methodology for designing cost-based mitigation; (ii) 
discounting; (iii) protecting customers in mitigated markets; and (iv) 
sales by mitigated sellers that ``sink'' in unmitigated markets.
1. Cost-Based Rate Methodology
a. Sales of One Week or Less
Commission Proposal
    606. The Commission noted that two principal issues concerning rate 
methodology have arisen in implementing the April 14 Order. The first 
relates to power sales of one week or less being made at incremental 
cost plus 10 percent.\624\ The Commission noted that sellers have 
argued that this is a departure from the Commission's historical 
acceptance of ``up to'' rates for short-term energy sales, including 
sales of one week or less, and sought comment on whether to continue to 
apply a default rate for such sales that is tied to incremental cost 
plus 10 percent. The Commission sought comment as to: (i) Whether there 
are problems associated with using ``up to'' rates for shorter-term 
sales and, if so, what are they; (ii) whether the current approach 
provides utilities a disincentive to offer their power to wholesale 
customers in their local control area for short-term sales; and (iii) 
whether an ``up to'' rate adequately mitigates market power for such 
sales.
---------------------------------------------------------------------------

    \624\ In a number of instances, the NOPR referred to these sales 
as ``sales of less than one week,'' and a number of commenters 
likewise used ``sales of less than one week'' in their comments. We 
clarify that the reference in the NOPR should have been to ``sales 
of one week or less,'' consistent with the April 14 and July 8 
Orders. Accordingly, for purposes of this Final Rule, we use ``sales 
of one week or less'' even if the commenters used ``sales of less 
than one week.''

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[[Page 39976]]

Comments
    607. While not opposing the default rate, APPA/TAPS state that as 
an alternative, sales of one week or less could occur under the 
traditional ``split the savings'' methodology.\625\ APPA/TAPS submit 
that both of these methods are consistent with the Commission's 
observation that ``[a]bsent market power, a generator would typically 
run if it had excess power and could cover its incremental costs plus 
some return.'' \626\
---------------------------------------------------------------------------

    \625\ APPA/TAPS at 45-46.
    \626\ Id. (quoting April 14 Order, 107 FERC ] 61,018 at P 152).
---------------------------------------------------------------------------

    608. While the Carolina Agencies claim that sales of one week or 
less should not carry a capacity charge, they concede that a reasonable 
contribution to the mitigated supplier's fixed costs may be appropriate 
(e.g., by including a modest adder over the supplier's incremental cost 
of energy).\627\
---------------------------------------------------------------------------

    \627\ Carolina Agencies at 11.
---------------------------------------------------------------------------

    609. NRECA and AARP ask the Commission to retain the incremental 
cost plus 10 percent methodology for mitigating sales of one week or 
less.\628\ NRECA expresses a concern that the Commission's default 
cost-based rates (for all three products--sales of one week or less; 
sales of more than one week but less than one year; and sales of one 
year or longer) may be subject to gaming by larger public utilities, 
especially because the sellers hold all of the critical data. It 
asserts that if sellers have too much leeway in choosing which units 
they will use to calculate their incremental or embedded costs, the 
default cost-based rates will not provide an effective rate ceiling, 
and the purpose of the default mitigation will be undermined. NRECA 
proposes that the Commission require sellers subject to default cost-
based rates to submit both pre- and post-approval filings supporting 
the mitigated cost-based rates for short- and mid-term sales. NRECA 
suggests that the seller justify its mitigated rates beforehand by 
demonstrating its incremental costs or embedded costs, as appropriate, 
and then file after-the-fact quarterly reports of the actual sales and 
the actual incremental or embedded costs incurred in making these 
sales.\629\ NRECA suggests that this approach would subject mitigated 
cost-based rate sales to a cost-based formula rate, and therefore to 
refund, upon Commission review of the quarterly compliance filing.\630\
---------------------------------------------------------------------------

    \628\ NRECA at 30; AARP at 8.
    \629\ Suez/Chevron voice a similar concern, adding that a true-
up provision would also help improve transparency with regard to the 
cost of mitigated sales for the benefit of state commissions. Suez/
Chevron at 13-14.
    \630\ NRECA at 30-32.
---------------------------------------------------------------------------

    610. NASUCA urges the Commission to require that all mitigated 
rates, and any rate discounts, whether for more or less than one year 
in duration, must be filed and made subject to public scrutiny and 
Commission review under section 205 of the FPA.\631\ NASUCA is 
concerned that under the NOPR, only rates to be in effect for more than 
one year are required to be filed publicly in advance and subject to 
protest, intervention, prior Commission review and revision. It argues, 
however, that section 205 contains no exception from the filing 
requirement for sales of less than one year.\632\ Given that all new 
rate schedules and contracts affecting rates must be publicly filed, 
NASUCA asks the Commission not to reduce section 205's procedural 
safeguards for sales of less than one year at cost-based rates (i.e., 
by not requiring that they be subject to prior notice and review).\633\
---------------------------------------------------------------------------

    \631\ NASUCA at 18-19; NASUCA reply comments at 16-18.
    \632\ NASUCA at 18 (citing NOPR at P 22).
    \633\ Id. at 18-19.
---------------------------------------------------------------------------

    611. Some commenters oppose the incremental cost plus 10 percent 
default rate, with several alleging that it deviates from prior 
Commission precedent without sufficient justification and fails to 
adequately compensate sellers.\634\ Some commenters also allege that 
such an approach will deter new entry and gives sellers the incentive 
to sell outside the mitigated market.
---------------------------------------------------------------------------

    \634\ MidAmerican at 9-11, Westar at 24.
---------------------------------------------------------------------------

    612. For example, Westar states that the Commission's reasoning in 
the July 8 Order which explained that the cost plus 10 percent default 
rate represents a ``conservative proxy for a reasonable margin 
available in a competitive market,'' \635\ suffers from two fatal 
flaws. First, the Commission failed to distinguish or even mention 
Terra Comfort wherein, Westar and Duke submit, the Commission found 
that 10 percent adders provide no contribution to fixed costs, and it 
rejected the argument that ``utilities routinely forego these margins 
and sell at 110 percent of incremental cost.'' \636\ Second, according 
to Westar, in adopting this default rate the Commission relied heavily 
upon an order that applied the formula in an RTO under entirely 
different circumstances.\637\
---------------------------------------------------------------------------

    \635\ July 8 Order, 108 FERC ] 61,026 at P 155.
    \636\ Westar at 24 (quoting Terra Comfort Corp., 52 FERC ] 
61,241 at 61,839-40 (1990)); Duke at 8-9, n.9.
    \637\ Westar at 25 (citing PJM Interconnection, L.L.C., 107 FERC 
] 61,112, at 61,366 (2004), order on reh'g, PJM Interconnection, 
L.L.C., 110 FERC ] 61,053 (2005)).
---------------------------------------------------------------------------

    613. MidAmerican and Westar note that, in support of the default 
rate, in the April 14 Order the Commission cited a PJM tariff provision 
pursuant to which generators dispatched out of economic merit have 
their bids mitigated to incremental costs plus 10 percent to prevent 
them from exercising market power and, at the same time, providing 
revenues which include a margin.\638\ MidAmerican and Westar contend 
that this is merely an example of a mitigation mechanism, not a 
rationale for a broad-scale default mitigation scheme that ignores 
years of precedent.\639\ They submit that the PJM tariff mitigates bids 
for a select set of generators. They state that, regardless of the 
level of their bids, those generators are still paid the market 
clearing price because only the offer is capped. Further, because PJM's 
methodology applied this offer cap only to a limited number of hours, 
MidAmerican and Westar state that sellers were also free to bid above 
the cap in the majority of the hours of the year.\640\ In contrast, 
MidAmerican and Westar claim that the incremental cost plus 10 percent 
default rate is an absolute cap on revenues that would apply to all 
sales of one week or less in length.\641\
---------------------------------------------------------------------------

    \638\ April 14 Order, 107 FERC ] 61,018 at P 152, n.146.
    \639\ MidAmerican at 10; Westar at 25.
    \640\ Id.
    \641\ Id.
---------------------------------------------------------------------------

    614. Although the July 8 Order explained that incremental cost plus 
10 percent was a backstop, default rate, and that entities were free to 
propose alternative mitigation schemes, MidAmerican asserts that this 
ignores the fact that the Commission has routinely accepted alternative 
cost-based rates for sales of one week or less. As such, MidAmerican 
maintains that there is no reason why ``split the savings'' rates, or 
rates reflecting a demand charge, could not be used as a default rate 
for mitigated sales of one week or less.\642\
---------------------------------------------------------------------------

    \642\ MidAmerican at 13.
---------------------------------------------------------------------------

    615. Several commenters also argue that the energy-only incremental 
cost plus 10 percent methodology does not allow for proper recovery of 
capacity-based costs on sales of one week or less thereby artificially 
depressing the prices of these short-term sales and possibly deterring 
new entry.\643\ These commenters state that sellers should be

[[Page 39977]]

allowed to recover a contribution to their fixed/capacity costs.
---------------------------------------------------------------------------

    \643\ Pinnacle at 10; Ameren at 15; Duke at 8; MidAmerican at 9-
11; Westar at 24; Drs. Broehm and Fox-Penner at 15-16; Xcel at 9; 
Progress Energy at 9; PPL reply comments at 17-18; EEI at 29; NRG at 
5, 11.
---------------------------------------------------------------------------

    616. Some commenters contend that the default cost-based rates 
create an incentive to sell outside the mitigated market because they 
recover less than cost-based rates historically accepted that included 
a demand charge. However, they assert that setting rates that require 
buyers to make a reasonable contribution to the seller's fixed costs 
for the use of the capacity would create an incentive for the seller to 
make sales within its mitigated control area.\644\ Duke and the Oregon 
Commission add that allowing recovery of capacity-based costs also 
ensures that wholesale customers bear their fair share of system 
costs.\645\
---------------------------------------------------------------------------

    \644\ See, e.g., Duke at 9.
    \645\ Id. at 10; Oregon Commission reply comments at 2.
---------------------------------------------------------------------------

    617. Several commenters also claim that by artificially depressing 
short-term sales prices, the default rate transfers wealth from the 
supplier's retail customers to wholesale customers.\646\ Such retail 
customers, these commenters state, have paid the fully-allocated costs 
of the system and obtain revenue credits to their costs from the 
supplier's short-term sales. Where short-term sales are made on a non-
interruptible basis, and the incremental cost plus 10 percent rate 
prices them only at incremental running cost, Progress Energy contends 
that wholesale purchasers are receiving the benefits of capacity 
without cost.\647\ Progress Energy and EEI submit that retail native 
load customers, as a result, lose the economic benefits that would 
otherwise accrue to them through revenue credits from short-term 
wholesale sales.\648\ Wholesale customers charged through an embedded 
cost-of-service are also harmed, Progress Energy adds, because they 
lose the economic benefits that would otherwise accrue to them through 
revenue credits from short-term wholesale sales.\649\
---------------------------------------------------------------------------

    \646\ Westar at 16; Progress Energy at 9; EEI at 33-34; Pinnacle 
at 10; MidAmerican at 9.
    \647\ Progress Energy at 9-10.
    \648\ Id. at 10, n.13; EEI at 29.
    \649\ Progress Energy at 10, n.13.
---------------------------------------------------------------------------

    618. Progress Energy and Duke instead favor an ``up to'' cost-based 
default rate for sales of one week or less.\650\ For such sales, 
Progress Energy supports an ``up to'' rate design flexible enough to 
allow rates as low as the mitigated seller's incremental costs and as 
high as 100 percent of the seller's capacity and energy costs. 
According to Progress Energy, a mitigated seller could choose to make 
sales as low as its incremental cost when either (1) The unmitigated 
market price of competing sellers dictates that price, or (2) the 
mitigated seller needs to sell its excess generation at that price to 
maintain a minimum generation control margin. Given that there is a 
short-term market for capacity, Progress Energy asks that the default 
cost-based rates include a price structure that allows pricing of 
capacity-only sales.\651\
---------------------------------------------------------------------------

    \650\ Progress Energy at 10; Duke at 8.
    \651\ Progress Energy at 10.
---------------------------------------------------------------------------

    619. Xcel suggests that the Commission should allow for an even 
higher emergency price in situations where purchasers need to make a 
purchase not simply to achieve economic benefits but where the 
purchaser is capacity deficient. Xcel submits that in such instances, a 
purchaser plainly obtains a capacity benefit from the purchase of such 
power. Historically, the Commission has allowed an emergency rate of 
$100 per MWh for emergency service. Given that gas prices have 
dramatically increased since that standard rate began to be utilized, 
Xcel claims that an emergency rate of the higher of cost plus 10 
percent or $1,000 per MWh would be appropriate in the present 
environment.\652\
---------------------------------------------------------------------------

    \652\ Xcel at 10.
---------------------------------------------------------------------------

Commission Determination
    620. The Commission will retain the incremental cost plus 10 
percent methodology as the default mitigation for sales of one week or 
less, while continuing to allow sellers to propose alternative cost-
based methods of mitigation tailored to their particular circumstances. 
As discussed more fully below, we clarify that in retaining the 
incremental cost plus 10 percent methodology as the default mitigation 
for sales of one week or less we do not otherwise limit a seller's 
ability to propose different cost-based rates for sales of one week or 
less.\653\
---------------------------------------------------------------------------

    \653\ For that matter, we also do not limit a seller's ability 
to propose and support different cost-based rates for any of the 
default cost-based rates.
---------------------------------------------------------------------------

    621. Although a number of commenters suggest that the Commission 
should adopt a different default cost-based ratemaking methodology for 
sales of one week or less, they have failed to persuade us that the 
existing default rate is inappropriate. As the Commission has 
previously stated, an incremental cost rate that allows a fair recovery 
of the incremental cost of generating with a 10 percent adder to 
provide for a margin over incremental cost is reasonable.\654\ 
Incremental costs plus 10 percent represents a conservative proxy for a 
reasonable rate available in a competitive market.\655\ On this basis, 
we find incremental cost plus 10 percent to be an appropriate default 
rate. Moreover, we allow sellers the opportunity to design, support, 
and propose other cost-based rates that they believe are more 
appropriate for their particular circumstances.
---------------------------------------------------------------------------

    \654\ April 14 Order, 107 FERC ] 61,018 at P 152.
    \655\ July 8 Order, 108 FERC ] 61,026 at P 155.
---------------------------------------------------------------------------

    622. Several commenters note that the Commission has permitted 
various cost-based rate methodologies prior to the April 14 Order, 
including a split-the-savings formula. These entities express concern 
that the use of the incremental cost plus 10 percent methodology as the 
default mitigation rate for sales of one week or less forecloses the 
possibility of other cost-based pricing methodologies. However, this is 
not the case. Rather than precluding alternative mitigation proposals, 
the April 14 Order allows sellers to propose case-specific tailored 
mitigation, or adopt the default cost-based rate. The April 14 Order 
described the default mitigation rate as ``a backstop measure'' 
intended to ensure a just and reasonable rate.\656\ The Commission re-
emphasized this in its July 8 Order explaining: ``In the instant case, 
the 10 percent adder is to be used only as a backstop or default 
measure in the event that an applicant does not opt to propose its own 
mitigation.'' \657\
---------------------------------------------------------------------------

    \656\ April 14 Order, 107 FERC ] 61,018 at P 148.
    \657\ July 8 Order, 108 FERC ] 61,026 at P 157 (emphasis added).
---------------------------------------------------------------------------

    623. As such, the incremental cost plus 10 percent rate represents 
a default, cost-based rate to protect customers from the potential 
exercise of market power and provide sellers regulatory rate certainty 
by establishing a ``safe harbor.'' Any proposal for alternative cost-
based rates will be considered on a case-by-case basis.
    624. Further, with regard to including capacity charges in rates 
for one week or less, a seller may propose to recover such charges and 
the Commission will consider these charges based on the specific facts 
and circumstances presented. Rather than ignoring alternative forms of 
cost-based rates, as some commenters claim, the Commission's policy 
offers sellers the opportunity to propose such alternatives.
    625. Use of the default rate as set forth in the April 14 and July 
8 Orders also is not inconsistent with Terra Comfort, as some 
commenters claim. As explained above, contrary to some commenters' 
allegations, the Commission does not confine mitigated sellers to rates 
that forego a contribution to fixed/capacity costs. In Terra Comfort, 
the Commission explained that

[[Page 39978]]

``most utilities maintain on file for all services flexible demand 
charge ceilings designed to reflect a 100-percent contribution to the 
fixed costs of their facilities.'' \658\ The Commission then added that 
utilities are not obligated to ``forego these margins and sell at 110 
percent of incremental costs.'' \659\ In the April 14 Order, the 
Commission, consistent with its holding in Terra Comfort, explained 
that ``as a backstop measure, we will also provide `default' rates to 
ensure that wholesale rates do not go into effect, or remain in effect, 
without assurance that they are just and reasonable.'' \660\ Contrary 
to Duke's assertion that this default rate suggests that sellers do not 
have economic justification (or need) to recover a share of their 
fixed/capacity costs in the prices charged for such transactions,\661\ 
the Commission's policy allows ``applicants to propose case-specific 
mitigation tailored to their particular circumstances that eliminates 
the ability to exercise market power, or adopt cost-based rates such as 
the default rates herein.'' \662\ The Commission explained in the April 
14 Order that ``[p]roposals for alternative mitigation in these 
circumstances could include cost-based rates or other mitigation that 
the Commission may deem appropriate.'' \663\ Consistent with industry 
practice and Commission precedent, therefore, where mitigated sellers 
can properly justify such contributions, they may propose to recover 
contributions to fixed/capacity costs under the Commission's mitigation 
policy.
---------------------------------------------------------------------------

    \658\ Terra Comfort Corp., 52 FERC at 61,839.
    \659\ Id.
    \660\ April 14 Order, 107 FERC ] 61,018 at P 148.
    \661\ Duke at 9 (citing Terra Comfort, 52 FERC at 61,839).
    \662\ April 14 Order, 107 FERC ] 61,018 at P 147.
    \663\ 663 April 14 Order, 107 FERC ] 61,018 at n.142.
---------------------------------------------------------------------------

    626. Such alternative mitigation has been proposed and accepted. 
For example, Progress Energy correctly notes that one of its 
subsidiaries proposed as mitigation--and the Commission approved--a 
cost-based ``up-to'' capacity charge and a cost-based energy charge for 
the subsidiary's power sales of less than one year, including sales of 
one week or less, in the mitigated control area.\664\ Progress Energy 
is correct in observing that this decision was consistent with the 
Commission's long-standing policy of permitting the pricing of short-
term sales at cost-based ``up-to'' capacity charges and cost-based 
energy charges.\665\ Rather than artificially depressing the prices of 
short-term sales, exacting a wealth transfer, or limiting a seller's 
ability to respond to market conditions, as Progress suggests, the 
default cost-based rate for sales of one week or less provides a 
backstop measure intended to protect customers by ensuring that, in the 
event a seller loses or relinquishes its market-based rate authority, 
there is a readily available cost-based rate under which such sellers 
may choose to transact, and the mitigated seller by establishing a 
refund floor that provides it with rate certainty.
---------------------------------------------------------------------------

    \664\ Carolina Power & Light, 113 FERC ] 61,130 at P 23-24 
(2005) (citing Detroit Edison Co., 78 FERC ] 61,149 (1997) 
(approving a demand charge for power sales for periods of an hour up 
to one year); Illinois Power Co., 57 FERC ] 61,213, at 61,699-700 
(1991) (permitting utilities to include in their rates an amount 
above incremental costs to provide a contribution to fixed costs)).
    \665\ Progress Energy at 8-9.
---------------------------------------------------------------------------

    627. As to some commenters' suggestion that the incremental cost 
plus 10 percent methodology, and cost-based rates in general, adversely 
affect retail rates because they exact a wealth transfer from the 
supplier's retail customers to wholesale customers, the July 8 Order 
rejected such claims on the ground that they were ``unsupported and 
speculative.'' \666\ Not only do these claims remain unsupported but 
they suggest that the Commission should allow wholesale rates in excess 
of a just and reasonable rate. This result would not be just and 
reasonable. As the Commission stated in the July 8 Order, ``our rate 
making policy is designed to provide for recovery of prudently incurred 
costs plus a reasonable return on investment.'' \667\ Moreover, the 
Commission explained that ``the opportunity for the applicants to 
propose alternative, tailored mitigation measures should allow adequate 
consideration of the effect on investment and customers.'' \668\
---------------------------------------------------------------------------

    \666\ July 8 Order, 108 FERC ] 61,026 at P 140, 154.
    \667\ Id. at P 152.
    \668\ Id. at P 154
---------------------------------------------------------------------------

    628. We will not adopt Progress Energy's request that the default 
rate be modified to include a price structure allowing pricing of 
capacity-only sales. Progress Energy fails to provide adequate 
justification to provide for such a rate in our default cost-based 
rates. For example, Progress Energy states that there is a short-term 
market for capacity-only sales but fails to explain how this market is 
a power sales market (for which our default cost-based rates apply) 
rather than an ancillary services market which is not contemplated in 
the default cost-based power sales rates. Nevertheless, as noted above, 
a mitigated seller has the opportunity to propose and justify an 
alternative to the default rate.
    629. Similarly, in response to NASUCA's request that the Commission 
require all mitigated rates and discounts to be filed under section 205 
of the FPA, we note that all mitigation proposals must be filed with 
the Commission for review. These filings are noticed and interested 
parties are given an opportunity to intervene, comment, or protest the 
submittal. With regard to discounts, as we explain in the discounting 
section of this Final Rule, discounts made to customers, like all other 
rates, are required to be reported in the seller's EQRs.
    630. We also note that the Commission stated in the April 14 Order 
that where a seller proposes to adopt the default cost-based rates (or 
where it proposes other cost-based rates), it must provide cost support 
for such rates.\669\ The Commission will examine the proposed rates on 
a case-by-case basis. With regard to sales of one week or less, where 
the seller fails to provide sufficient cost support, the Commission 
will direct the seller to submit a compliance filing to provide the 
formulas and methodology according to which it intends to calculate 
incremental costs.\670\ We note here that, to the extent a seller 
proposes a cost-based rate formula, we will require the rate formula 
used be provided for Commission review and such formula included in the 
cost-based rate tariff including formulas used in calculating 
incremental cost.
---------------------------------------------------------------------------

    \669\ April 14 Order, 107 FERC ] 61,018 at P 208. See Entergy 
Services, Inc., 115 FERC ] 61,260 at P 49 (2006) (accepting cost-
based rates based on incremental cost plus 10 percent, noting that 
filing included the formula and methodology according to which 
seller intends to calculate incremental costs).
    \670\ See, e.g., Aquila, Inc., 112 FERC ] 61,307 at P 26 (2005); 
Oklahoma Gas and Electric Co., 114 FERC ] 61,297 at P 19 (2006).
---------------------------------------------------------------------------

    631. The Commission also has set proposed default cost-based rates 
for hearing when appropriate.\671\ We believe that this case-by-case 
review of proposed default cost-based rates adequately addresses 
NRECA's and Suez/Chevron's concerns. Moreover, to the extent that an 
entity contends that a mitigated seller is flowing inappropriate costs 
through its formula rate, section 206 of the FPA provides a process for 
filing a complaint.
---------------------------------------------------------------------------

    \671\ AEP Power Marketing, Inc., 112 FERC ] 61,047 at P 28 
(2005).
---------------------------------------------------------------------------

b. Sales of More Than One Week But Less Than One Year
Commission Proposal
    632. In the NOPR, the Commission sought comment on issues related 
to the design of an ``up to'' cost-based rate. The Commission noted in 
the NOPR

[[Page 39979]]

that it has allowed significant flexibility in designing ``up to'' 
rates in the past, and invited comments on whether such flexibility is 
still warranted. In particular, the Commission noted that there are 
often disputes over which units are ``most likely to participate'' or 
``could participate'' in coordinated sales, and asked if it should 
continue to allow utilities flexibility in selecting the particular 
units that form the basis of the ``up to'' rate. If not, the Commission 
asked which units should form the basis of an ``up to'' rate, and how 
such a rate should be calculated. In addition, parties were invited to 
comment on whether a standard rate methodology should be prescribed 
that would allow a seller to avoid a hearing on this issue. The 
Commission asked whether a methodology that is based on average costs 
(both variable and embedded) would allow a seller to avoid a hearing 
because it eliminates the seller's discretion in designating particular 
units as ``likely to participate.'' The Commission also inquired as to 
whether there are other approaches that would accomplish a similar 
objective.
Comments
i. Selecting the Particular Units That Form the Basis of the ``Up to'' 
Rate
    633. Regarding whether the Commission should continue to allow 
utilities flexibility in selecting the particular units that form the 
basis of the ``up to'' rate, EEI argues for flexibility because 
selection of generating units for these short-terms sales is made with 
the goal of minimizing the cost-of-service to the utility's native load 
customers.\672\ Several commenters note that the Commission has the 
ability to verify the validity of the seller's analysis through an 
audit of the company's records to monitor transactions made under the 
``up to'' rates.\673\
---------------------------------------------------------------------------

    \672\ EEI at 30-31.
    \673\ MidAmerican at 12; Duke reply comments at 14; EEI reply 
comments at 20.
---------------------------------------------------------------------------

    634. Pinnacle asks the Commission to establish a stacking 
methodology that determines default units most likely to run while 
allowing utilities to propose a different stack based on historical 
operational sales data. Pinnacle also urges the Commission to clarify 
that the variable cost for the unit can be defined as the system 
incremental cost.\674\
---------------------------------------------------------------------------

    \674\ Pinnacle at 11.
---------------------------------------------------------------------------

    635. Other commenters raise concerns with respect to the discretion 
given to utilities to choose units used to calculate the ceiling.\675\ 
They submit that taking only a small snapshot of certain generating 
plants to develop cost-based rates will subject buyers to the 
discretion of sellers possessing market power.
---------------------------------------------------------------------------

    \675\ See, e.g., NC Towns at 4-5; NRECA at 30-32 (utilities with 
a portfolio of generation units of various vintages and operating 
characteristics could manipulate the rate ceiling and undermine 
mitigation).
---------------------------------------------------------------------------

    636. APPA/TAPS, the Carolina Agencies and AARP oppose allowing 
mitigated sellers too much flexibility in designing mitigation methods 
on the grounds that such an approach would result in market-based rates 
disguised as cost-based mitigated rates.\676\ For mid-term sales, APPA/
TAPS and AARP urge the Commission to require a well-supported analysis 
of the units most likely to provide the service.\677\
---------------------------------------------------------------------------

    \676\ APPA/TAPS at 44-45; Carolina Agencies at 24-25; AARP at 8.
    \677\ APPA/TAPS at 46; AARP at 8. Alternatively, both APPA/TAPS 
and the Carolina Agencies agree that the Commission's proposal to 
use an average embedded cost basis for mid-term sales would be 
acceptable and would avoid the need to make determinations about 
units most likely to run. APPA/TAPS at 4, 44-47; Carolina Agencies 
at 24.
---------------------------------------------------------------------------

    637. The Carolina Agencies ask the Commission to consider whether 
pricing service based on the costs of units ``likely to participate'' 
is sufficiently rigorous to meet the operative statutory standards. 
They oppose the ``units most likely to participate'' method on the 
basis that the cost and dispatch assumptions used in the underlying 
analyses are subjective and difficult to verify. The Carolina Agencies 
state that the identified ``likely to participate'' units often wind up 
being those units on the system with the highest fixed costs, 
regardless of whether the units are of a type that one might expect to 
be cycled or ramped for short-term sales. If mitigated utilities are 
allowed to continue using this method, the Carolina Agencies urge the 
Commission to develop a set of generic guidelines that will yield more 
rigorous, less subjective analyses.\678\
---------------------------------------------------------------------------

    \678\ Carolina Agencies at 24.
---------------------------------------------------------------------------

ii. Standard Default Rate Methodology To Allow a Seller To Avoid a 
Hearing
    638. With regard to whether a standard methodology should be 
prescribed that would allow a seller to avoid a hearing on rate 
methodology (e.g., a methodology that is based on average costs (both 
variable and embedded)), many commenters urge the Commission to 
continue to allow flexibility rather than imposing a standard 
methodology based on average costs.\679\
---------------------------------------------------------------------------

    \679\ See, e.g., Westar at 14; MidAmerican at 11; PPL reply 
comments at 17-18; Southern at 66-67; Duke at 10; Progress Energy at 
10-12; Xcel at 10; EEI at 30-31.
---------------------------------------------------------------------------

    639. Westar argues that the use of a standard methodology based on 
average costs would constitute a radical departure from long-settled 
Commission policy. Westar states that in Opinion No. 203, the 
Commission found that cost-based pricing cannot keep pace with 
fluctuating markets,\680\ and that imposing average cost pricing would 
only exacerbate the market inefficiencies that result under cost-based 
rate making by eliminating pricing flexibility and lowering ceiling 
rates.\681\
---------------------------------------------------------------------------

    \680\ Similarly, Southern states that the use of an ``up to'' 
rate design protects customers against unreasonably high prices (the 
purpose of mitigation in the first place), while giving mitigated 
sellers the ability to respond to pricing and market dynamics. 
Southern at 66; see also EEI reply comments at 19-20; Xcel at 10.
    \681\ Westar at 14, 23.
---------------------------------------------------------------------------

    640. Westar adds that public utilities have the statutory right 
under section 205 to propose and file their rates, and that the 
Commission lacks the power to impose rates upon public utilities.\682\ 
Westar therefore opposes standardizing cost-based rates in any manner 
that would curb a mitigated seller's section 205 discretion to select a 
pricing methodology.\683\ Westar contends that the Commission's section 
206 authority to require rate changes is limited to instances where the 
Commission finds that the utility's presumptively just and reasonable 
existing rate is unjust and unreasonable, and that the Commission's 
proposed alternative is just and reasonable.\684\ According to Westar, 
the NOPR offers no support for a finding that the wide variety of 
previously approved cost-based rate methodologies are no longer just 
and reasonable, and must be replaced with a standardized rate 
method.\685\
---------------------------------------------------------------------------

    \682\ Id. at 17-18, 23-24 (citing Atlantic City Electric Company 
v. FERC, 295 F.3d 1, 9 (D.C. Cir. 2002)).
    \683\ See Westar at 14, n.26 (claiming that an average cost 
methodology would eliminate the seller's discretion in designating 
particular units as ``likely to participate'' in cost-based sales 
and conflicts with utilities' fundamental rights under section 205 
of the FPA, and long-standing precedent under the ``units most 
likely'' methodology.)
    \684\ Id. at 18 (citing Tennessee Gas Pipeline Company v. FERC, 
860 F.2d 446, 456 (D.C. Cir. 1988)); see also id. at 23-24. See also 
MidAmerican reply comments at 22.
    \685\ Westar at 24.
---------------------------------------------------------------------------

    641. Duke and PPL support ``up to'' rates \686\ based on the 
embedded costs of

[[Page 39980]]

the units most likely to provide the service.\687\ According to Duke, 
the average costs of all units in a utility's installed generating 
capacity base could be quite different than the costs of the specific 
units most likely to participate in the short-term wholesale 
market.\688\ As such, Duke claims that a system-average cost approach 
could force the mitigated seller to charge non-native load customers 
less than the cost actually incurred for generating power whenever 
incremental costs are greater than average costs, thereby creating a 
disincentive for the mitigated seller to market wholesale power in a 
control area where it does not have market-based rate authority.\689\
---------------------------------------------------------------------------

    \686\ Drs. Broehm and Fox-Penner also support the use of an ``up 
to'' rate because it offers flexibility in conducting transactions. 
However, they suggest a methodology that reflects the incremental 
cost of new entry to encourage new investment and allow sellers a 
reasonable opportunity to earn a fair return on their investment. 
According to Drs. Broehm and Fox-Penner, the weakness of setting a 
price cap based on embedded cost stems from disputes that arise over 
which units are selected as the basis for the price cap. Because the 
cost of new entry methodology would allow the price cap to be 
formulaic and generic based on the estimate of the annualized total 
cost of building a new combustion turbine peaking facility, they 
suggest that this approach would minimize discretion in determining 
the foundation of a cost-based rate. Drs. Broehm and Fox-Penner at 
16.
    \687\ Duke at 10; Duke reply comments at 13-14; PPL reply 
comments at 17-18.
    \688\ Duke at 10; see also MidAmerican at 9-11; PPL reply 
comments at 17-18; Southern at 66-67.
    \689\ Duke at 10; Duke reply comments at 14.
---------------------------------------------------------------------------

    642. Progress Energy states that it opposes a standardized 
methodology because it will not send appropriate price signals to 
customers or appropriately compensate the seller for costs where the 
seller's generating units or the customer's usage deviates materially 
from the standardized methodology. Rather than adopting a ``units most 
likely'' approach, Progress Energy prefers a methodology that 
identifies units based on load conditions that are more closely 
associated with typical market clearing opportunities, between the 
average of monthly minimum loads and the average of monthly peak loads. 
Such an approach, Progress Energy argues, better represents conditions 
where sales occur.\690\
---------------------------------------------------------------------------

    \690\ Progress Energy at 11-12.
---------------------------------------------------------------------------

    643. While supporting flexibility in the design of up-to 
rates,\691\ Ameren urges the Commission to prescribe a standard 
methodology that sellers could opt to use to avoid prolonged and costly 
factual disputes. Ameren asserts that a formula rate based on 
information from FERC Form No. 1, where available, and incorporating 
the AEP Methodology \692\ could easily form the basis of such a 
standard methodology.\693\
---------------------------------------------------------------------------

    \691\ Ameren maintains that allowing mitigated sellers to sell 
at cost-based ``up to'' rates from which the seller may discount 
adequately mitigates the seller's market power while still allowing 
that entity to participate in competitive markets. Ameren states 
that ``up to'' rates thus can benefit customers by resulting in a 
more robust market. Ameren at 15.
    \692\ American Electric Power Company, 88 FERC ] 61,141 at 
61,453-54 (1999). Under this methodology, Ameren explains that a 
seller must develop a cost-based annual rate, which then is divided 
by 52 to derive a weekly rate, which then is divided by 5 to derive 
a daily peak rate, which then is divided by 16 to derive an hourly 
peak rate. Ameren at 15.
    \693\ Ameren at 16.
---------------------------------------------------------------------------

    644. Because of concerns with regard to the discretion given to 
sellers to choose units used to calculate the cost-based rate, the NC 
Towns assert that a standard, system-average ratemaking methodology 
would provide a certainty beneficial to both utilities and wholesale 
customers, as well as help reduce protracted negotiations and 
litigation surrounding parties' concepts of a cost-based rate.\694\
---------------------------------------------------------------------------

    \694\ NC Towns at 4-5.
---------------------------------------------------------------------------

    645. For mid-term sales that carry a capacity charge, the Carolina 
Agencies contend that charge should be based on the utility's fully 
allocated system-wide cost of capacity. The Carolina Agencies state 
that energy associated with the purchased capacity also should be 
priced on a system average basis, in order to adhere to the principle 
that capacity and energy charges be developed on a consistent 
basis.\695\ For these mid-term sales, the Carolina Agencies also 
support giving Load Serving Entities (LSEs) located within the 
mitigated utility's control area an option between: (1) Locking-in 
their price for capacity and/or energy in advance of delivery, at the 
mitigated utility's forecasted cost of energy and its cost-based tariff 
rate for capacity; or (2) having their charges determined through a 
formula rate that would charge purchasers an annually-updated price 
reflecting the utility's actual system-wide average costs.\696\
---------------------------------------------------------------------------

    \695\ Carolina Agencies at 11; see also APPA/TAPS at 46-47, n.50 
(citing Florida Power & Light Co., 66 FERC ] 61,227 at 61,532 
(1994)).
    \696\ Carolina Agencies at 11.
---------------------------------------------------------------------------

    646. The Carolina Agencies add that any change in the Commission's 
pricing policy that would yield more reasonable cost-based rates must 
be coupled with a ``must-offer'' requirement. Lower cost-based rates 
without a concurrent ``must-offer'' requirement, they argue, will only 
provide the mitigated utility with an even greater incentive to sell 
all its available power beyond the mitigated region, thereby 
exacerbating the problems of depleted supply and profiteering by 
remaining suppliers.\697\
---------------------------------------------------------------------------

    \697\ Carolina Agencies at 25.
---------------------------------------------------------------------------

    647. For mid-term sales, NRECA asks the Commission to enforce a 
matching or consistency principle. Here, NRECA advocates using the same 
generating units ``as the basis for the fixed and variable costs in 
determining the default embedded-cost rate. In no case should a seller 
be allowed to mix high-fixed-cost units with high-variable-cost units 
to artificially inflate the embedded-cost rate. If a seller can show 
that a portfolio of generating units is likely to be used to provide 
service, then the seller might be permitted to use a weighted average 
of the fixed and variable costs of the portfolio.'' \698\
---------------------------------------------------------------------------

    \698\ NRECA at 32.
---------------------------------------------------------------------------

Commission Determination
    648. Under the Commission's current policy, the default mitigation 
rate for mid-term sales (sales of more than one week but less than one 
year) is priced at an embedded cost ``up to'' rate reflecting the costs 
of the unit(s) expected to provide the service. The Commission will 
retain this approach as the default mitigation for mid-term sales. As 
is the case with sales for one week or less, sellers may choose to 
adopt the default cost-based rate or propose alternative cost-based 
rates.
Selecting the Particular Units That Form the Basis of the ``Up to'' 
Rate
    649. When a seller adopts the default cost-based mid-term rate or 
otherwise proposes a cost-based rate designed on the unit or units 
expected to run, the Commission will continue to allow the seller 
flexibility in selecting the particular units that form the basis of 
the ``up to'' rate. Entities that included various proposals for ``up 
to'' cost-based rate methodologies in their comments may propose those 
or other methodologies as alternatives to the default cost-based rates, 
and the Commission will consider any such proposal on a case-by-case 
basis. Any seller proposing an alternative mitigation methodology, 
including a cost-based methodology with demand or capacity charges, 
carries the burden of justifying its proposal.
    650. We agree with commenters that the Commission has the ability 
to verify the validity of the seller's analysis and will continue to do 
so in our review of proposed cost-based rates. We will continue to 
conduct our own analysis of whether a proposed cost-based rate is just 
and reasonable and, if warranted, will set such a proposed rate for 
evidentiary hearing where there are issues of material fact.
    651. In response to the concerns raised by some commenters 
regarding the discretion given to sellers in the design of ``up-to'' 
rates, as noted above, the Commission considers all evidence when 
reviewing a cost-based rate proposal and, if a company has not 
justified selection of certain generating

[[Page 39981]]

units, we will not accept the proposed rate. Under the FPA, we have the 
authority to accept, reject, or modify a proposed rate based on an 
analysis of the specific facts and circumstances.
    652. Further, we find that the approach we adopt in this regard 
allowing sellers flexibility in designing ``up to'' rates for purposes 
of mitigation, subject to Commission review and approval, is consistent 
with the Commission's historical approach to the pricing of cost-based 
rates. Because the Commission will have the opportunity to review a 
seller's proposed ``up to'' rates, we find that allowing mitigated 
sellers flexibility in choosing which units are used to calculate the 
proposed cost-based rate will not result in market-based rates being 
disguised as cost-based mitigated rates.
    653. In response to Pinnacle's suggestion that the Commission make 
available a stacking methodology to be used to determine which units 
are most likely to run, we will do so for informational purposes and 
will make the methodology available on the FERC Internet site. We also 
note, however, that sellers may propose to use their own stacking 
methodology.
    654. With regard to the Carolina Agencies' question of whether 
pricing service based on the costs of units ``likely to participate'' 
is sufficiently rigorous to meet the operative statutory standards, we 
find that it is. Historically, the Commission has allowed such an 
approach and the Carolina Agencies have failed to convince us that, 
whether or not the underlying analysis is difficult to verify, the 
approach does not result in just and reasonable rates. In addition, 
with regard to Carolina Agencies' position with regard to a ``must-
offer'' provision, we discuss proposals for a ``must-offer'' provision 
below in the section on protecting mitigated markets.
Standard Default Rate Methodology To Allow a Seller To Avoid a Hearing
    655. Regarding a standard default rate methodology that would allow 
a seller to avoid a hearing on rate methodology (e.g., a methodology 
that is based on average costs (both variable and embedded)), we note 
that the Commission has approved various rate methodologies in the 
past. Rather than adopting a specific default rate methodology in this 
Final Rule, we affirm that, to the extent the Commission has previously 
accepted a particular rate methodology, that methodology is presumed to 
be just and reasonable until the Commission makes a contrary 
finding.\699\
---------------------------------------------------------------------------

    \699\ In response to Westar, as discussed herein, Commission 
precedent supports flexibility in designing cost-based rates and we 
are not proposing to standardize cost-based rates here. Upon loss or 
surrender of market-based rate authority a seller has a number of 
options on how to make wholesale power sales. It can revert to a 
cost-based rate tariff on file with the Commission, file a new 
proposed cost-based rate tariff, or propose other mitigation. While 
we provide a default cost-based rate methodology, we also allow a 
seller to submit its own cost-based mitigation. On this basis, a 
seller's filing rights under section 205 of the FPA are not eroded 
and we are not finding methodologies different from the default 
methodology necessarily to be unjust and unreasonable.
---------------------------------------------------------------------------

    656. The Commission will continue to allow sellers flexibility in 
designing ``up to'' cost-based rate proposals as alternatives to the 
default methodology. Entities that included various proposals for ``up 
to'' cost-based rate methodologies in their comments may propose those 
or other methodologies as alternatives to the default cost-based rates, 
and the Commission will consider any such proposal on a case-by-case 
basis.\700\ Any seller proposing an alternative mitigation methodology 
carries the burden of justifying its proposal.
---------------------------------------------------------------------------

    \700\ In response to Pinnacle's request for clarification that 
the variable cost for the unit can be defined as the system 
incremental cost, a mitigated seller can make that argument in 
support of an alternative cost-based mitigation methodology.
---------------------------------------------------------------------------

    657. We acknowledge that a standard default rate methodology may 
provide, as several commenters suggest, some level of certainty and 
avoid prolonged factual disputes. However, we are persuaded by the 
concerns expressed by others that designing a standard default rate 
methodology based, for example, on average costs may not account for 
the actual costs of the units making the sales, and thus may not allow 
the seller to recover its costs.
c. Sales of One Year or Greater
Comments
    658. While the NOPR did not propose changes to the default pricing 
for long-term sales (sales of one year or more), several entities filed 
comments on that issue. APPA/TAPS and AARP reiterate their support for 
pricing such sales on an embedded cost basis.\701\ They submit that the 
Commission should not depart from its default cost-based mitigation 
policy with regard to long-term sales. The NC Towns also favor using 
system average costs in a rate base, rate of return model for 
determining long term cost-based rates.\702\ Similarly, the Carolina 
Agencies assert that long-term sales to embedded LSEs should be priced 
at the mitigated utility's fully allocated average embedded cost of 
capacity and system average energy costs. As with short-term sales, the 
Carolina Agencies urge the Commission to allow the embedded LSEs the 
choice between: (1) Locking-in their price at the mitigated utility's 
embedded cost rates; or (2) agreeing to have their charges determined 
through an annually updated formula rate that reflects the utility's 
actual system-wide average costs.\703\
---------------------------------------------------------------------------

    \701\ APPA/TAPS at 47; AARP at 8.
    \702\ NC Towns at 4.
    \703\ Carolina Agencies at 12-13.
---------------------------------------------------------------------------

Commission Determination
    659. We will retain our existing policy for sales of one year or 
more (long-term) sales. Specifically, we will continue to require 
mitigated sellers to price long-term sales on an embedded cost of 
service basis and to file each such contract with the Commission for 
review and approval prior to the commencement of service.\704\ We 
discuss below the Carolina Agencies' request for a ``must offer'' 
requirement.
---------------------------------------------------------------------------

    \704\ April 14 Order, 107 FERC ] 61,018 at P 151, 155.
---------------------------------------------------------------------------

d. Alternative Methods of Mitigation
Commission Proposal
    660. In the NOPR, the Commission noted that sellers that are found 
to have market power (i.e., after the Commission has ruled on a DPT 
analysis), or that accept a presumption of market power, can either 
accept the Commission's default cost-based mitigation measures or 
propose alternative methods of mitigation. With regard to alternative 
methods of mitigation, the Commission asked in the NOPR whether it 
should allow as a means of mitigating market power the use of 
agreements that are not tied to the cost of any particular seller but 
rather to a group of sellers. The Commission asked whether the use of 
such agreements as a mitigation measure would satisfy the just and 
reasonable standard of the FPA.
Comments
    661. Many commenters favor allowing alternative mitigation methods 
tied to the costs of a group of sellers, in particular the Western 
Systems Power Pool Agreement (WSPP Agreement),\705\ or transparent 
competitive market prices in regional markets. Xcel asserts that the 
FPA does not require a mitigated rate to reflect a utility's own cost-
of-service.\706\
---------------------------------------------------------------------------

    \705\ Westar at 26-27; Pinnacle at 10; Ameren at 16-17; PG&E at 
22; MidAmerican at 12; Xcel at 8; PPL reply comments at 18; and PNM/
Tucson reply comments at 2-3.
    \706\ Xcel reply comments at 7.
---------------------------------------------------------------------------

    662. E.ON U.S. supports mitigation that sets prices at competitive 
market

[[Page 39982]]

levels. It claims that cost-based rate mitigation eliminates the 
potential for new competition in a mitigated area. In this regard, E.ON 
U.S. argues that profits are available only when market prices are 
below the mitigated utility's cost-based rates, which reduces the 
incentive for investment in new generation as long as buyers can obtain 
below market-price energy from generation facilities of the mitigated 
utility's ratepayers.\707\ E.ON U.S. adds that mitigation reflective of 
competitive prices results in mitigated sellers that are indifferent as 
to the buyer's location and competitive price signals to which buyers 
can respond accordingly.\708\
---------------------------------------------------------------------------

    \707\ E.ON U.S. reply comments at 3; see also EPSA at 13.
    \708\ E.ON U.S. reply comments at 3.
---------------------------------------------------------------------------

Use of the WSPP Agreement Rate To Mitigate Market Power
    663. Several entities suggest that the rates under the WSPP 
Agreement may be an appropriate alternative mitigation method.\709\ 
Westar asserts that the purpose of the cost-based rate schedules under 
the WSPP Agreement is to mitigate perceived market power,\710\ and 
notes that the Commission has also accepted use of the WSPP Agreement 
to mitigate market power in various contexts.\711\ Westar contends that 
parties to the WSPP Agreement may sell under the cost-based rate 
schedules of the WSPP Agreement regardless of whether they have a 
separate tariff and authorization from the Commission.\712\ Thus, 
Westar claims that the NOPR's implicit question whether additional 
authorization is needed to make mitigated sales is misplaced since the 
WSPP Agreement, as an accepted tariff/rate schedule, establishes the 
lawful filed rate.
---------------------------------------------------------------------------

    \709\ See, e.g., Westar at 26 (``The Commission developed and 
approved the rates under Schedules A and C of the WSPP Agreement as 
`rates that are within the zone of reasonableness and that are just 
and reasonable under the [Federal Power Act]''' (citing Western 
Systems Power Pool, 55 FERC ] 61,099, at 61,321 (WSPP), order on 
reh'g, Western Systems Power Pool, 55 FERC ] 61,495 (1990), aff'd in 
relevant part and remanded in part sub nom. Environmental Action and 
Consumer Federation of America v. FERC, 996 F.2d 401 (D.C. Cir. 
1992), order on remand, 66 FERC ] 61,201 (1994)); Pinnacle at 10; 
PG&E at 22.
    \710\ Westar at 26 (citing Pacific Gas and Electric Company, 38 
FERC ] 61,242 (1987) (accepting WSPP Agreement on experimental 
basis); Pacific Gas and Electric Company, 50 FERC ] 61,339 (1990) 
(reducing the ceiling price on economy energy and capacity service 
under Schedules A, B and C from $245/MWh to $124/MWh); WSPP; Western 
Systems Power Pool, 83 FERC ] 61,099 (1998) (order accepting 
amendments); Western Systems Power Pool, 85 FERC ] 61,363 (1998) 
(Letter Order accepting revised WSPP Agreement); Western Systems 
Power Pool, Inc., 95 FERC ] 61,483 (2001) (order accepting 
amendments)).
    \711\ Id. (citing, among other cases, Western Resources, Inc., 
94 FERC ] 61,050, at 61,247 (2001) (accepting WSPP Agreement to 
mitigate potential affiliate preference concerns between prospective 
merger partners)).
    \712\ Id. at 27 (citing NorthPoint Energy Solutions, Inc., 107 
FERC ] 61,181 (2004) (rejecting wholesale cost-based rate tariff as 
unnecessary in light of seller's intent to make sales under the WSPP 
Agreement)).
---------------------------------------------------------------------------

    664. Pinnacle notes that the WSPP Agreement's price caps were 
established based on a system-wide average cost and serve to put 
entities without market-based rate authority on a similar footing. In 
Pinnacle's view, such agreements enhance liquidity in the regional 
markets and facilitate transactions due to the commonality of terms and 
conditions.\713\
---------------------------------------------------------------------------

    \713\ Pinnacle at 10.
---------------------------------------------------------------------------

    665. PG&E adds that the WSPP Agreement is the most commonly used 
standardized power sales contract in the electric industry. PG&E states 
that the WSPP membership continuously updates the WSPP Agreement to 
ensure that it represents up-to-date terms for power sales contracts 
and notes that the process of updating its terms involves a 
diversified, experienced group of market participants focused on 
developing an appropriate rate for short-term sales. PG&E concludes 
that the terms of the WSPP tariff should be an accepted alternative 
rate to the default rate determined by the Commission.\714\
---------------------------------------------------------------------------

    \714\ PG&E at 22.
---------------------------------------------------------------------------

    666. In contrast, APPA/TAPS and AARP oppose alternative mitigation 
methods tied to the costs of a group of sellers because there is no 
assurance that the group rate would reflect the costs of the seller 
subject to mitigation.\715\ Further, APPA/TAPS have concerns that 
selecting the appropriate group and obtaining the necessary cost 
information could be extremely difficult and controversial.\716\
---------------------------------------------------------------------------

    \715\ APPA/TAPS at 47; AARP at 8.
    \716\ APPA/TAPS at 41.
---------------------------------------------------------------------------

Commission Determination
    667. We will address on a case-by-case basis whether the use of an 
agreement that is not tied to the cost of any particular seller but 
rather to a group of sellers is an appropriate mitigation measure.
    668. With regard to the WSPP Agreement, as discussed below, we 
conclude that use of the WSPP Agreement may be unjust, unreasonable or 
unduly discriminatory or preferential for certain sellers. Therefore, 
in an order being issued concurrently with this Final Rule, the 
Commission is instituting a proceeding under section 206 of the FPA to 
investigate whether, for sellers found to have market power or presumed 
to have market power in a particular market, the WSPP Agreement rate 
for coordination energy sales is just and reasonable in such market.
    669. The WSPP Agreement was initially accepted by the Commission on 
a non-experimental basis in 1991,\717\ providing for flexible pricing 
for coordination sales and transmission services. Currently, there are 
over 300 members of the WSPP Agreement located from coast to coast in 
the United States and Canada, including private, public and 
governmental entities, financial institutions and aggregators, and 
wholesale and retail customers. The WSPP Agreement as it exists today 
permits sellers of electric energy to charge either an uncapped market-
based rate (for public utility sellers, they must have obtained 
separate market-based rate authorization from the Commission to do 
this), or an ``up to'' cost-based ceiling rate. For sellers without 
market-based rate authority, the cost-based ceiling rate under the WSPP 
Agreement consists of an individual seller's forecasted incremental 
cost plus an ``up-to'' demand charge based on the costs of a sub-set 
(eighteen sellers) of the original WSPP Agreement members, not 
necessarily the costs of any one seller. The up-to demand charge is 
based on the average fixed costs of the generating facilities of that 
sub-set of WSPP Agreement members; it was designed to reflect the costs 
of a hypothetical average utility member in 1989. The only limitations 
are: (1) That the trades by Commission-regulated public utilities must 
be short-term (lasting one year or less), and (2) that they be priced 
at or below the ceilings for sellers without market-based rate 
authority.
---------------------------------------------------------------------------

    \717\ WSPP, 55 FERC ] 61,099 (1991). Prior to 1991, the WSPP 
Agreement was used for three years on an experimental basis. See 
Western Sys. Power Pool, 50 FERC ] 61,339 (1990) (extending the 
initial two-year period for an additional year).
---------------------------------------------------------------------------

    670. In a number of recent orders, the Commission accepted the use 
of the WSPP Agreement as a mitigation measure subject to the outcome of 
the instant proceeding and any determinations that the Commission makes 
regarding mitigation in this proceeding. In those cases, we explained 
that the WSPP Agreement contains a Commission-approved cost-based rate 
schedule that has been found to be just and reasonable. Further, we 
noted that parties to the WSPP Agreement have ``the option of 
transacting under the WSPP Agreement and thus can make sales under the 
WSPP Agreement without any further authorization from the Commission.'' 
\718\
---------------------------------------------------------------------------

    \718\ Westar Energy, Inc., 116 FERC ] 61,219 at P 33 (2006); The 
Empire Dist. Elec. Co., 116 FERC ] 61,150 at P 12 (2006); Xcel 
Energy Services, Inc., 117 FERC ] 61,180 at P 49 (2006). However, we 
note that a review of EQR data indicates that of 65 sellers 
reporting contracts under the WSPP Agreement, 56 sellers reported 
sales under that agreement in 2006. Fifty-five of these sellers 
reported sales that were identified as market-based rate sales.

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

[[Page 39983]]

    671. Though the Commission has allowed sellers to charge flexible 
cost-based ceiling rates that are not necessarily based on a particular 
seller's own costs (such as the WSPP Agreement ceiling rate), we are 
concerned that the evolution and use of the WSPP Agreement ceiling rate 
and the evolution of competitive markets have resulted in circumstances 
in which the WSPP rate may no longer be just and reasonable for sellers 
that are found to have market power or are presumed to have market 
power in a particular market, i.e., sellers under the WSPP Agreement 
that do not have market-based rate authority or that lose or relinquish 
market-based rate authority.
    672. We recognize that the ceiling rate under the WSPP Agreement 
has been found to be a just and reasonable cost-based rate by this 
Commission as well as by the U.S. Court of Appeals for the D.C. 
Circuit,\719\ and that it has been in use for over 15 years by sellers 
irrespective of whether they have market power. Nevertheless, the WSPP 
Agreement ceiling rate contains extensive pricing flexibility and 
relies in part on market forces to set the rate at or below the demand 
charge cap, and we believe the WSPP Agreement rate needs to be 
revisited in light of its widespread use and changes in electric 
markets since 1991. When originally approved by the Commission in 1991, 
there were 40 members under the WSPP Agreement; now there are over 300 
members. Additionally, the WSPP Agreement is now used by entities not 
only in the Western Interconnection, but throughout the continental 
United States. Further, the demand charge component of the WSPP 
Agreement ceiling rate is based on the costs of only 18 of the original 
WSPP members in 1991 (utilizing 1989 data) and does not reflect the 
costs of the members that joined the agreement since 1991.
---------------------------------------------------------------------------

    \719\ Environmental Action and Consumer Federation of America v. 
FERC, 996 F.2d 401 (D.C. Cir. 1993).
---------------------------------------------------------------------------

    673. For these reasons, concurrently with issuance of this Final 
Rule, we are instituting in Docket No. EL07-69-000 a proceeding under 
section 206 of the FPA to investigate whether the WSPP Agreement 
ceiling rate is just and reasonable for a public utility seller in a 
market in which such seller has been found to have market power or is 
presumed to have market power. All interested entities will have an 
opportunity to address this issue through a paper hearing.
    674. As noted above, the Commission has accepted, subject to the 
outcome of this rulemaking proceeding, the use of the WSPP Agreement 
ceiling rate as mitigation by a number of sellers. These sellers may 
continue to use the WSPP Agreement ceiling rate as mitigation, subject 
to refund (and the refund effective date established in Docket No. 
EL07-69-000) and subject to the outcome of the section 206 proceeding.
Market-Based Proposals for Mitigation
Comments
    675. Commenters are generally concerned that where the Commission's 
current mitigation approach focuses on a seller's own cost of service, 
it imposes cost-based rates on a mitigated utility in the home control 
area regardless of whether the prices of alternative sources of supply 
in the mitigated market exceed the mitigated seller's cost-based 
rates.\720\ Rather than relying on cost-based price caps that may bear 
no relationship to market conditions, several commenters support 
allowing mitigation methods based on transparent competitive market 
prices in regional markets.\721\ Commenters suggest various market 
indicia that the Commission could use as price proxies in market-based 
mitigation alternatives.\722\
---------------------------------------------------------------------------

    \720\ See, e.g., Xcel at 7-9.
    \721\ Duke at 3, 13-14; Drs. Broehm and Fox-Penner at 16-17; 
MidAmerican at 12-13; E.ON U.S. at 10-12; Southern at 65, n. 104, 
66; Ameren at 14; Xcel at 8-9; PNM/Tucson at 12,14; EEI at 26-29; 
Dr. Pace at 23; PPL reply comments at 17-18; and Oregon Commission 
reply comments at 2-3.
    \722\ For example, Duke (prices from an adjoining LMP market 
that are transparent and contemporaneously available); MidAmerican 
(reference prices for the region or from neighboring LMP markets, 
published index prices reported by public subscription services, or 
prices capped at levels reported in the Commission's Electric 
Quarterly Report for sales in neighboring markets); Xcel (proximate 
price indexes where available, the WSPP Agreement, a utility's own 
sales in areas where it does not possess market power, competitive 
solicitations with a sufficient amount of bidders or opportunity 
cost pricing); EEI (published index prices at liquid regional 
trading hubs or LMP nodal prices for adjacent Day 2 RTOs); the 
Oregon Commission (price at a frequently traded energy hub or an LMP 
determined by an adjoining RTO would be appropriate price indexes). 
If an appropriate and valid price index is not available, the Oregon 
Commission would require the seller to make mitigated sales at cost-
based rates.
---------------------------------------------------------------------------

    676. Because different markets may be uncompetitive for different 
reasons, and the same mitigation measure is not necessarily equivalent 
in all situations, several commenters urge the Commission to consider 
more tailored, market-based rate approaches to mitigation on a case-by-
case basis.\723\ MidAmerican suggests that any specific index chosen 
could be reflected in the tariff of mitigated sellers (for sales up to 
one year) or in agreements filed with the Commission (for sales of one 
year or longer).\724\
---------------------------------------------------------------------------

    \723\ MidAmerican at 14; NYISO at 8; Duke at 13-14; Drs. Broehm 
and Fox-Penner at 15.
    \724\ MidAmerican reply comments at 5.
---------------------------------------------------------------------------

    677. Duke explains that market-based rate mitigation alternatives 
could be applied to mitigated sellers whose control area markets are 
adjacent to a Commission-approved market. If the proxy prices are 
established in markets that the Commission has found to be functionally 
competitive, Duke contends that the price will by definition be just 
and reasonable. Duke submits that the Commission approved similar 
mitigation for sales by the LG&E Parties sinking in the Big Rivers 
control area capped at the Midwest ISO's LMP at the Big Rivers control 
area interface.\725\
---------------------------------------------------------------------------

    \725\ Duke at 14 (citing LG&E Energy Marketing Inc., 113 FERC ] 
61,229 at P 30 (2005)).
---------------------------------------------------------------------------

    678. E.ON U.S. argues that allowing index-based price caps as a 
mitigation option is just and reasonable because such sales are either 
subject to the market monitoring provisions of an RTO, or in the case 
of price indices, are structured according to the Commission's 
instructions with regard to market price reporting. They add that 
index-based price caps are efficient because: (a) They can be used to 
address pricing requirements for varying time commitments; (b) they 
meet the Commission's criteria for accurate and timely reporting; and 
(c) they do not require the administrative overhead and complexity 
associated with calculating and reporting cost-based rates.\726 \
---------------------------------------------------------------------------

    \726\ E.ON U.S. at 12.
---------------------------------------------------------------------------

    679. MidAmerican and the Oregon Commission submit that using an 
appropriate price index as a proxy could ensure that prices are derived 
from competitive conditions and do not reflect the market power of the 
mitigated seller (or, for that matter, of any seller).\727\ Duke, 
MidAmerican, and the Oregon Commission reason that allowing a published 
price index would effectively make the mitigated seller a price taker 
rather than a price setter.\728\ E.ON U.S., PNM/Tucson, and 
Indianapolis P&L also suggest that requiring cost-based mitigation may 
result in sellers giving up their market-based rate authority in 
mitigated areas

[[Page 39984]]

due to the significant time and expense of developing a cost-of-service 
filing.\729\ Where sellers opt to give up market-based rate authority, 
these commenters conclude that buyers will be harmed by a reduction in 
the number of competitive options available to them in mitigated 
markets.
---------------------------------------------------------------------------

    \727\ MidAmerican at 13; Oregon Commission reply comments at 2; 
see also PPL reply comments at 17-18.
    \728\ Duke at 14; MidAmerican at 13-14; Oregon Commission reply 
comments at 2.
    \729\ Indianapolis P&L at 11; E.ON U.S. at 11; PNM/Tucson at 13.
---------------------------------------------------------------------------

    680. MidAmerican claims that using price indices would (a) 
Eliminate the incentive for round-trip transactions; (b) alleviate the 
need to determine whether the need for mitigation should be based on 
the point of delivery, the sink location, or some other determinant; 
and (c) reduce contention over how to calculate cost-based rates.\730\ 
EEI and the Oregon Commission conclude that allowing mitigated rates to 
be based on competitive market prices would: (1) Maintain supply 
choices for captive customers by encouraging mitigated suppliers to 
participate actively in the mitigated markets; (2) avoid the unintended 
consequences of cost-based rate mitigation (e.g., incentive to sell 
outside the mitigated region); (3) help to ensure that buyers continue 
to receive accurate price signals and not inappropriately lean on cost-
based rates in times of peak demand; and (4) be consistent with the 
Commission's goal of encouraging competitive market solutions.\731\
---------------------------------------------------------------------------

    \730\ MidAmerican reply comments at 3-4, 20.
    \731\ EEI reply comments at 12; Oregon Commission reply comments 
at 3.
---------------------------------------------------------------------------

    681. APPA/TAPS reject this reasoning, arguing that a dominant 
supplier has other incentives not to sell to captive customers beyond 
just the availability of a higher price elsewhere, including the desire 
to disadvantage competing suppliers within its control area. Therefore, 
even if a market price index is used as a mitigation alternative, APPA/
TAPS submit that a ``must offer'' obligation remains necessary.\732\
---------------------------------------------------------------------------

    \732\ APPA/TAPS reply comments at 15.
---------------------------------------------------------------------------

    682. According to some commenters, capping mitigated prices at the 
levels of relevant price indices would also reduce the market 
distortions that exist under dual price systems.\733\ E.ON U.S., Xcel, 
PNM/Tucson, Duke, EEI, MidAmerican and the Oregon Commission generally 
contend that allowing market-based rate mitigation methods would reduce 
the incentive, arising from price disparities in dual-price systems (a 
regime where a seller has market-based rate authority in some markets 
but is limited to cost-based sales in other market(s)), for mitigated 
sellers to seek market-based rate sales beyond the mitigated 
market.\734\ This, in turn, would obviate the need for a ``must offer'' 
requirement or mitigation of sales outside the mitigated region. 
Somewhat similarly, EEI warns that if the Commission implements a 
``must offer'' obligation, suppliers may not apply for market-based 
rate authorization in markets where they are likely to fail any of the 
market power screens.\735\
---------------------------------------------------------------------------

    \733\ PNM/Tuscon at 13-14; MidAmerican at 14; EEI at 26; see 
also, CAISO at 6.
    \734\ E.ON U.S. at 10-11; Xcel at 8-9; PNM/Tucson at 13; Duke at 
9; EEI at 28; MidAmerican at 14; Oregon Commission reply comments at 
3.
    \735\ EEI reply comments at 18.
---------------------------------------------------------------------------

    683. Some commenters add that the Commission surrenders nothing in 
terms of consumer protection by allowing market-based price caps as a 
mitigation option. In their view, permitting such mitigation will 
likely increase the willingness of sellers to engage in market 
transactions in mitigated areas and result in buyers paying no more 
than what is already recognized as a just and reasonable competitive 
market price.\736\
---------------------------------------------------------------------------

    \736\ Duke at 14; APPA/TAPS at 64; MidAmerican at 13.
---------------------------------------------------------------------------

    684. MidAmerican, E.ON U.S., PNM/Tucson, and Indianapolis P&L all 
note that the Commission (1) Has found that inter-affiliate sales are 
permissible at RTO price indices, and (2) proposes in the NOPR (at P 
113-14) to extend this policy to market indices satisfying the November 
19 Price Index Order.\737\ These commenters argue that if sales at a 
meaningful market index are per se just and reasonable for affiliate 
transactions, there is no reason why such sales are not per se just and 
reasonable for non-affiliate transactions.\738\ PNM/Tucson add that 
even in regions without organized RTO/ISO markets, sellers with market-
based rate authority have established highly liquid trading hubs (e.g., 
Four Corners or Palo Verde) that also produce market prices that are 
readily available, transparent, can serve as an appropriate proxy, and 
satisfy the Commission's index pricing standards.\739\
---------------------------------------------------------------------------

    \737\ MidAmerican at 13; E.ON U.S. at 11; PNM/Tucson at 12; 
Indianapolis P&L at 7.
    \738\ E.ON U.S. at 11; Indianapolis P&L at 11; MidAmerican reply 
comments at 5.
    \739\ PNM/Tucson at 13.
---------------------------------------------------------------------------

    685. Another commenter supports the adoption of more market-
oriented approaches to mitigation. For daily and hourly transactions, 
this commenter asks the Commission to be receptive to rates tied to an 
acceptable price index at a liquid trading point. For long term 
transactions, rather than focusing on average embedded costs, which 
this commenter claims are likely to be a poor proxy for market rates, 
the Commission should consider capacity and associated energy rates 
that provide a competitive rate of return on new generation units built 
in the region. Where transmission constraints bind only occasionally 
and the seller does not have market power absent such constraints, this 
commenter reasons that it is rational to only apply mitigated rates to 
sales made at the time such constraints are binding. Similarly, where 
indicative screens or the DPT analysis point to the existence of a 
market power problem in a well-defined seasonal or peak period, this 
commenter favors confining rate mitigation to sales made in the 
relevant market during that period.\740\
---------------------------------------------------------------------------

    \740\ Dr. Pace at 23-24.
---------------------------------------------------------------------------

    686. APPA/TAPS acknowledge that cost-based rates do not achieve 
competitive wholesale markets.\741\ Ideally, wholesale customers should 
have a meaningful choice of suppliers whose costs are disciplined by 
competitive forces and remedies focused on fostering structurally 
competitive markets will help to ensure that future consumers have 
choices. Until such structural remedies are fully implemented, APPA/
TAPS maintain that mitigated sellers should sell at cost-based 
rates.\742\
---------------------------------------------------------------------------

    \741\ APPA/TAPS at 48.
    \742\ Id. at 48-49.
---------------------------------------------------------------------------

    687. APPA/TAPS and Morgan Stanley do not categorically oppose the 
use of price indices as a mitigation alternative that could be 
justified with substantial evidence, but urge caution and ask the 
Commission not to assume that the index relied upon is a just and 
reasonable, and comparable, proxy for the mitigated market.\743\ Morgan 
Stanley explains that given the price variation among transmission 
nodes, it is not possible to generically find that any one index-based 
price would be an adequate proxy for another node(s). APPA/TAPS explain 
that a thinly traded market, or one separated by transmission 
constraints, could create volatility or arbitrage possibilities that 
would leave captive customers worse-off than a cost-based mitigated 
rate. They add that appropriate price proxies may not be available for 
all products, and that RTO-administered real-time or day-ahead markets 
would not generally provide acceptable proxies for price mitigation in 
markets for weekly, monthly or annual sales. APPA/TAPS also note that 
the Southeast has no real liquid trading hubs.\744\ While urging the 
Commission to continue requiring cost-based mitigation, Morgan Stanley 
does not oppose allowing mitigated sellers to

[[Page 39985]]

justify an index-based mitigation approach as appropriate for their 
specific circumstances. According to Morgan Stanley, such an approach 
may prove justifiable where a viable, liquid index exists within or 
adjacent to the territory in which a finding of market power 
exists.\745\
---------------------------------------------------------------------------

    \743\ APPA/TAPS reply comments at 13; Morgan Stanley reply 
comments at 2, 8-10.
    \744\ APPA/TAPS reply comments at 14-15.
    \745\ Morgan Stanley reply comments at 9-10.
---------------------------------------------------------------------------

    688. NRECA likewise is concerned that there is no assurance that 
(1) The external market price would be a competitive price; (2) 
external markets are a reasonable proxy for non-existent competitive 
market prices in the mitigated market; and (3) there are sufficient 
monitoring and enforcement mechanisms to ensure these first two 
conditions are continually being met.\746\ Unless these three concerns 
are addressed, NRECA asserts that the Commission may not lawfully rely 
on an external market price as a proxy in a mitigated market, 
particularly where the FPA is clear that the Commission may not approve 
market-based rates absent ``empirical proof'' that ``existing 
competition would ensure that the actual price is just and 
reasonable.''\747\ Moreover, where ``Congress could not have assumed 
that `just and reasonable' rates could conclusively be determined by 
reference to market price,'' \748\ NRECA argues that the Commission may 
not rely exclusively on market prices but rather must have a regulatory 
``escape hatch'' or ``safeguard'' mechanism \749\ if actual competitive 
pressures alone cannot keep rates just and reasonable. NRECA, similar 
to APPA/TAPS, is concerned that proxy indices are irrelevant oftentimes 
because they are too far removed from the mitigated market to be 
adequately representative. While NRECA admits that such indices may be 
adequate in some instances, it takes the position that, at most, the 
Commission could entertain proxy index proposals from mitigated sellers 
on a case-by-case basis.\750\
---------------------------------------------------------------------------

    \746\ NRECA reply comments at 31-33.
    \747\ Id. at 32 (quoting Farmers Union Cent. Exch., Inc. v. 
FERC, 734 F.2d 1486, 1510 (D.C. Cir. 1984)).
    \748\ Id. (quoting FPC v. Texaco, 417 U.S. 380, 399 (1974)).
    \749\ Id. (quoting Louisiana Energy & Power Auth. v. FERC, 141 
F.3d 364, 370-71 (D.C. Cir. 1998)).
    \750\ Id. at 33.
---------------------------------------------------------------------------

    689. The Carolina Agencies are similarly concerned that market-
based indices based on LMPs from adjacent markets in many hours will 
reflect transmission congestion that may not be representative of 
congestion patterns in the mitigated market, and therefore must not be 
deemed a just and reasonable proxy for an entirely different market. 
Moreover, LSEs in RTOs with Day 2 markets have some ability to limit 
their exposure to LMP spikes through the use of hedging tools (i.e. 
Auction Revenue Rights and Financial Transmission Rights). However, the 
Carolina Agencies argue, LSEs in mitigated markets would face these LMP 
gyrations from adjacent markets as proxy prices without any hedging 
protections. These agencies further claim that there are no other 
sources of non-LMP price information in their region that are reliable 
enough to serve as proxy prices.\751\ In the Carolina Agencies' view, 
because price information from non-LMP markets is mostly illiquid, non-
transparent and easily manipulated due to the low volume of 
transactions, such reference prices are unlikely to be an accurate and 
reasonable proxy for competitive prices in the mitigated control area. 
They state that, as the Commission has reported, ``some electric power 
markets are almost entirely opaque both to regulators and to price 
takers. In these markets (such as electricity in the Southeast), so 
little information is available that price indices either do not 
develop or have little value in price discovery.'' \752\ The Carolina 
Agencies also wonder how a meaningful proxy could be determined for a 
market price in a control area where a dominant supplier has market 
power.\753\
---------------------------------------------------------------------------

    \751\ Carolina Agencies reply comments at 2-3, 10, 14-18.
    \752\ Id. at 18, n. 11 (citing Federal Energy Regulatory 
Commission--Office of Market Oversight and Investigations, 2004 
State of the Market Report (June 2005)).
    \753\ Id. at 15, n. 9.
---------------------------------------------------------------------------

    690. The Carolina Agencies and NASUCA oppose providing mitigated 
utilities with the option of filing cost-based rates or choosing the 
market rates of a neighboring control area.\754\ NASUCA adds that 
commenters articulate no legal theory by which mitigated sellers should 
be allowed any market rate or how the Commission has power to grant any 
waiver of the rate filing and review requirements of section 205 of the 
FPA.\755\ Rather than allowing mitigated rates to be determined by 
market prices in adjacent market areas, NASUCA urges the Commission to 
deny any form of market rates to mitigated utilities and require such 
suppliers to comply with section 205 of the FPA by filing their rates 
subject to the traditional review to ensure just and reasonable 
rates.\756 \
---------------------------------------------------------------------------

    \754\ Id. at 18-19; NASUCA reply comments at 18-19.
    \755\ NASUCA reply comments at 18-19.
    \756\ Id.
---------------------------------------------------------------------------

    691. If the presence of transmission constraints in a dominant 
transmission provider's control area allow it to charge supra-
competitive market-based rates there, APPA/TAPS submit that the 
Commission must require these constraints to be addressed.\757\ These 
commenters ask the Commission to impose mitigating conditions on 
market-based rate authority to increase access to existing transmission 
facilities as well as to expand their transmission access through 
rolled-in upgrades. For example, APPA/TAPS,\758\ and the Carolina 
Agencies \759\ suggest that the Commission could condition the market-
based rate authority of a mitigated seller on the demonstrated 
willingness of vertically-integrated transmission owners to jointly 
plan and construct new generation projects with market participants, 
and/or to participate with them in collaborative, open regional 
transmission planning processes.
---------------------------------------------------------------------------

    \757\ APPA/TAPS at 50.
    \758\ Id. at 40-41, 49, 50-51.
    \759\ Carolina Agencies at 12, n.10.
---------------------------------------------------------------------------

    692. Xcel responds that, aside from such a requirement being 
impractical, the Commission has no legal authority to impose a 
condition requiring joint planning of new facilities nor jurisdiction 
over the construction of new facilities.\760\ Xcel states that the FPA 
does not provide the Commission with certificate jurisdiction over 
generation facilities or otherwise, nor does the Commission have the 
authority to order utilities to enter into such a contract.\761\
---------------------------------------------------------------------------

    \760\ Xcel reply comments on 9-10.
    \761\ Id. at 10. Duke likewise opposes any proposal granting an 
automatic entitlement to participate in new generation planned by 
the mitigated utility, arguing that the commercial terms of any 
joint ownership arrangements must be negotiated by the parties. Duke 
reply comments at 11; see also, EEI reply comments at 8-9.
---------------------------------------------------------------------------

Commission Determination
    693. The Commission continues to believe that proposed alternative 
methods of mitigation should be cost-based. However, as discussed 
below, while we will not allow the use of alternative ``market-based'' 
mitigation on a generic basis, we will permit sellers to submit 
alternative non-cost-based mitigation proposals for Commission 
consideration on a case-by-case basis.
    694. A variety of suggestions have been made such as basing 
mitigated prices on: Prices from an adjoining LMP market that are 
transparent and contemporaneously available; published index prices; 
prices capped at levels reported in the Electric Quarterly Reports for 
sales in neighboring markets; a utility's own sales in areas where it 
does not possess market power;

[[Page 39986]]

and competitive solicitations with a sufficient amount of bidders or 
opportunity cost pricing. However, while some commenters suggest that 
market-based rate mitigation may cure several of the cost-based 
mitigation regime's alleged ailments, they fail to convincingly address 
a fundamental concern with such mitigation. That is, why a market-based 
price from one market would be a relevant and appropriate proxy price 
to mitigate market power found in a different market.
    695. Specifically, we reject Duke's argument that we should allow 
market-based rate mitigation alternatives to be used by mitigated 
sellers whose control area markets are adjacent to a Commission-
approved market because if the proxy prices are established in markets 
that the Commission has found to be functionally competitive, the price 
will by definition be just and reasonable. Although Duke is correct 
that a price in a market may be presumed to be just and reasonable in 
the market in which it has been approved, Duke's claim fails because 
that price has not been shown to be just and reasonable for other 
markets with differing competitive circumstances.\762\ Duke's argument 
also fails to recognize that the Commission does not certify markets as 
competitive; rather, we make determinations on whether individual 
sellers in a market have market power. In addition, contrary to Duke's 
view, the Commission's acceptance of proposed mitigation in the Big 
Rivers control area does not support Duke's proposal in this regard. In 
LG&E Energy Marketing Inc.,\763\ the Commission accepted a proposal 
that capped--at the Midwest ISO's LMP price at the Big Rivers control 
area interface--all market-based sales by LG&E sinking in the Big 
Rivers control area not sold pursuant to contractual agreements already 
in existence. However, Duke fails to point out that, when LG&E proposed 
to mitigate its sales into the Big Rivers control area, LG&E was a 
member of the Midwest ISO and, accordingly, capping LG&E's sales price 
at the Midwest ISO LMP at the Big Rivers interface was appropriate.
---------------------------------------------------------------------------

    \762\ E.ON U.S.' proposal that the use of index-based price caps 
subject to the market monitoring provisions of an RTO is a just and 
reasonable mitigation option equally fails to address whether the 
index-based price is relevant to the market in which the sale is 
made.
    \763\ 113 FERC ] 61,229 (2005).
---------------------------------------------------------------------------

    696. Commenters raise many reasons why allowing the use of an index 
could be beneficial such as: Using an appropriate price index as a 
proxy could ensure that prices are derived from competitive conditions 
and do not reflect the market power of the mitigated seller; allowing a 
published price index would effectively make the mitigated seller a 
price taker rather than a price setter; use of an index price would 
eliminate the incentive for round-trip transactions and alleviate the 
need to determine whether the need for mitigation should be based on 
the point of delivery, the sink location, or some other determinant; 
would maintain supply choices for captive customers by encouraging 
mitigated suppliers to participate actively in the mitigated markets; 
would help to ensure that buyers continue to receive accurate price 
signals and not inappropriately lean on cost-based rates in times of 
peak demand; and, would be consistent with the Commission's goal of 
encouraging competitive market solutions.
    697. However, we agree with Morgan Stanley and others that, given 
price variations among transmission nodes, we should not generically 
find that one index-based price is necessarily an adequate proxy for 
another node. Commenters urging the Commission to consider such 
alternatives on a case-by-case basis acknowledge that different markets 
may be uncompetitive for different reasons.\764\ While commenters speak 
of ``relevant price indexes,'' their comments contain little more than 
undeveloped proposals and limited discussion as to how such an index 
would be chosen, and why it would be an appropriate proxy for the 
mitigated market. For example, commenters fail to explain how a proxy 
price based on existing competition from one market with distinct 
traits such as transmission congestion ensures a just and reasonable 
price in another market that has its own unique traits and 
circumstances. Deriving prices from competitive conditions, making a 
mitigated seller a price taker rather than a price setter, and reducing 
market distortions are all goals commenters claim market-based 
mitigation can help achieve. Nonetheless, the use of an external market 
price to establish the just and reasonable price in the mitigated 
market has not yet been shown to be appropriate.
---------------------------------------------------------------------------

    \764\ MidAmerican at 14; NYISO at 8; Duke at 13-14; Drs. Broehm 
and Fox-Penner at 15.
---------------------------------------------------------------------------

    698. While we will not allow the use of ``market-based'' mitigation 
on a generic basis, we nevertheless will permit sellers to submit non-
cost-based mitigation proposals, such as the use of an index or an LMP 
proxy, for Commission consideration on a case-by-case basis based on 
their particular circumstances. Sellers choosing to propose such 
alternative mitigation will carry the burden of showing why and how the 
proposed index-based price is relevant, appropriate and a just and 
reasonable price for the mitigated market. While several commenters 
also seek to have the Commission make market-based rate authorization 
of mitigated sellers contingent upon their pledging to jointly plan and 
construct future generation projects with market participants, or 
pursue other structural conditions, they have not justified imposing 
such a burden. For those sellers that are affected with a market power 
concern, we discuss elsewhere in this Final Rule the means by which we 
will require adequate mitigation. Moreover, we believe that we have 
adequately addressed these concerns related to planning in our recent 
Order No. 890, where we require all jurisdictional transmission owners 
to engage in transmission planning with other market participants. 
Therefore, we find no reason to mandate a mitigated seller's 
participation in such arrangements.
2. Discounting
Commission Proposal
    699. In the NOPR, the Commission explained that a supplier 
authorized to sell under an ``up to'' cost-based rate has an incentive 
to discount its sales price when the market price in the supplier's 
local area is lower than the cost-based ceiling rate. During these 
periods, a rational seller will discount its sales to maximize revenue. 
In the past, the Commission has encouraged discounting as an efficient 
practice that can maximize revenues to reduce the revenue requirements 
borne by requirements customers.
    700. Here, the primary issue is whether a seller can 
``selectively'' discount, i.e., offer different prices to different 
purchasers of the same product during the same time period. The 
Commission invited comment on whether selective discounting should be 
allowed for sellers that are found to have market power or have 
accepted a presumption of market power and are offering power under 
cost-based rates. If so, the Commission sought comment on what 
mechanisms (reporting or otherwise), if any, are necessary to protect 
against undue discrimination. By contrast, were it to forbid selective 
discounting, the Commission asked for comment on whether it should 
require the utility to post discounts to ensure that they are available 
to all similarly-situated customers.

[[Page 39987]]

Comments
    701. Some commenters favor selective discounting because it 
provides an opportunity to meet competition where necessary to retain 
and attract business. They add that the contracting flexibility 
afforded by selective discounting allows sellers to modify rates and 
tailor sales based on customer-specific factors such as load 
characteristics and credit ratings. They argue that such flexibility 
maximizes liquidity and available capacity and energy.\765\
---------------------------------------------------------------------------

    \765\ See, e.g., Indianapolis P&L at 10; MidAmerican at 15-16; 
Duke at 10-11; EEI at 34; PG&E at 23; Progress Energy at 12.
---------------------------------------------------------------------------

    702. MidAmerican and Indianapolis P&L both state that section 206 
of the FPA already prohibits undue discrimination and provides well-
established procedures for entities that have been subjected to undue 
discrimination.\766\ Westar notes that the Commission's long-standing 
policy is to allow selective discounting and asserts that discounting 
to customers who have competitive alternatives is not unduly 
discriminatory.\767\
---------------------------------------------------------------------------

    \766\ MidAmerican at 15; Indianapolis P&L at 10.
    \767\ Westar at 26 (citing Town of Norwood v. FERC, 587 F.2d 
1306, 1312 & n.17 (D.C. Cir. 1978) (rate disparity may be justified 
by, inter alia, differences in the customers' level of risk aversion 
and bargaining power)); see Policy for Selective Discounting by 
Natural Gas Pipelines, 111 FERC ] 61,309, reh'g denied, 113 FERC ] 
61,173 (2005) (affirming Commission's 16-year policy to allow 
selective discounting by interstate natural gas pipelines when 
necessary to meet competition).
---------------------------------------------------------------------------

    703. PG&E maintains that it is just and reasonable for a seller to 
offer a discount below its cost-based mitigated rate if the seller will 
gain other (non-market power) advantages such as repeat customers or 
lower transaction costs. PG&E also suggests that principles of 
efficiency and competition support providing selective discounts to 
entities with larger needs.\768 \
---------------------------------------------------------------------------

    \768\ PG&E at 23.
---------------------------------------------------------------------------

    704. Duke contends that sales arising from selective discounting 
spread fixed costs over more units of service, thereby reducing the 
``up to'' rate.\769\ Moreover, without the ability to selectively 
discount, Duke submits that utilities will not have the opportunity to 
compete for many wholesale transactions in the mitigated control 
area.\770\
---------------------------------------------------------------------------

    \769\ Duke at 11.
    \770\ Id.
---------------------------------------------------------------------------

    705. Southern asserts that if selective discounting were 
eliminated, then the resulting loss of a low-cost source of supply 
would harm the customers. In Southern's view, captive customers also 
lose because of foregone opportunities to optimize capacity nominally 
dedicated to native load service.\771\ EEI adds that where a mitigated 
seller is already precluded from making market-based rate sales within 
mitigated areas, selective discounting does not give rise to conditions 
that support the potential exercise of market power.\772\
---------------------------------------------------------------------------

    \771\ Southern at 67.
    \772\ EEI at 31; see also PG&E at 23.
---------------------------------------------------------------------------

    706. Other commenters generally oppose allowing mitigated sellers 
to selectively discount sales. For example, TDU Systems claim that 
selective discounting is unnecessary because a seller subject to cost-
based mitigation in its home control area would not face competition by 
definition. They also contend that selective discounting would allow 
mitigated sellers to engage in price discrimination in a non-
competitive market, thereby permitting the seller to exercise market 
power by economically or physically withholding capacity to increase 
the posited market price. Thus, in the TDU Systems' view, a rule 
allowing selective discounting would effectively grant market-based 
rate authority in a non-competitive market, in contravention of the 
requirements of the FPA.\773\
---------------------------------------------------------------------------

    \773\ TDU Systems at 19-21.
---------------------------------------------------------------------------

    707. While NC Towns generally encourage discounts to cost-based 
rates, they oppose selective discounting because they do not believe 
that the size of a load should be a factor when determining whether to 
give a buyer a discount.\774\
---------------------------------------------------------------------------

    \774\ NC Towns at 5.
---------------------------------------------------------------------------

    708. APPA/TAPS question why a dominant seller would offer discounts 
to captive customers with no other viable supply options. They add that 
there is no evidence that local, competing generation exists or that 
there is available transmission capacity that could support significant 
imports. In order to avoid discrimination, APPA/TAPS advocate requiring 
a mitigated supplier to offer captive customers any discounts that it 
offers to other purchasers.\775\ Factors such as a customer's capacity 
factor, credit rating or fuel costs may justify adjustments to seller-
specific cost-based rates, but such factors, argue APPA/TAPS, should be 
reflected in the seller's cost-based rates rather than through 
selective discounting.\776\
---------------------------------------------------------------------------

    \775\ APPA/TAPS reply comments at 15-16; APPA/TAPS at 44-48.
    \776\ APPA/TAPS reply comments at 16.
---------------------------------------------------------------------------

    709. If selective discounting is permitted, TDU Systems and NRECA 
urge the Commission to require sellers to file reports of the discounts 
offered, and encourage the Commission to vigorously enforce its market 
manipulation and affiliate transactions rules.\777\
---------------------------------------------------------------------------

    \777\ TDU Systems at 24; NRECA at 32.
---------------------------------------------------------------------------

    710. Suez/Chevron urges the Commission to require selective 
discounts to be contemporaneously offered to similarly-situated buyers, 
and separately identified in the mitigated seller's EQR.\778\ To 
minimize the potential for market power abuse when a mitigated seller 
selectively discounts to an affiliate,\779\ Suez/Chevron supports 
requiring a presumption that nonaffiliated buyers are similarly-
situated, and therefore entitled to the same discount as a mitigated 
seller offers to its affiliate.\780\
---------------------------------------------------------------------------

    \778\ NC Towns and Morgan Stanley state that any discount the 
seller wishes to offer should be required to be posted with 
sufficient time for other interested parties to take advantage of 
the offer. NC Towns at 5-6; Morgan Stanley at 7.
    \779\ Suez/Chevron states that sellers should be required to 
post any affiliate discounts on their OASIS. Suez/Chevron at 13.
    \780\ Suez/Chevron at 12-13.
---------------------------------------------------------------------------

    711. PG&E, in contrast, opposes requiring the seller to make 
discounts available to all similarly-situated entities. According to 
PG&E, it would be difficult to determine which entities are in fact 
similarly-situated because the seller would have to consider multiple 
factors, such as quantity of load, timing, flexibility, credit rating, 
and purchases history.\781\
---------------------------------------------------------------------------

    \781\ PG&E at 24.
---------------------------------------------------------------------------

    712. Ameren disagrees with a posting requirement, arguing that the 
Commission's requirements for separate filings and advance approval of 
affiliate power sales provide the appropriate oversight and mechanisms 
necessary to police discounting concerns regarding selective discounts 
favoring affiliates. Ameren concludes that a requirement to post 
discounts is unduly burdensome given that the only discounts of concern 
are in the affiliate sales, which are subject to separate filing 
requirements.\782\ PG&E, in turn, notes that the affiliate restrictions 
also provide protection against the use of selective discounts to 
benefit affiliates.\783\
---------------------------------------------------------------------------

    \782\ Ameren at 17-18.
    \783\ PG&E at 23.
---------------------------------------------------------------------------

Commission Determination
    713. We will continue our practice of allowing discounting from the 
default cost-based mitigated rates for short- and mid-term sales and 
will permit selective discounting by mitigated sellers provided that 
the sellers do not use such discounting to unduly discriminate or give 
undue preference. We believe that selective discounting that does not 
constitute undue discrimination can improve liquidity, available 
capacity and energy, and customer supply

[[Page 39988]]

options. In other words, non-discriminatory discounting can provide 
benefits to the market.
    714. APPA/TAPS question why a dominant seller would offer discounts 
to captive customers with no other viable supply options, and the TDU 
Systems comment that selective discounting is unnecessary because a 
mitigated seller by definition would not face competition in its home 
control area. However, in times when there are viable alternatives, a 
seller under an ``up to'' cost-based rate has an incentive to discount 
its sales price when the market price in the seller's mitigated market 
is lower than the cost-based ceiling rate. Allowing a mitigated seller 
to non-discriminatorily discount the rate when there are viable 
alternatives in the market benefits customers by providing more supply 
options in such instances.
    715. Discounting also can maximize revenue by optimizing capacity 
nominally dedicated to native load service, allowing the supplier to 
spread fixed costs over more units of service. Maximizing revenue in 
this manner can help reduce the ``up to'' rate, and therefore the 
revenue requirements borne by captive customers. The Commission has 
previously determined that requiring a mitigated entity to limit sales 
to its ceiling rates ``is at odds with the long-standing policy of 
allowing `up to' cost-based rates.'' \784\
---------------------------------------------------------------------------

    \784\ Duke Power, 113 FERC ] 61,192 at P 17 (2005).
---------------------------------------------------------------------------

    716. The FPA requires that all rates charged by public utilities 
for the sale or resale of electric energy be ``just and reasonable.'' 
\785\ If a seller's cost-based rate has been found to be just and 
reasonable by the Commission, it follows that discounted rates below 
such a cost-based rate are also just and reasonable.\786\ However, a 
seller may not lawfully discount to gain, or profit from, market power 
advantages. We emphasize that section 205 of the FPA prohibits public 
utilities, in any power sale subject to the Commission's jurisdiction, 
from granting any undue preference or advantage to any person \787\ and 
also prohibits undue discrimination.\788\
---------------------------------------------------------------------------

    \785\ 16 U.S.C. 824d(a).
    \786\ Public Service Company of Oklahoma, 54 FERC ] 61,021, at 
61,032 and fn. 8 (1991) (``If PSO's rates set at full cost are 
reasonable in the presence of market power, it follows that PSO's 
rates reflecting less than a 100-percent contribution to fixed costs 
are also reasonable in the presence of market power.'').
    \787\ 16 U.S.C. 824d(b).
    \788\ 16 U.S.C. 824e(a).
---------------------------------------------------------------------------

    717. With regard to comments that the Commission establish a 
reporting mechanism, under the Commission's existing reporting 
requirements entities making power sales must submit EQRs containing: A 
summary of the contractual terms and conditions in every effective 
service agreement for all jurisdictional services, including market-
based and cost-based power sales and transmission services; and, 
transaction information for effective short-term (less than one year) 
and long-term (one year or greater) power sales during the most recent 
calendar quarter.\789\ Through this reporting requirement, the 
Commission monitors the rates charged by mitigated sellers.
---------------------------------------------------------------------------

    \789\ Revised Public Utility Filing Requirements, Order No. 
2001, 67 FR 31043 (May 8, 2002), FERC Stats. & Regs. ] 31,127 
(2002). Required data sets for contractual and transaction 
information are described in Attachments B and C of Order No. 2001.
---------------------------------------------------------------------------

    718. Several commenters also seek to have the Commission require 
selective discounts to be posted and contemporaneously offered to 
similarly-situated buyers. Some seek a presumption that nonaffiliated 
buyers are similarly situated whenever a mitigated seller offers an 
affiliate a discount. The Commission will not require mitigated sellers 
to contemporaneously post in a public forum all discounts provided for 
cost-based sales (i.e., where the sale is made at a price below the 
maximum up-to cost-based rate approved by the Commission in that tariff 
or rate schedule). Proponents of a posting requirement have not 
justified nor demonstrated how the Commission's EQR requirement fails 
to provide an adequate means by which to monitor such discounts. In 
addition, many sales are made below the cost-based cap, and the 
commenters' proposals would place an undue burden on sellers that would 
be required to contemporaneously post rates that the Commission has 
already deemed to be just and reasonable. Accordingly, the Commission 
will not require the contemporaneous posting of discounted cost-based 
rates. Finally, commenters have provided no basis to conclude that 
nonaffiliated buyers are similarly situated whenever a mitigated seller 
offers an affiliate a discount, and we will not adopt the proposed 
presumption in this regard. Thus, sellers may selectively discount only 
if they do so in a manner that is not unduly discriminatory or 
preferential.
    719. Further, we agree with MidAmerican that identifying 
discriminatory selective discounting requires fact-specific 
evaluations. Because individual proceedings are the best instrument 
available to the Commission for such efforts, allegations of undue 
discrimination arising from selective discounting are best addressed on 
a case-by-case basis.
3. Protecting Mitigated Markets
a. Must Offer
Commission Proposal
    720. Under the Commission's current mitigation policy, a seller 
that loses market-based rate authority in its home control area is 
limited to charging cost-based rates in that control area; however, 
there is no requirement that the seller offer its available power to 
customers in that home control area. Instead, the seller is free to 
market all of its available power to purchasers outside that control 
area if it chooses to do so. If, for example, market prices outside the 
mitigated seller's control area exceed the cost-based caps within the 
mitigated control area, then the seller will, other things being equal, 
have an incentive to sell outside. As noted in the NOPR, wholesale 
customers have argued that default cost-based mitigation of this kind 
is of little value if a seller can market its excess capacity at 
market-based rates in other control areas. In the NOPR, the Commission 
sought comment on whether its current policy is appropriate, and if 
not, what further restrictions are needed. The Commission asked whether 
it should adopt a form of ``must offer'' requirement in mitigated 
markets to ensure that available capacity (i.e., above that needed to 
serve firm and native load customers) is not withheld. If so, the 
Commission asked if such a ``must offer'' requirement should be limited 
to sales of a certain period to help ensure that wholesale customers 
use that power to serve their own needs, rather than simply remarketing 
that power outside the control area and profiting. \790\ If it were to 
adopt such a ``must offer'' requirement, the Commission asked what 
rules there should be to define the ``available'' capacity that must be 
offered , in order to avoid case-by-case disputes over this issue.
---------------------------------------------------------------------------

    \790\ In this regard, the Commission asked if there should be an 
annual open season under which the mitigated seller offers its 
available capacity to local customers for the following year at the 
cost-based ceiling rate and, if customers do not commit to purchase 
that capacity, then the seller would be free to sell the remaining 
capacity at market-based rates where it has authority to do so.
---------------------------------------------------------------------------

Comments
    721. Wholesale customers generally support a ``must offer'' 
requirement,'' stating that it is needed to ensure that power is 
available for purchase in the mitigated market and to protect them from 
incurring higher costs to serve

[[Page 39989]]

load.\791\ They argue that the existence of a dual price system (a 
regime where a seller has market-based rate authority in some markets 
but is limited to cost-based sales in other market(s)) creates an 
incentive for a mitigated seller to sell its power outside of the 
mitigated market whenever market prices in the outside market are above 
the mitigated seller's cost-based price. They are concerned 
particularly with the situation where a wholesale customer faces few or 
no alternatives in the mitigated market due to transmission 
constraints.
---------------------------------------------------------------------------

    \791\ See, e.g., APPA/TAPS at 40-42 (also urging the Commission 
to apply any ``must offer'' requirement to captive customers in the 
seller's transmission service area); Carolina Agencies at 10-13; 
NRECA at 35; Montana Counsel at 19; TDU Systems at 19; NC Towns at 
6-8 (asking the Commission to require mitigated utilities to serve 
wholesale customers in the mitigated control area at long-term 
system average cost-based rates in order to maintain reliability). 
See also MidAmerican reply comments at 9-12 (arguing that the APPA/
TAPS and Carolina Agencies proposals suffer from significant policy 
flaws).
---------------------------------------------------------------------------

    722. APPA/TAPS, the Carolina Agencies and NRECA claim that the 
Commission has both the authority and obligation to remedy undue 
discrimination in wholesale sales, which are clearly set forth in 
sections 205 and 206 of the FPA.\792\ They specifically argue that a 
``must offer'' condition is within the Commission's authority as a 
remedy for the unjust and unreasonable rates and undue discrimination 
(refusal to sell in the mitigated control area) that are a consequence 
of the mitigated seller's accumulation of market power.\793\ Several 
commenters reason that, similar to imposing reporting requirements and 
other conditions on a grant of market-based rate authority, where a 
seller no longer has market-based rate authority in its home control 
area, the Commission may impose a ``must offer'' condition on the 
continuation of market-based rate authorization outside a mitigated 
seller's control area.\794\ APPA/TAPS and the Carolina Agencies argue 
that the Commission already imposed a must-offer obligation on the 
continued availability of market-based rate authority for sellers in 
the California markets.\795\
---------------------------------------------------------------------------

    \792\ APPA/TAPS and Carolina Agencies supplemental comments at 
4, 9-18 (citing, among others, 16 U.S.C. 824d(a), 824d(b), 824e(a); 
Associated Gas Distributors v. FERC, 824 F.2d 981, 998 (D.C. Cir. 
1987)).
    \793\ NRECA reply comments at 41 (citing New York v. FERC, 535 
U.S. 1, 27 (2002); Transmission Access Policy Study Group v. FERC, 
225 F.3d 667, 683-88 (D.C. Cir. 2000), aff'd sub nom. New York v. 
FERC, 535 U.S. 1 (2002)); Carolina Agencies at 4-5; Carolina 
Agencies reply comments at 2. See also Montana Counsel at 19 (citing 
Atlantic Ref. Co. v. Public Serv. Comm'n of N.Y., 360 U.S. 378 
(1959) and United Gas Improvement Co. v. Callery Properties, Inc., 
382 U.S. 223 (1965), two cases in which the Montana Counsel claim 
that the Supreme Court, in recognition of the market power of 
natural gas producers and the public interest provisions of the NGA, 
``virtually ordered'' the Commission to exercise its jurisdiction to 
condition producer natural gas certificates and rate orders to limit 
gas prices); APPA/TAPS and Carolina Agencies supplemental comments 
at 2, 18-30; NRECA supplemental comments at 6-7.
    \794\ APPA/TAPS at 37-38; APPA/TAPS reply comments at 8; Montana 
Counsel at 21-22; Carolina Agencies at 4-5; Carolina Agencies reply 
comments at 3-4.
    \795\ APPA/TAPS and Carolina Agencies supplemental comments at 
27 (citing San Diego Gas & Elec. Co. v. Sellers of Energy and 
Ancillary Servs. Into Mkts. Operated by the Cal. Ind. Sys. Operator 
and the Cal. Power Exch., 93 FERC ] 61,294, at 62,010-11 (2000) 
(extended-refund-period condition), order on rehearing and 
clarification, 97 FERC 61,275, at 62,243-44 (2001), order on 
rehearing and clarification, 99 FERC ] 61,160 (2002), on rehearing 
and clarification, 105 FERC ] 61,065 (2003), petitions for rev. 
granted in part sub nom. Bonneville Power Auth. v. FERC, 422 F.3d 
908 (9th Cir. 2005) and Public Utils. Comm'n of Cal. v. FERC, 462 
F.3d 1027, 1043 (9th Cir. 2006) (discussing must-offer condition)).
---------------------------------------------------------------------------

    723. APPA/TAPS also assert that while Order No. 888 rejected a 
generic obligation that would have required sellers to continue 
wholesale sales past the expiration of the contract(s) in question in 
that proceeding, Order No. 888 explained that the Commission can impose 
an obligation to continue service on a case-by-case basis.\796\
---------------------------------------------------------------------------

    \796\ APPA/TAPS at 39 (citing Order No. 888--``we continue to 
believe that the extent to which a customer could demonstrate a 
reasonable expectation of continued service at the existing contract 
rate (or at a cost-based rate, if that was the customer's 
expectation) is best addressed on a case-by-case basis''); see also 
Order No. 888, FERC Stats. & Regs. ] 31,036, at 31,805 & n.652 
(1996) (explaining that although the Commission determined ``not to 
impose a regulatory obligation on wholesale requirements suppliers 
to continue to serve their existing requirements customers,'' ``any 
party claiming to be aggrieved by a utility's alleged abuse of 
generation market power under a wholesale requirements contract can 
file a complaint with the Commission under Section 206''); see also 
Montana Counsel at 22.
---------------------------------------------------------------------------

    724. APPA/TAPS and the Carolina Agencies argue that a dominant 
public utility's physical withholding of generation in the mitigated 
market in order to make market-based sales elsewhere results in undue 
discrimination that the Commission has an obligation to remedy. They 
assert that because wholesale customers in the mitigated market are 
harmed through decreased supply, increased market concentration, and 
increased prices, these customers are exposed to the type of injury 
against which the FPA was designed to protect.\797\ The Carolina 
Agencies also maintain that, whether or not exporting behavior can be 
considered economically efficient, such behavior results in undue 
discrimination between (i) The mitigated utility's native load and (ii) 
LSEs located within the mitigated utility's home control area.\798\ 
This outcome, the Carolina Agencies continue, violates the FPA's 
mandate that rates be just, reasonable and not unduly discriminatory 
regardless of whether the mitigated utility's decision to export power 
is a conscious ``withholding'' for anticompetitive ends.\799\ APPA/TAPS 
and Carolina Agencies add that vertically-integrated utilities with 
substantial generation in their home control areas frequently have the 
ability and incentive to discriminate against their wholesale 
customers, who compete against them on both the wholesale and retail 
level.\800\
---------------------------------------------------------------------------

    \797\ APPA/TAPS and Carolina Agencies supplemental comments at 
19.
    \798\ Carolina Agencies at 6.
    \799\ Id. at 9.
    \800\ APPA/TAPS and Carolina Agencies supplemental comments at 
16 (citing FPC v. Conway Corp., 426 U.S. 271, 278 (1976) to further 
argue that the Commission can and must take account of competition 
at retail when determining whether such discrimination exists.)
---------------------------------------------------------------------------

    725. APPA/TAPS and Carolina Agencies maintain that undue 
discrimination occurs if a dominant public utility unjustifiably 
disadvantages a class of market participants. They cite case law that 
the D.C. Circuit found ``upholds the power of the Commission to subject 
approval of a set of voluntary transactions to a condition that 
providers open up the class of permissible users.'' \801\ Absent 
relevant circumstances that render two sets of customers differently 
situated, they assert that it is unduly discriminatory for a public 
utility to sell wholesale power to one set of customers (at market-
based rates) while denying service to another set (to whom sales, if 
made, would need to be priced at cost-based rates). They contend there 
is no justification for disparate treatment in such a case and, 
therefore, the Commission is obligated under sections 205 and 206 to 
remedy such undue discrimination by either denying or conditioning the 
grant of market-based rate authority outside of the mitigated home 
control area. A ``must offer'' condition, they claim, would satisfy 
this obligation by preventing undue discrimination.\802\
---------------------------------------------------------------------------

    \801\ Id. at 13 (citing Central Iowa Power Coop. v. FERC, 606 
F.2d 1156, 1172 (D.C. Cir. 1979); and quoting Associated Gas 
Distributors v. FERC, 824 F.2d 981, 999 (D.C. Cir. 1987)). APPA/TAPS 
and Carolina Agencies claim that in this case, a must offer 
requirement would expand the class of buyers of the mitigated 
seller's wholesale services to include customers from the mitigated 
utility's home control area.
    \802\ Id. at 15-16.
---------------------------------------------------------------------------

    726. APPA/TAPS and the Carolina Agencies further allege that, while 
it may not be unduly discriminatory for a utility to elect to sell to 
the wholesale

[[Page 39990]]

customer who will pay the highest price, it is unduly discriminatory if 
the price differential is based upon mitigation required as a result of 
the seller's market power.\803\ Where sellers claim a right to seek the 
highest prices, APPA/TAPS and the Carolina Agencies counter that this 
profit maximization impulse can neither justify the exercise of market 
power nor insulate it from correction.\804\
---------------------------------------------------------------------------

    \803\ Id. at 30.
    \804\ Id. at 31.
---------------------------------------------------------------------------

    727. According to APPA/TAPS and the Carolina Agencies, it is also 
unduly discriminatory for a mitigated seller to make market-based rate 
sales outside its home control area when constraints on that entity's 
own transmission system prevent embedded customers from similarly 
accessing those markets as buyers. They argue that refusal to sell 
wholesale power supplies to embedded LSE customers at fully-
compensatory cost-based rates effectively compounds the de facto denial 
of access by exacerbating both the discrimination and the resulting 
harm.\805\ According to APPA/TAPS and the Carolina Agencies, the claim 
that mitigated sellers are merely engaging in economically efficient 
behavior ignores the market power that the sellers possess.\806\ They 
state that when captive customers have few or no supply alternatives in 
the mitigated market and are constrained from accessing opportunities 
in the broader market (even with open access tariffs), and the dominant 
supplier sells its excess capacity beyond the mitigated market, the 
resulting reduction in output in the mitigated market is not addressed 
simply by prohibiting the mitigated seller from selling at unmitigated 
prices in the mitigated region.\807\ They conclude that it would be 
unjust and unreasonable to permit or facilitate such withholding by 
allowing unconditioned sales at market-based rates outside a mitigated 
supplier's home control area; this would reserve the benefits of 
competitive markets exclusively to dominant public utility 
sellers.\808\
---------------------------------------------------------------------------

    \805\ Id. at 30-31.
    \806\ APPA/TAPS at 6-7; Carolina Agencies reply comments at 6.
    \807\ APPA/TAPS reply comments at 6-7.
    \808\ APPA/TAPS supplemental comments at 30-31.
---------------------------------------------------------------------------

    728. A number of commenters claim that a ``must offer'' requirement 
is necessary due to their lack of viable options in mitigated control 
areas. For example, Fayetteville submits that it finds itself without 
transmission access to make short-term energy purchases to displace its 
higher cost generation.\809\ Fayetteville contends that Progress 
Energy's dominant position, as well as Fayetteville's inability to 
access alternative suppliers due to the inadequacy of Progress Energy's 
transmission system, gives Progress Energy unmitigated market 
power.\810\
---------------------------------------------------------------------------

    \809\ Fayetteville reply comments at 5.
    \810\ Id. at 6. See also Montana Counsel at 15-23 (where market 
power is found, sellers should be required to offer power to meet 
the requirements of dependent customers at cost).
---------------------------------------------------------------------------

    729. The Carolina Agencies add that, while economic efficiency is a 
worthy goal in structurally sound markets where participants have ready 
and equal access to meaningful choices, the idea of economic efficiency 
cannot justify a mitigated supplier's behavior in a control area where 
its market power arises from import limitations or other factors that 
deprive captive LSEs of viable options. Nor can, they claim, the goal 
of economic efficiency trump the Commission's clear duty to protect 
customers by ensuring that rates are just, reasonable, and not unduly 
discriminatory.\811\
---------------------------------------------------------------------------

    \811\ Carolina Agencies reply comments at 9.
---------------------------------------------------------------------------

    730. The Carolina Agencies dispute the claim that there is no need 
for a ``must offer'' requirement given the Commission's authority to 
penalize market manipulation. They question whether refusal to sell in 
the mitigated market would be actionable under the anti-manipulation 
rules if there is no obligation to offer power to embedded LSEs.\812\
---------------------------------------------------------------------------

    \812\ Carolina Agencies reply comments at 10-11.
---------------------------------------------------------------------------

    731. NRECA and others ask the Commission to reject the claim that a 
``must offer'' requirement would impede a mitigated seller's ability to 
fulfill its retail crediting obligations.\813\ NRECA responds that 
retail customers can sometimes benefit from cost-based rates; if 
competition reduces the market price to a seller's marginal cost, no 
contribution to fixed costs would be recovered. Commenters note that 
not all utilities are subject to rules requiring the sharing of profits 
from off-system sales.\814\ NRECA argues that a utility's authority to 
make off-system sales at market-based rates is a privilege granted by 
the Commission; if the Commission restricts or conditions that 
privilege, any obligation the public utility has under State law or 
regulation to sell excess energy or capacity is pre-empted by the 
requirements of Federal regulation.\815\ The Carolina Agencies and 
NRECA add that a ``must offer'' requirement would serve the intended 
purpose of the Commission's mitigation policy, which is to protect 
wholesale customers from the exercise of actual and potential market 
power, not to preserve a utility's ability to reduce retail rates nor 
its ability to engage in a certain volume of off-system power 
sales.\816\
---------------------------------------------------------------------------

    \813\ See, e.g., NRECA reply comments at 37-39; Carolina 
Agencies at 17 (citing April 14 Order, 107 FERC ] 61,018 at P 140, 
154, where they claim that the Commission rejected arguments that 
cost-based mitigation rates adversely affect retail rates, because 
such rates provide for the recovery of the mitigated utility's 
longer-term costs, and because the adverse impact claims were 
``unsupported and speculative.''); Fayetteville reply comments at 7, 
9-10.
    \814\ NRECA reply comments at 38; Carolina Agencies at 8.
    \815\ NRECA reply comments at 38-39 (citing Entergy La., Inc., 
v. La. Pub. Serv. Comm'n, 539 U.S. 39 (2003); Miss. Power & Light 
Co. v. Mississippi ex rel. Moore, 487 U. S. 354 (1988); Nantahala 
Power & Light Co. v. Thornburg, 476 U. S. 953 (1986)); see also 
Carolina Agencies reply comments at 7-8 (where a utility is 
satisfying a countervailing regulatory mandate (such as a ``must 
offer'' obligation, it cannot be held to be violating the cost 
minimization duty)).
    \816\ Carolina Agencies at 17; Carolina Agencies reply comments 
at 7-8; NRECA reply comments at 35.
---------------------------------------------------------------------------

    732. NRECA, APPA/TAPS and the Carolina Agencies all set forth 
proposals in their comments for implementing a ``must offer'' 
requirement.\817\ NRECA suggests requiring a mitigated seller to hold 
an annual open season to offer long-term service (one year or more), as 
well as requiring a mitigated seller to offer shorter-term capacity and 
energy.\818\ While not favoring an annual open season, APPA/TAPS and 
the Carolina Agencies each propose ``must-offer'' parameters to govern 
short- and long-term sales.\819\ For both short- and long-term sales, 
the Carolina Agencies would offer captive customers an option between 
(1) Locking-in their price at the mitigated utility's embedded cost 
rates or (2) agreeing to have their charges determined through an 
annually updated formula rate that reflects the mitigated utility's 
actual system-wide average costs.\820\ The APPA/TAPS proposal also 
includes an obligation to offer captive customers participation on 
proposed generation projects.\821\ Both APPA/TAPS and the Carolina 
Agencies would limit any ``must-offer'' to loads actually located in 
the mitigated control area.
---------------------------------------------------------------------------

    \817\ NRECA at 35; APPA/TAPS at 40-42; Carolina Agencies at 10-
13.
    \818\ NRECA at 35-36.
    \819\ APPA/TAPS at 40-42; Carolina Agencies at 10-13.
    \820\ Carolina Agencies at 12-13.
    \821\ APPA/TAPS at 41.
---------------------------------------------------------------------------

    733. NRECA also proposes two alternatives to a ``must offer'' 
requirement. First, NRECA suggests that the Commission give captive 
wholesale customers a right of first refusal to purchase at a market 
price energy or capacity that the mitigated seller proposes to sell 
outside the mitigated

[[Page 39991]]

market.\822\ The weakness of this approach, NRECA acknowledges, is that 
it would allow the mitigated seller to charge wholesale customers a 
supra-competitive price in the mitigated market given that the market-
based rate outside the control area would be higher than the cost-based 
rate in the seller's control area.\823\
---------------------------------------------------------------------------

    \822\ NRECA reply comments at 36-37.
    \823\ NRECA at 36-37. MidAmerican disagrees, arguing that 
market-based prices are not by definition always higher than cost-
based prices in the mitigated region. Rather, the Commission has 
encouraged open access transmission and market competition because 
economically efficient market-based rates can be lower than cost-
based rates. At the same time, where a price index at a trading hub 
may be lower than the seller's incremental cost, MidAmerican argues 
that a seller should never be required to sell at rates below its 
incremental cost. MidAmerican reply comments at 21.
---------------------------------------------------------------------------

    734. NRECA also suggests as an alternative an enforceable 
commitment to provide sufficient additional transmission import 
capacity to mitigate the generation market power. It states that such a 
commitment could be implemented by re-dispatching resources, 
relinquishing transmission reservations, or physically upgrading the 
transmission grid. This would allow additional suppliers to make sales 
in the mitigated region, thereby mitigating the seller's generation 
market power. NRECA contends that this approach would directly address 
the larger issue of the need to eliminate transmission bottlenecks and 
load pockets that give rise to generation market power.\824\
---------------------------------------------------------------------------

    \824\ NRECA at 37.
---------------------------------------------------------------------------

    735. The Carolina Agencies also propose that mitigated utilities be 
required to investigate and report on transmission expansion or other 
actions that could remove structural impediments causing market power. 
The Carolina Agencies claim that such a requirement is consistent with 
the Commission's affirmative duty to remedy undue discrimination, an 
area in which the Commission has broad authority to craft 
remedies.\825\
---------------------------------------------------------------------------

    \825\ Carolina Agencies at 16 (citing the OATT Reform NOPR at P 
210 and n.203).
---------------------------------------------------------------------------

    736. Other commenters argue against imposition of a ``must offer'' 
requirement, stating that it would encourage inefficiencies, undermine 
competition, discourage investment, and perpetuate market power. They 
also assert that such a requirement goes beyond any cost-of-service 
requirement that the Commission has ever adopted.\826\ They question 
the need for a ``must offer'' requirement, claiming that existing 
Commission statutory authority, regulations, and enforcement mechanisms 
already sufficiently guard against the market power abuse and market 
manipulation concerns that ``must offer'' proponents claim such a 
provision is needed to prevent.\827\
---------------------------------------------------------------------------

    \826\ See, e.g., Xcel at 5; Progress Energy reply comments at 5. 
APPA/TAPS and NRECA respond that as long as the rate is cost-
compensatory, and therefore just and reasonable, it provides an 
adequate return and the mitigated supplier is not disadvantaged by 
making such sale. APPA/TAPS reply comments at 9; NRECA reply 
comments at 31, 35, 38.
    \827\ See, e.g., EEI at 36; Progress Energy at 17.
---------------------------------------------------------------------------

    737. EEI and Progress Energy claim that when the Commission 
establishes a cost-based rate in a mitigated market, it ensures that 
the rate meets the just and reasonable and not unduly discriminatory 
requirements of sections 205 and 206 of the FPA, and thus there is no 
further Commission action that is required to mitigate the indicated 
market power.\828 \
---------------------------------------------------------------------------

    \828\ EEI at 37; Progress Energy at 13.
---------------------------------------------------------------------------

    738. Several commenters that argue against imposition of a ``must 
offer'' requirement state that wholesale customers have not presented 
sufficient evidence to justify the generic imposition of such a 
requirement. They state that there have been no specific instances 
cited where a wholesale customer in a mitigated market was unable to 
obtain service, much less evidence that such instances are commonplace.
    739. Duke/Progress Energy argue that the Commission must make a 
finding that rates or practices are unjust, unreasonable, or unduly 
discriminatory as a predicate to taking action, and that in the case of 
a generic rulemaking, ``the Commission'' cannot rely solely on 
``unsupported or abstract allegations.''' \829\ They cite National Fuel 
Gas Supply Corp. v. FERC,\830\ where the D.C. Circuit, describing 
Tenneco Gas v. FERC,\831\ stated ``[t]he court [in Tenneco] `upheld 
Order 497 in relevant part because FERC presented an adequate 
justification--by advancing both (i) A plausible theoretical threat of 
anti-competitive information-sharing between pipelines and their 
marketing affiliates and (ii) vast record evidence of abuse.' ''\832\ 
They note that the D.C. Circuit contrasted Tenneco with Order No. 2004 
(at issue in National Fuel), where `` `FERC has cited no complaints and 
provided zero evidence of actual abuse between pipelines and their non-
marketing affiliates.' '' They assert that the D.C. Circuit concluded 
that `` `[p]rofessing that an order ameliorates a real industry problem 
but then citing no evidence demonstrating that there is in fact an 
industry problem is not reasoned decisionmaking.'' ' \833\
---------------------------------------------------------------------------

    \829\ Duke/Progress Energy supplemental coments at 21 (quoting 
Transmission Access Policy Study Group v. FERC, 225 F.3d 667, 688 
(D.C. Cir. 2000) (TAPS)).
    \830\ 468 F.3d 831, 840 (D.C. Cir. 2006) (National Fuel).
    \831\ 969 F.2d 1187 (D.C. Cir. 1992) (Tenneco).
    \832\ Duke/Progress Energy supplemental comments at 22 (quoting 
National Fuel, 468 F.3d at 840).
    \833\ National Fuel, 468 F.3d at 843-44.
---------------------------------------------------------------------------

    740. According to Duke/Progress Energy, the commenters favoring a 
``must offer'' requirement ``have presented no evidence whatsoever to 
support the conclusion that any systemic discrimination is occurring or 
that any party is suffering any actual harm under the discrimination 
theory they have posited.'' \834\ Duke/Progress Energy offer several 
examples where they have sold power to LSEs within their control areas 
after the Commission imposed cost-based mitigation for those sales as 
evidence that there is no basis for expecting mitigated utilities to 
abandon long-standing customers and ``decades of intersystem 
coordination and mutual assistance, whereby utilities take whatever 
measures are possible * * * to help their neighbors maintain 
reliability.'' \835\
---------------------------------------------------------------------------

    \834\ Duke/Progress Energy supplemental comments at 23 (citing 
TAPS, 225 F.3d at 688, (emphasis in original)); see also Xcel reply 
comments at 6-7 (parties have not provided any supporting rationale 
that would justify a ``must offer'' requirement over other potential 
purchasers); EEI supplemental comments at 3 (commenters have failed 
to demonstrate that there is discrimination warranting generic 
action).
    \835\ Duke/Progress Energy supplemental comments at 17 and n.7.
---------------------------------------------------------------------------

    741. A number of commenters assert that the Commission's statutory 
authority to require wholesale sales under section 202(b) and 202(c) of 
the FPA is limited and cannot justify the imposition of a ``must 
offer'' requirement in this context.\836\ Southern explains that the 
Commission has forced power sales by a jurisdictional public utility to 
wholesale customers under section 202(b) of the FPA only if such 
customers have proven they lack service alternatives. Southern states 
that it would be unreasonable to impose a generic obligation to serve 
at wholesale by means of a ``must offer'' requirement, absent 
particularized findings based on a properly developed record that 
wholesale customers lack reasonable alternatives.\837\
---------------------------------------------------------------------------

    \836\ See, e.g., Pinnacle at 8; EEI at 35-36; Progress Energy 
reply comments at 5, n.5; Duke reply comments at 6.
    \837\ Southern at 60.
---------------------------------------------------------------------------

    742. EEI agrees that the Commission's section 202(b) authority is 
clearly aimed at individual transactions where a wholesale customer 
cannot access supply, with ample due process safeguards to ensure that 
a requirement to sell is truly warranted and will not

[[Page 39992]]

harm the seller.\838\ EEI states that the Commission cannot turn such a 
provision into a blanket regulatory requirement without violating the 
intent of Congress and inappropriately bypassing these safeguards, nor 
is such a blanket requirement warranted.\839\
---------------------------------------------------------------------------

    \838\ EEI reply comments at 16.
    \839\ EEI at 35-36 (citing El Paso Electric Co. v. FERC, 201 
FERC F.3d 667 (5th Cir. 2000)).
---------------------------------------------------------------------------

    743. Several commenters question the legal support for a ``must 
offer'' requirement, arguing that the FPA does not contain an express 
obligation to serve wholesale customers,\840\ and that neither section 
205 nor section 206 of the FPA authorize the Commission to mandate or 
prohibit sales, as long as they are made at just, reasonable, and non-
discriminatory rates approved by the Commission.\841\
---------------------------------------------------------------------------

    \840\ MidAmerican at 18-19; EEI at 33; Southern at 59; Westar at 
17; Duke at 12; E.ON U.S. reply comments at 1-2; Progress at 13.
    \841\ EEI at 35; Progress Energy at 13-14; E.ON U.S. reply 
comments at 1-2; Duke reply comments at 5-6.
---------------------------------------------------------------------------

    744. Many commenters also contest claims that sales outside the 
mitigated control area at market-based rates constitute withholding or 
undue discrimination. Westar and others suggest that offering 
generation for sale outside of the mitigated control area at the 
prevailing market price to serve demand does not constitute 
withholding. They state that withholding generally refers to either 
physical withholding (not offering to sell) or economic withholding 
(offering to sell only at inflated prices), which in either case is 
intended to raise prices.\842\ Duke/Progress Energy claim that ``the 
Commission has confirmed that it is `legitimate economically rational' 
behavior for a market participant to export power in order to sell at 
higher prices outside a control area rather than to sell at lower 
capped prices within a control area.'' \843\ Westar similarly argues 
that, absent evidence of manipulation or fraud, a `` `seller of a 
commodity is acting quite rationally and legally to withhold his supply 
from the market if he believes that in the future the commodity will 
command a higher price--assuming, of course, the seller is under no 
legal duty to sell.' '' \844\ Westar and E.ON U.S. reason that the 
Commission's market behavior rules already address economic withholding 
concerns.\845\
---------------------------------------------------------------------------

    \842\ EEI reply at 2; Duke/Progress Energy at 15.
    \843\ Duke/Progress Energy at supplemental comments 16 (quoting 
San Diego Gas & Elec. Co., 103 FERC ] 61,345 at P 63 (2003)).
    \844\ See Westar at 11, n.23 (quoting United States v. Reliant 
Energy Services Co., 420 F. Supp. 2d 1043, 1059 (N.D. Cal. 2006)); 
see also EEI at 36.
    \845\ Westar at 12; E.ON U.S. reply comments at 7. In adopting 
those rules, Westar submits that the Commission specifically 
rejected arguments that ``withholding for an anti-competitive 
purpose can only be remedied by way of a generic ``must offer'' 
obligation,'' stating that ``[i]n fact, where a seller intentionally 
withholds capacity for the purpose of manipulating market prices, 
market conditions, or markets rules for electric energy or 
electricity products, it has done so without a legitimate business 
purpose in violation of Market Behavior Rule 2.'' Westar at 12 
(quoting Investigation of Terms and Conditions of Public Utility 
Market-Based Rate Authorizations, 107 FERC ] 61,175 at P 27 (2004) 
(emphasis added)).
---------------------------------------------------------------------------

    745. MidAmerican adds that in the limited instances where a 
wholesale customer cannot obtain service, and where an obligation to 
serve exists, the Commission can address the issue in fact-specific 
proceedings of individual sellers.\846\ Duke suggests that the ``must 
offer'' proponents have failed to demonstrate why ``self-supply,'' 
including new construction and supply from external resources, is not a 
viable option in at least some instances.\847\ Duke states, for 
example, that the Carolina Agencies submit that LSEs will have few if 
any practical supply options if a mitigated supplier is not subject to 
a must offer requirement. However in Duke's view, the Carolina Agencies 
fail to demonstrate why ``self-supply,'' including construction of 
local generation by their members, is not a viable option in at least 
some instances. Nor do they demonstrate lack of ability to secure 
supply from resources external to the control area. Duke submits that 
even where construction of new generation may not be cost-effective, 
``self-supply'' includes purchasing as well as self-build. Duke argues 
that lack of an economic self-build option at a given time does not 
relieve an LSE of its obligation to acquire generation resources 
through alternate means such as long-term purchases.\848\
---------------------------------------------------------------------------

    \846\ MidAmerican at 19.
    \847\ Duke reply comments at 10. APPA/TAPS responds that the 
Commission has recognized that not all LSEs can build their own 
generation. APPA/TAPS reply comments at 9 (citing April 14 Order, 
107 FERC ] 61,018 at P 155).
    \848\ Duke reply comments at 10.
---------------------------------------------------------------------------

    746. Several commenters similarly challenge the claim that choosing 
to make sales outside the mitigated control area at market-based rates 
is discriminatory. EEI notes that not all rate distinctions are 
prohibited by section 205(b) of the FPA. It states that only undue 
discrimination between customers of the same class that is not 
justified by cost of service differences, operating conditions, or 
other considerations is forbidden.\849\ In this proceeding, Duke/
Progress Energy claim that wholesale customers are seeking a superior 
product to that offered to other customers outside the mitigated 
control area: ``a Commission-enforced right to a free and unilateral 
call option to buy any available energy generated by [m]itigated 
[u]tility assets at cost-based prices, exercisable during peak periods 
when market prices are high.'' \850\
---------------------------------------------------------------------------

    \849\ EEI reply comments at 13-14 (citations, including 
Wisconsin Michigan Power Co., 31 FPC 1445 (1964); CED Rock Springs 
LLC, 116 FERC ] 61,163 at P 39 (2006) (In examining potential undue 
discrimination, the Commission properly focuses on whether ``there 
are any similarly situated projects that have been treated 
differently.''); see also Badger Power Marketing Authority, 116 FERC 
] 61,200 at P 10 (2006) (approving a rate that is essentially the 
same as the rate charged another similarly-situated customer)).
    \850\ Duke/Progress Energy supplemental comments at 9.
---------------------------------------------------------------------------

    747. EEI adds that the courts also recognize that the just and 
reasonable standard allows--and can even require--rate differences to 
reflect different locations and classes of customers.\851\ EEI and 
Progress Energy therefore contend that, once the Commission has 
determined whether a seller may sell at market-based rates or must use 
mitigated rates in various markets, the seller must be allowed to sell 
electricity at the just and reasonable rates approved for the different 
markets.\852\
---------------------------------------------------------------------------

    \851\ EEI reply comments at 14-15 (citing Town of Norwood, 
Massachusetts v. FERC, 202 F.3d 392 at 402 (1st Cir. 2000) 
(``[D]ifferential treatment does not necessarily amount to undue 
preference where the difference in treatment can be explained by 
some factor deemed acceptable by the regulators (and the 
courts).''); City of Vernon, California v. FERC, 983 F.2d 1089 at 
1093 (D.C. Cir. 1993)).
    \852\ Id. at 15; Progress Energy at 13.
---------------------------------------------------------------------------

    748. MidAmerican claims that customer concerns that a mitigated 
seller will unduly discriminate between the seller's native load and 
wholesale customers in the mitigated region are baseless because the 
Commission's jurisdiction does not extend to a comparison of retail and 
wholesale rates. MidAmerican states that while a seller typically has 
an obligation to serve retail customers in a franchised service area, 
that obligation does not extend to wholesale customers. Therefore, 
MidAmerican states there is no issue of undue discrimination between 
retail and wholesale rates that either requires or allows a ``must 
offer'' requirement.\853\
---------------------------------------------------------------------------

    \853\ MidAmerican reply comments at 7; see also, Duke reply 
comments at 6. Compare APPA/TAPS reply comments at 3 (``The 
Commission is not called upon to decide a struggle between wholesale 
and retail ratepayers, but to set a just and reasonable wholesale 
rate, which a Commission-approved cost-based rate surely is.'').
---------------------------------------------------------------------------

    749. Xcel and others submit that wholesale customers are seeking a 
preference or entitlement through a ``must offer'' requirement and are 
in fact calling for discrimination by asserting a preference to power 
available for sale by a mitigated seller over all other

[[Page 39993]]

purchasers, even those who value it more highly,\854\ and have provided 
no evidence to justify such a preference or entitlement over other 
potential purchasers.\855\ Duke/Progress Energy state that customer 
claims that ``they are victims of market power and therefore need some 
specially tailored remedy'' is erroneous, and that ``[b]y imposing 
cost-based rates * * * within their control area, the Commission has 
fully mitigated any market power concerns.'' \856\ Xcel and others also 
note that the LSEs have no reciprocal obligation to purchase power if a 
``must offer'' requirement were imposed upon mitigated sellers.\857\
---------------------------------------------------------------------------

    \854\ Xcel reply at 6-7; EEI supplemental comments at 4-5.
    \855\ Xcel reply comments at 6-7; Progress Energy reply comments 
at 2, 4, 7-11; Duke reply comments at 7, n.10.
    \856\ Duke/Progress Energy supplemental comments at 13 (citing 
Duke Power, 113 FERC ] 61,192 at P 22).
    \857\ Xcel reply comments at 7; Progress Energy reply comments 
at 6; MidAmerican reply comments at 9.
---------------------------------------------------------------------------

    750. According to Duke and others, when a mitigated supplier sells 
excess generation at market-based rates outside of the mitigated 
control area, it is exhibiting economic behavior.\858\ Such behavior 
encourages trading within and across regions, making markets more 
competitive. Similarly, Westar contends that a ``must offer'' 
requirement prevents markets from allocating scarce resources to 
customers who value them the most, hindering optimal resource 
allocation.\859\ Westar states that this is inefficient because ``the 
highest cost generation may not be displaced by the seller's lower cost 
energy.'' \860\
---------------------------------------------------------------------------

    \858\ Duke at 11; Xcel at 6; Southern at 56-57; EEI reply 
comments at 11.
    \859\ Westar at 13 (citing Pacific Gas and Electric Company, 38 
FERC ] 61,242 at 61,790 (1987)).
    \860\ Id. (quoting Pacific Gas and Electric Company, 38 FERC at 
61,790, n.19).
---------------------------------------------------------------------------

    751. EEI, Progress Energy, and others also claim that a ``must 
offer'' requirement would effectively take economic benefits away from 
the mitigated utility's retail native load and transfer them to 
wholesale customers in the mitigated control area.\861\ Some of these 
commenters claim that a ``must offer'' requirement may result in a 
windfall for the wholesale customer originally seeking protection from 
the seller's market power at the expense of the mitigated utility and 
its native load customers.\862\ PNM/Tucson adds that sales made by a 
utility pursuant to a ``must offer'' requirement could affect 
reliability by making capacity unavailable to meet State-established 
reserve margins.\863\
---------------------------------------------------------------------------

    \861 \ See, e.g., EEI at 33; Progress Energy at 14, 16; Entergy 
at 2; Westar at 16; see also Dr. Pace at 24-25.
    \862\ PPL reply comments at 14; Duke reply comments at 2, 7-8; 
Progress Energy at 16; E.ON U.S. at 13-14; Duke at 12-13; 
MidAmerican at 27.
    \863\ PNM/Tucson at 18.
---------------------------------------------------------------------------

    752. Xcel and Duke point out that a ``must offer'' requirement at 
cost-based rates may result in a lost opportunity cost to the 
seller.\864\ A number of commenters assert that mitigation is intended 
to assure that selling utilities do not benefit from the exercise of 
market power; it is not to guarantee preferential treatment for 
particular customers to obtain below-market generation through an 
obligation to serve.\865\
---------------------------------------------------------------------------

    \864\ Xcel at 8; Duke reply comments at 3, n.4.
    \865\ Xcel at 5; EEI reply comments at 10, 12; Progress Energy 
at 14.
---------------------------------------------------------------------------

    753. Some commenters further contend that a ``must offer'' 
requirement would create significant wealth transfers from mitigated 
sellers as a result of arbitrage opportunities. For example, wholesale 
customers would accept the mitigated offer any time the ``must offer'' 
price was below the market price, either in or outside of the mitigated 
region.\866\ E.ON U.S. is concerned that a ``must offer'' requirement 
giving a buyer the option to buy power at mitigated prices will 
inevitably result in external third parties negotiating with such a 
buyer to obtain longer-term access to the mitigated power.\867\
---------------------------------------------------------------------------

    \866\ Progress Energy at 16; Westar at 16.
    \867\ E.ON U.S. at 13.
---------------------------------------------------------------------------

    754. In addition, EEI and others argue that a ``must offer'' 
requirement would reduce competition and stifle development by 
providing a disincentive for sellers to develop new generation 
resources.\868\ New entrants would be deterred from building generation 
due to the disparity between cost-based and market-based rates; \869\ 
other sellers in the mitigated region effectively would be mitigated 
because they would not be selected by buyers unless their price is 
below the mitigated price of the ``must offer'' requirement.\870\ At 
the same time, EEI asserts that the mitigated seller would perpetuate 
its market power by increasing its capacity in the mitigated control 
area.\871\
---------------------------------------------------------------------------

    \868\ EEI at 37; Progress Energy at 16; MidAmerican at 22. APPA/
TAPS responds that it is in fact the mitigated seller's constrained 
transmission system that keeps LSEs captive and prevents new entry 
that could reduce the seller's market power. APPA/TAPS reply 
comments at 9.
    \869\ EEI reply comments at 10.
    \870\ MidAmerican reply comments at 8.
    \871\ EEI reply comments at 10.
---------------------------------------------------------------------------

    755. Progress Energy and MidAmerican add that a ``must offer'' 
requirement would impede a mitigated seller's ability to fulfill its 
retail crediting obligations and to provide adequate and reliable 
service to its native load retail customers, which bear, through their 
retail rates, the fixed costs of the generation to serve them.\872\
---------------------------------------------------------------------------

    \872\ See, e.g., Progress Energy at 14-15; E.ON U.S. at 12-13; 
PNM Tucson at 18; MidAmerican at 21.
---------------------------------------------------------------------------

    756. Southern, Duke and others further suggest that a ``must 
offer'' requirement could undermine the required planning and 
operations processes of utility systems purchasing the ``must offer'' 
output.\873\ They argue that a ``must offer'' requirement could bias 
shorter-term operating decisions where, for example, an LSE has the 
opportunity to purchase peak supply in real time at less than market 
prices, thereby avoiding incurring any fixed costs on a day-ahead basis 
to ensure peak supply availability.\874\ They contend that this would 
eliminate incentives for the LSEs to plan to meet their resource needs 
and shift planning obligations at the expense of a mitigated utility's 
native load customers.\875\
---------------------------------------------------------------------------

    \873\ Southern at 61; Progress Energy at 16; Duke reply comments 
at 9-10; EEI reply comments at 10-11.
    \874\ Southern at 63.
    \875\ Duke reply comments at 8-11. APPA/TAPS counters that where 
a ``must offer'' requirement would not, by its own terms, obligate a 
seller to build, an LSE that relied exclusively on ``must offer'' 
sales would be taking risks that capacity to support those sales 
might no longer be available. APPA/TAPS reply comments at 9.
---------------------------------------------------------------------------

    757. Another commenter is also wary of a ``must offer'' 
requirement, reasoning that such a requirement is normally designed to 
mitigate physical withholding. This commenter states that it may work 
well in an organized power market where an independent operator ensures 
that the power is used to serve the local needs caused by reliability 
or local resource deficiency. However, without an independent operator, 
a ``must offer'' requirement may be more difficult to administer.\876\ 
In advocating for separate market policies and tests for short- and 
long-term markets, this commenter prefers a price cap for short-term 
products rather than a ``must offer'' requirement, asserting that a 
price cap for short-term products is preferable to a ``must offer'' 
approach because it is more economically efficient, fair, and easier to 
administer.\877\ For long-term products, this commenter takes the 
position that, ``[i]n situations where a lack of long-term transmission 
and/or a lack of long-term supply alternatives exist, it is difficult 
to think of an

[[Page 39994]]

alternative to full cost-of-service rates.'' \878\ They add that these 
cost-based rates should offer both fair prices and adequate investment 
returns to suppliers in the destination market with rate-of-return 
levels that fully enable incumbent suppliers to make appropriate 
investments to meet such cost-based obligations.\879\
---------------------------------------------------------------------------

    \876\ Drs. Broehm and Fox-Penner at 16-17.
    \877\ Drs. Broehm and Fox-Penner supplemental comments at 3. 
Drs. Broehm and Fox-Penner advocate other approaches, such as use of 
a proxy price when transmission constraints are not binding and use 
of default cost-based rates when they are binding.
    \878\ Id.
    \879\ Id.
---------------------------------------------------------------------------

    758. Entergy raises a concern that in the NOPR the Commission erred 
by failing to define what constitutes available capacity. It asserts 
that there is difficulty in calculating available capacity because of 
uncertainty regarding: (1) Loads; (2) qualifying facility puts; (3) 
unit performance; and (4) fuel arrangements and prices.\880\
---------------------------------------------------------------------------

    \880\ Entergy at 2-3.
---------------------------------------------------------------------------

Commission Determination
    759. After careful consideration of the arguments raised by 
commenters, we will not impose an across-the-board ``must offer'' 
requirement for mitigated sellers. While wholesale customer commenters 
have raised concerns relating to their ability to access needed power, 
we conclude that there is insufficient record evidence to support 
instituting a generic ``must offer'' requirement.
    760. As discussed above, some commenters argue that undue 
discrimination occurs if a mitigated seller refuses to sell power to 
customers in the mitigated balancing authority area and instead sells 
that power at market-based rates to customers outside the mitigated 
balancing authority area. Some commenters also contend that it is 
unduly discriminatory for a mitigated seller to make market-based rate 
sales to competitive markets outside the mitigated balancing authority 
area when constraints on that seller's own transmission system prevent 
embedded customers from similarly accessing those markets as buyers. 
However, these commenters have not provided any evidence of specific 
instances in which the harms they identify have, or are, occurring. 
Without such evidence, we decline to impose a generic remedy such as a 
``must offer'' requirement.
    761. In National Fuel, the D.C. Circuit vacated a final rule of the 
Commission, Order No. 2004, as applicable to natural gas pipelines 
because of the expansion of the standards of conduct to include a new 
definition of energy affiliates. The court explained that the 
Commission relied on both theoretical grounds and on record evidence to 
justify this expansion. The court concluded that the Commission's 
record evidence did not withstand scrutiny and, thus, concluded the 
expansion was arbitrary and capricious in violation of the 
Administrative Procedure Act.\881\ While the court left open the 
possibility of the Commission relying solely on a theoretical threat of 
abuse, it cautioned that if the Commission chooses to take that 
approach, ``it will need to explain how the potential danger * * * 
unsupported by a record of abuse, justifies such costly prophylactic 
rules.'' \882\ In addition, the court said the Commission would need to 
explain why individual complaint procedures were insufficient to ensure 
against abuse.\883\
---------------------------------------------------------------------------

    \881\ National Fuel, 468 F.3d at 844.
    \882\ Id.
    \883\ Id.
---------------------------------------------------------------------------

    762. We find here that, although wholesale customer commenters have 
raised theoretical concerns that they will be unable to access power 
absent a ``must offer'' requirement, they have not provided any 
concrete examples of harm nor explained how the potential harm 
justifies the generic remedy they seek. Given the lack of evidence in 
the record that wholesale customers in mitigated markets will be unable 
to obtain power supplies at reasonable rates, we conclude that there is 
insufficient basis for instituting a generic ``must offer'' 
requirement. Indeed, the record includes evidence of utilities 
continuing to make cost-based sales after loss or surrender of market-
based rate authority.\884\
---------------------------------------------------------------------------

    \884\ See Duke reply comments at 7 and n.10; Progress Energy 
reply comments at 9-11; Duke/Progress Energy supplemental comments 
at 17 and n.7.
---------------------------------------------------------------------------

    763. In addition, consistent with the guidance provided in National 
Fuel, commenters advocating a generic ``must offer'' have not 
demonstrated that existing procedures and remedies under the FPA are 
inadequate to deal with specific cases that may arise. To the contrary, 
we find that there are potential remedies available on a case-by-case 
basis to a wholesale customer alleging undue discrimination or other 
unlawful behavior on the part of a mitigated seller. For example, a 
wholesale customer can file a complaint pursuant to section 206 of the 
FPA. It also can bring an action under section 202(b) of the FPA.\885\ 
In addition, it can bring an action pursuant to the statutory 
prohibition in section 222 of the FPA against market manipulation.
---------------------------------------------------------------------------

    \885\ See, e.g, City of Las Cruces, New Mexico v. El Paso 
Electric Co., 87 FERC ] 61,220 (1999) (``In our view, section 202(b) 
allows the Commission to direct a public utility to take three 
separate actions: (1) Establish a physical connection of its 
transmission facilities with the facilities of one or more eligible 
persons; (2) sell energy to eligible persons; or (3) exchange energy 
with eligible persons.'')
---------------------------------------------------------------------------

    764. While we do not impose a generic ``must offer'' requirement in 
this Final Rule, we do not rule out the possibility that we might find 
the imposition of a ``must offer'' requirement, or some other condition 
on the seller's market-based rate authority, to be an appropriate 
remedy in a particular case depending on the facts and circumstances, 
as we have done in the past.\886\ We note that the Commission has 
previously imposed a ``must offer'' requirement as a condition of 
market-based rate authority for sellers in the California markets.\887\ 
There, the record demonstrated a problem in a limited geographic area 
that warranted a ``must offer'' remedy to prevent unjust and 
unreasonable rates from being charged during certain times and under 
certain conditions. If a wholesale customer were to present specific 
evidence documenting that a transmission provider either denied the 
customer's request for transmission service, in violation of the OATT, 
or was unreasonably delaying responding to a request for transmission 
service, in violation of the OATT, we might find the imposition of a 
``must offer'' requirement on a transmission provider to be an 
appropriate remedy.\888\ As the Commission recently explained in Order 
No. 890, transmission providers must process requests for transmission 
service ``as soon as reasonably practicable after receipt'' of such 
requests \889\ and must post performance metrics that are intended ``to 
enhance the transparency of the study process and shed light on whether 
transmission providers are processing request studies in a non-
discriminatory manner.'' \890\ Order No. 890 explained that ``the 
revised pro forma OATT will greatly enhance our oversight and 
enforcement capabilities by increasing the transparency of many 
critical functions

[[Page 39995]]

under the pro forma OATT, such as ATC calculation and transmission 
planning.'' \891\ Here too, we reiterate that 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.'' \892\
---------------------------------------------------------------------------

    \886\ If an intervenor believes a ``must-offer'' requirement is 
the only way to mitigate market power, it may present evidence to 
that effect in a particular proceeding.
    \887\ See San Diego Gas & Elec. Co., 95 FERC ] 61,418 at 62,557 
(2001) (``After carefully considering the record, the Commission 
reaffirmed its general finding that, as a result of the seriously 
flawed electric market structure and rules for wholesale sales of 
electric energy in California, unjust and unreasonable rates were 
charged and could continue to be charged during certain times and 
under certain conditions, unless certain targeted remedies were 
implemented.'')
    \888\ We are not prejudging here that such facts warrant 
imposition of a ``must offer'' requirement.
    \889\ Preventing Undue Discrimination and Preference in 
Transmission Service, Order No. 890, FERC Stats. & Regs. ] 31,241 at 
P 1296 (2007) (Order No. 890).
    \890\ Id. at P 1308.
    \891\ Id. at P 1721.
    \892\ Id. at P 1714.
---------------------------------------------------------------------------

    765. In addition to our conclusion that there is not sufficient 
record evidence to support the imposition of a generic ``must offer'' 
requirement, we are also concerned that adoption of a ``must offer'' 
requirement would present a number of difficult implementation and 
logistical problems.\893\
---------------------------------------------------------------------------

    \893\ Because we have decided not to impose a generic ``must 
offer'' requirement in this Final Rule, we do not address the merits 
of the particular must-offer proposals made by commenters.
---------------------------------------------------------------------------

    766. For example, given the difficulties associated with 
calculations of available transfer capability,\894\ we foresee similar 
disputes over the calculation of available generation capacity were we 
to impose a generic ``must offer'' obligation. For instance, how far in 
advance should such calculations occur--one hour, one day, one month, 
or some other time frame? Would such calculations be derived on a 
generator specific basis or on a system basis (and how is transmission 
factored in)? Would the Commission or the industry need to develop a 
standard method of calculating available generation capacity? How would 
available generation capacity be allocated to potential purchasers?
---------------------------------------------------------------------------

    \894\ OATT Reform NOPR at PP 37-41 (outlining problems that 
result from inconsistent available transfer capacity calculation, 
including missed opportunities for transactions, frequent errors, 
and undue discrimination).
---------------------------------------------------------------------------

    767. We also are concerned that adopting a ``must offer'' 
requirement could harm other markets. For example, if a mitigated 
seller is required to offer its available power first to customers in 
the mitigated market, such a requirement may effectively preclude the 
mitigated seller from participating in adjoining markets particularly 
at times when additional supply is most needed (i.e., when prices in 
the adjoining market are high). Such a policy may serve to assist one 
set of customers at the expense of other customers that see their 
supply options reduced.
    768. Parties have asserted that imposing a must offer requirement 
may discourage long-term planning, while others have disagreed with 
those arguments. Given that we do not impose any must offer obligation 
in this rule, we need not and do not address these arguments. If the 
Commission considers imposing a ``must offer'' requirement in an 
individual case, affected parties can raise these arguments at that 
time.
    769. Though APPA/TAPS and the Carolina Agencies are correct that 
the Commission has previously imposed a ``must offer'' requirement as a 
condition of market-based rate authority for sellers in the California 
markets, as discussed above, that holding supports our approach here. 
There, the record demonstrated a problem in a limited geographic area 
that warranted a ``must offer'' remedy to prevent unjust and 
unreasonable rates from being charged during certain times and under 
certain conditions. By contrast, here APPA/TAPS and the Carolina 
Agencies urge us to impose a generic remedy on all mitigated sellers in 
all markets without a showing that there is a concrete problem 
justifying imposition of a ``must offer'' requirement in all markets.
    770. Given that we have not adopted a ``must offer'' requirement in 
this Final Rule, we need not, and do not, address arguments asserting 
that we lack legal authority to do so. If the Commission should adopt 
any such requirement in an individual case, affected parties can raise 
any related legal arguments at that time and nothing in this rule 
precludes them from doing so.
    771. For many of the same reasons that we decline to impose a 
``must offer'' requirement, we also decline to adopt the ``right of 
first refusal'' requirement proposed by NRECA. Under this approach, a 
wholesale customer in the mitigated market would be given a right of 
refusal to purchase, at the market price, power that the mitigated 
seller proposes to sell outside the mitigated market. For the reasons 
provided above, there is insufficient record evidence to support 
imposition of such an across-the-board requirement.
    772. A ``right of first refusal'' also would carry significant 
administrative burdens. Such an approach would invite disputes about 
what constitutes a legitimate offer by a third party to purchase power 
which establishes the basis for the offered rate. There also may be 
disputes if more than one wholesale customer wants to purchase the 
power in question. We are also concerned about the long-term viability 
of a rate setting that is based on mitigated sellers repeatedly 
negotiating tentative power sale arrangements with would-be buyers in 
first-tier markets only to have those offers withdrawn so the sale 
could be made to another buyer. Under such a regime, buyers from 
outside the mitigated market may be disinclined to invest resources to 
negotiate tentative contracts knowing that there is a significant 
chance that another buyer from within the mitigated market will usurp 
their position and instead get the sale.
    773. There are also administrative concerns with how the Commission 
or third parties could be certain what the actual price and conditions 
of service would be for the sale in the first-tier market unless the 
contract was actually executed.
    774. In response to NRECA's suggestion that an enforceable 
commitment to provide sufficient additional transmission import 
capacity to mitigate generation market power be considered as an 
alternative, the Commission notes that, consistent with the April 14 
Order, a seller that fails one of the generation market power screens 
is allowed to propose alternative mitigation that the Commission may 
deem appropriate.\895\ As a result, a mitigated seller could propose, 
as alternative mitigation, to provide additional transmission capacity 
by, for example, committing to relinquish transmission reservations or 
to physically upgrade the transmission grid.\896\ The Commission would 
consider such proposals on a case-by-case basis. Moreover, a primary 
purpose of Order No. 890 is to ``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.'' \897\
---------------------------------------------------------------------------

    \895\ April 14 Order, 107 FERC ] 61,018 at P 147, 148 n.142.
    \896\ See, e.g., Westar Energy, Inc., 115 FERC ] 61,228, order 
on reh'g, 117 FERC ] 61,011 (2006), order on further reh'g, 118 FERC 
] 61,237 (2007) (concerning such mitigation proposed in the context 
of a disposition of jurisdictional facilities).
    \897\ Order No. 890, FERC Stats. & Regs. ] 31,241 at P 3.
---------------------------------------------------------------------------

    775. In particular, we believe recent actions we took in Order No. 
890 address the Carolina Agencies' proposal that mitigated utilities be 
required to investigate and report on transmission expansion or other 
actions that could remove structural impediments exacerbating market 
power. In Order No. 890, the Commission adopted a number of reforms 
designed to mitigate transmission market power, including a requirement 
that all transmission providers develop a coordinated, open and 
transparent transmission planning process that would, among other 
things, enable customers to request studies evaluating potential 
upgrades or other investments that could reduce congestion or integrate 
new resources and loads.\898\ The requests for these

[[Page 39996]]

economic planning studies and the responses will be posted on the 
transmission provider's OASIS site, subject to confidentiality 
requirements.\899\ We believe these steps may assist in reducing 
structural impediments that contribute to market power.
---------------------------------------------------------------------------

    \898\ Id. at P 544.
    \899\ Id. at P 546 (to be codified at 18 CFR 37.6(b)(2)(iii)).
---------------------------------------------------------------------------

b. First-Tier Markets
Commission Proposal
    776. In the NOPR, the Commission sought comment on whether it is 
appropriate to continue to allow sellers that are subject to mitigation 
in their home control area to sell power at market-based rates outside 
their control area. The Commission asked if this represents undue 
discrimination or otherwise constitutes ``withholding'' in the home 
control area that is inconsistent with the FPA's mandate that rates be 
just, reasonable and not unduly discriminatory, or, instead, if this 
reflects economically efficient behavior and encourages necessary 
trading within and across regions, particularly in peak periods when 
marginal prices rise above average embedded costs.
    777. The Commission also asked if it should find that any seller 
that has lost market-based rate authority in its home control area 
should be precluded from selling power at market-based rates in 
adjacent (first tier) control areas.
Comments
    778. A number of commenters state that there is no basis for 
prohibiting a mitigated seller from selling excess power at market-
based rates in adjacent control areas, as the Commission will have 
determined that the seller does not have the ability to exercise market 
power in any of those adjacent control areas.\900\ Some commenters also 
claim that prohibiting these sales would limit market activity and 
constrain the benefits of competitive pricing by excluding sellers from 
markets in which they do not possess market power.\901\
---------------------------------------------------------------------------

    \900\ Ameren at 18-19; see also Duke at 12 (citing Florida Power 
Corp., 113 FERC ] 61,131 at P 24 (2005)); Southern at 56; PNM/Tucson 
at 19-20 ; Xcel at 5-6; EEI at 33; and PPL reply comments at 15-16.
    \901\ MidAmerican at 22-23; PPL at 24-25; EEI at 28.
---------------------------------------------------------------------------

    779. PNM/Tucson contends that prohibiting sales of available 
capacity at market-based rates in adjacent control areas where the 
seller does not possess market power would be a disproportionate 
response that would render the Commission's market-by-market analysis 
meaningless.\902\ Moreover, PNM/Tucson and MidAmerican warn that 
independent power producers have no incentive to invest in new 
resources in markets where prices are effectively constrained to the 
level of another entity's embedded costs.\903\
---------------------------------------------------------------------------

    \902\ PNM/Tucson at 19-20.
    \903\ MidAmerican at 22, PNM/Tucson at 17.
---------------------------------------------------------------------------

    780. Southern asks the Commission not to impose mitigation that 
will create flaws in markets that may have periods of genuine temporary 
scarcity but where the seller does not possess market power.\904\ 
Southern states that prohibiting a mitigated seller from responding to 
price signals in neighboring markets will adversely affect efficient 
resource development and contradicts the Commission's desire to promote 
competitive markets and resource adequacy.\905\ Further, foreclosing 
markets otherwise accessible to resources nominally dedicated to native 
load service may impair the optimization of those resources by 
impairing a full response to price signals. This, Southern adds, would 
harm native load customers because the mitigated utility would be 
unable to optimize surplus resources, as mandated through State retail 
credit obligations, thereby depriving retail customers of the benefits 
of system optimization.\906\
---------------------------------------------------------------------------

    \904\ Southern at 64-65.
    \905\ Id. at 57.
    \906\ Id.
---------------------------------------------------------------------------

    781. Another commenter agrees that a mitigated seller should be 
allowed to sell available capacity at market-based rates in markets 
where that seller does not possess market power, provided that this 
does not raise prices in the mitigated region.\907\ This commenter 
asserts that such sales facilitate regional trading and market 
efficiency in developing competitive markets.\908\ Another commenter 
contends that unless ``costs'' are defined in a way that effectively 
allows competitive market rates to be charged, revoking a seller's 
market-based rate authority in markets where the seller does not 
possess market power would reduce the mitigated seller's incentive to 
supply available power to the market, deprive the mitigated seller and 
its customers of legitimate economic rent, subsidize those buyers with 
access to the mitigated rates, and create a rationing problem among 
buyers with access to the mitigated-rate power.\909\
---------------------------------------------------------------------------

    \907\ Drs. Broehm and Fox-Penner at 16. The NYISO also supports 
market-based rate sales in competitive markets where the mitigated 
seller does not possess market power. According to the NYISO, with 
regard to the NYISO, PJM Interconnection, LLC and ISO-New England, 
the Commission can ensure that sellers respond to market price 
signals by designing market power mitigation in a manner that will 
permit even mitigated sellers to receive the applicable market 
clearing price. For example, any cost-based rate mitigation imposed 
could limit the maximum bids that the seller may submit without 
limiting the revenues that the mitigated seller may receive. NYISO 
at 10.
    \908\ Drs. Broehm and Fox-Penner at 16. See also PPL at 24; 
MidAmerican at 17; E.ON U.S. at 12-13; EEI at 28; Duke at 11.
    \909\ Dr. Pace at 21.
---------------------------------------------------------------------------

    782. MidAmerican states that, if the Commission were to eliminate a 
seller's market-based rate authority in all regions, the mitigated 
prices should only apply prospectively. MidAmerican reasons that 
existing transactions negotiated in the absence of market power should 
not be altered, since these previously-negotiated transactions would 
have no impact on a seller's willingness to make future sales to 
customers in the home control area.\910\
---------------------------------------------------------------------------

    \910\ MidAmerican at 23.
---------------------------------------------------------------------------

    783. Other commenters oppose allowing mitigated sellers to sell at 
market-based rates outside the home control area on the basis that it 
encourages and provides incentives for the seller to engage in physical 
or economic withholding of its generation output in the home control 
area. These commenters indicate that their concerns in this regard 
would be addressed if mitigation is combined with a requirement that 
the mitigated seller make power available to customers within the 
mitigated control area. APPA/TAPS state that, absent a ``must offer'' 
requirement, it is not clear that prohibiting mitigated sellers from 
making market-based sales outside their home control areas would 
necessarily prompt the mitigated seller to sell power in its home 
control area.\911\
---------------------------------------------------------------------------

    \911\ APPA/TAPS at 43.
---------------------------------------------------------------------------

    784. However, APPA/TAPS ask the Commission not to rule out across-
the-board revocation of market-based rate authority as it may be 
necessary to motivate mitigated sellers to undertake the kind of 
structural measures needed to mitigate market power on a long-term 
basis. If the Commission adopts a policy to revoke or condition market-
based rate authority beyond the home control area, APPA/TAPS state that 
the policy should not be limited to just the first-tier control area. 
Rather, the revocation or conditions should apply to any market where 
the seller can use generation located in or originally delivered to its 
control area to sell outside that mitigated area.\912\
---------------------------------------------------------------------------

    \912\ APPA/TAPS at 43-44.
---------------------------------------------------------------------------

    785. The Carolina Agencies state that a generic prohibition on 
market-based rate sales outside the mitigated market

[[Page 39997]]

appears likely to inhibit regional trade to a greater extent than is 
necessary to protect the interests of embedded LSEs.\913\ Both the 
Carolina Agencies and NC Towns state that there is no clear need to 
prohibit mitigated sellers from making market-based sales outside their 
home control areas if a ``must offer'' requirement is adopted.\914\ 
According to the Carolina Agencies, a mitigated seller should be free 
to engage in market-based rate sales in other control areas as long as 
that utility has provided embedded LSEs a reasonable opportunity to 
purchase capacity and/or energy.
---------------------------------------------------------------------------

    \913\ Carolina Agencies at 19.
    \914\ Id. at 18-19; NC Towns at 7.
---------------------------------------------------------------------------

    786. As to any claim that it would be unduly discriminatory for the 
Commission to deny or condition the market-based rate authority of a 
utility that passes the screens in markets beyond its mitigated home 
control area, APPA/TAPS and the Carolina Agencies submit that mitigated 
sellers are not similarly-situated to the other utilities selling at 
market-based rates in those other competitive markets. They assert that 
other sellers' market-based rate sales do not implicate those sellers' 
ability to withhold supply from disfavored wholesale customers in a 
mitigated control area. Moreover, they argue that it elevates the 
importance of the screens above the FPA to argue that granting 
unconditioned market-based rate authority to one seller who passes the 
screens obligates the Commission to grant unconditioned authority to 
all who pass the screens. In their view, the Commission would be 
failing its duty under the FPA if it permitted physical withholding by 
a dominant utility, as such actions would be unjust, unreasonable, and 
unduly discriminatory.\915\
---------------------------------------------------------------------------

    \915\ APPA/TAPS and Carolina Agencies supplemental comments at 
36-37. NRECA adds that ``the FPA does not bar--as unduly 
discriminatory--Commission imposition of remedies in a non-
discriminatory fashion, including banning sales outside the 
mitigated market: the statute protects buyers, not sellers, from 
undue discrimination.'' NRECA reply comments at 41; see also 
Carolina Agencies at 16 (citing the OATT Reform NOPR at P 210 and 
n.203).
---------------------------------------------------------------------------

    787. ELCON advocates suspending any mitigated seller's market-based 
rates in all markets it can access. Short of this long-term fix, ELCON 
asserts that other proposals such as ``must offer'' requirements will 
be prone to fail because of likely unintended consequences.\916\
---------------------------------------------------------------------------

    \916\ ELCON at 11.
---------------------------------------------------------------------------

    788. Morgan Stanley favors requiring mitigated sellers to post the 
mitigated price and other material terms on a publicly-available Web 
site for all sales to be made from the units that are part of the 
portfolio covered by the Commission's market power finding, regardless 
of where the actual sale sinks.\917\ Morgan Stanley asserts that 
effective mitigation can only occur if it is imposed on all sales from 
a mitigated supplier's generation portfolio and urges the Commission 
not to focus on who the purchaser is or where the power sinks.\918\ If 
a mitigated seller chooses to offer its excess power only outside the 
mitigated region and simply refuses to sell inside its home market, 
Morgan Stanley is concerned that the market in the ``home'' territory 
would be even less competitive than if the seller were allowed to sell 
there on an unmitigated basis.\919\
---------------------------------------------------------------------------

    \917\ Morgan Stanley at 7; Morgan Stanley reply comments at 6.
    \918\ Morgan Stanley reply comments at 6. The Oregon Commission 
responds that such broad mitigation would not benefit wholesale 
customers in the mitigated region and would harm the supplier's 
native retail load by transferring wealth to marketers like Morgan 
Stanley. Oregon Commission reply comments at 4; see also MidAmerican 
reply comments at 13-14 (arguing that Morgan Stanley's proposal 
would be an arbitrary and capricious redistribution of income and 
allow windfall arbitrage profits).
    \919\ Morgan Stanley at 6.
---------------------------------------------------------------------------

    789. CAISO states that, where a competitive supply of imports into 
a mitigated control area does not exist, market power mitigation 
mechanisms or other incentive schemes will be necessary to ensure that 
the local supplier makes all of its capacity available to supply energy 
and ancillary services to the home control area.\920\ CAISO asks the 
Commission to provide greater clarity on the extent to which the 
antifraud and anti-manipulation rules adopted in Order No. 670 prohibit 
economic and physical withholding of resources. In particular, CAISO 
asks the Commission to provide greater clarity on the deceptive conduct 
criteria it would use to determine whether a particular case of 
physical or economic withholding would be a violation of the new Part 
47 regulations. CAISO explains that greater clarity in this area will 
help ISO and RTO market monitors in developing effective RTO/ISO market 
power mitigation rules tailored for the types of physical and economic 
withholding that are not addressed under Part 47 regulations.
---------------------------------------------------------------------------

    \920\ CAISO at 16.
---------------------------------------------------------------------------

Commission Determination
    790. After careful consideration of the arguments raised by 
commenters, we will retain our current policy and limit mitigation to 
the market in which the seller has been found to possess, or chosen not 
to rebut the presumption of, market power. We will not place 
limitations on a mitigated seller's ability to sell at market-based 
rates in balancing authority areas in which the seller has not been 
found to have market power.
    791. The Commission authorizes sales of electric energy at market-
based rates if the seller and its affiliates do not have, or have 
adequately mitigated, horizontal and vertical market power in 
generation and transmission, and cannot erect other barriers to entry. 
As the Commission has explained, ``The consideration of market power is 
important in determining if customers have genuine alternatives to 
buying the seller's product.'' \921\ Commenters favoring revocation of 
a mitigated seller's market-based rate authority in markets where there 
has been no finding of market power, as well as those supporting 
broadening mitigation to first-tier markets, have not provided a 
sufficient legal basis for such a policy. Where the record demonstrates 
that a seller does not have market power in a market, or has adequately 
mitigated any market power, the Commission has authorized such a seller 
to transact under market-based rates.\922\ As the April 14 Order 
explained, ``Market-based rates will not be revoked and cost-based 
rates will not be imposed until there has been a Commission order 
making a definitive finding that the applicant has market power * * *'' 
\923\
---------------------------------------------------------------------------

    \921\ Louisville Gas & Elec. Co., 62 FERC at 61,144.
    \922\ Florida Power Corp., 113 FERC ] 61,131 at P 24.
    \923\ April 14 Order, 107 FERC ] 61.018 at P 149.
---------------------------------------------------------------------------

    792. We recognize that wholesale customer commenters are generally 
concerned that allowing mitigated sellers to sell outside their 
mitigated markets at market-based rates could encourage such sellers 
not to offer generation for sale within the mitigated market. However, 
we agree with the Carolina Agencies that a generic prohibition against 
such sales could inhibit regional trade to a greater extent than 
necessary to protect captive LSEs. We note that even some wholesale 
customer commenters acknowledge that it is not clear that prohibiting 
mitigated sellers from making market-based sales beyond their mitigated 
region would prompt the mitigated seller to sell power in the mitigated 
market. For these reasons, we limit mitigation to the areas in which 
the seller has market power.
    793. For the reasons stated above, we disagree with Morgan 
Stanley's assertion that effective mitigation can only occur if it is 
imposed on all sales from a mitigated seller's generation portfolio. In 
addition, though we appreciate CAISO's request for greater clarity on 
the criteria the Commission

[[Page 39998]]

will use to determine whether economic and physical withholding has 
occurred, such a determination must be made on a case-by-case basis.
c. Sales That Sink in Unmitigated Markets
Commission Proposal
    794. In the NOPR, the Commission stated that some companies have 
proposed limiting mitigation to sales that ``sink in'' the mitigated 
market, that is, so that mitigation would only apply to end users in 
the mitigated market. However, in MidAmerican Energy Company,\924\ the 
Commission stated that limiting mitigation to sales that ``sink in'' 
the mitigated market would improperly limit mitigation to certain 
sales, namely, only to sales to buyers that serve end-use customers in 
the mitigated market. The Commission reasoned that limiting mitigation 
in this manner would improperly allow market-based rate sales within 
the mitigated market to entities that do not serve end-use customers in 
the mitigated market.\925\ The Commission stated that such a limitation 
would not mitigate the seller's ability to attempt to exercise market 
power over sales in the mitigated market and is inconsistent with the 
Commission's direction in the April 14 and July 8 Orders. On rehearing 
of the April 14 Order, it was argued that access to power sold under 
mitigated prices should be restricted to buyers serving end-use 
customers within the relevant geographic market in which the seller has 
been found to have market power. In particular, arguments were made 
that a seller should not be required to make sales at mitigated prices 
to power marketers or brokers without end-use customers in the relevant 
market. In the July 8 Order, the Commission rejected the suggestion 
that mitigated sellers be restricted to selling power only to buyers 
serving end-use customers, and has since rejected tariff language that 
proposes to do so.
---------------------------------------------------------------------------

    \924\ 114 FERC ] 61,280 at P 29-33 (2006), reh'g pending 
(MidAmerican).
    \925\ Id. at P 31.
---------------------------------------------------------------------------

    795. In the NOPR, the Commission sought comment on whether it 
should modify or revise its current policy. The Commission sought 
comment on whether and, if so, how it should allow market-based rate 
sales by a mitigated seller within a mitigated market if those sales do 
not ``sink'' in that control area.
Comments
    796. While some commenters generally seek to allow a mitigated 
seller to make sales at market-based rates if those sales do not 
``sink'' in the mitigated market, other commenters support the current 
policy of requiring all of a mitigated supplier's sales in the 
mitigated market to be cost-based. The State AGs and Advocates go even 
further and encourage the Commission to apply its mitigation policy to 
all wholesale sales that sink in the mitigated market, regardless of 
the seller, arguing that the impact of market power on price is market-
wide in scope.\926\
---------------------------------------------------------------------------

    \926\ State AGs and Advocates at 43-44.
---------------------------------------------------------------------------

    797. APPA/TAPS support the current policy of requiring cost-based 
rate mitigation for all sales in the mitigated market regardless of 
whether the sales ultimately sink in an unmitigated market. APPA/TAPS 
argue that allowing market-based rate sales in a mitigated market would 
yield unlawful rates because the mitigated seller would be making 
market-based rate sales in a market where it has, or is presumed to 
have, market power.\927\
---------------------------------------------------------------------------

    \927\ APPA/TAPS at 47-48. To limit marketers' arbitrage 
opportunities, APPA/TAPS suggest limiting any ``must offer'' 
obligation to sales that sink in the seller's control area. The 
seller could make additional sales in its control area at the cost-
based rate, but would not be obligated to do so because purchasers 
for loads outside of the seller's control area would presumably have 
other power supply options.
---------------------------------------------------------------------------

    798. The NYISO agrees that mitigation should not be limited to 
sales that ``sink in'' the mitigated market, at least in clearing price 
auctions such as those administered by the NYISO. The clearing prices 
are established by the interaction of all eligible buyers and sellers, 
and the NYISO reasons that there would be no practical basis, nor 
economic justification, for carving out marketers or brokers who may 
export their purchases.\928 \
---------------------------------------------------------------------------

    \928\ NYISO at 8-10. The NYISO suggests that the Commission can 
avoid concerns regarding exports to neighboring markets by applying 
any cost-based mitigation it imposes to limit the maximum bids that 
the seller may submit, without limiting the revenues that the 
mitigated seller may receive. Id.
---------------------------------------------------------------------------

    799. The Carolina Agencies express concern that limiting mitigation 
to sales that sink in a mitigated market would reduce supply options 
for LSEs embedded in that mitigated market. They contend that 
unrestricted exports from a mitigated market increase the prices 
charged by other sellers due to scarcity. Even when a sale sinks 
outside the mitigated market, the Carolina Agencies claim that round-
trip gaming will continue, and they question the Commission's ability 
to effectively detect and stop such gaming by attempting to trace 
megawatts via NERC tag data or other means. However, the Carolina 
Agencies submit that with a properly structured ``must offer'' 
requirement in place, there is no reason to bar market-based rate sales 
based on the location of the point of sale or even the identified 
sink.\929\
---------------------------------------------------------------------------

    \929\ Carolina Agencies at 20.
---------------------------------------------------------------------------

    800. Other commenters support allowing sales of power within a 
mitigated market that nonetheless sink in unmitigated markets (i.e., 
markets where the seller does not possess market power) to be made at 
market-based rates.\930\ As discussed below, they offer various 
proposals on what factors should determine whether a sale should be 
priced at market-based rates.
---------------------------------------------------------------------------

    \930\ See, e.g., PPL reply comments at 16.
---------------------------------------------------------------------------

    801. Several commenters state that the relevant inquiry should be 
whether the power serves load (sinks) in a control area where 
generation market power is an issue. MidAmerican and the Oregon 
Commission submit that there is no reason to mitigate sales over which 
the seller is unable to exercise market power.\931\ Rather, MidAmerican 
asks the Commission to refocus on whether a seller could exercise 
market power, not on the physical location where a change in ownership 
of energy occurs. MidAmerican argues that if a mitigated seller cannot 
exercise market power over sales made directly in an outside 
competitive market, such seller cannot exercise market power over sales 
made in its home control area that are for export to that outside 
competitive market.\932\ Rather than protecting the ultimate buyers, 
these commenters submit that mitigating such sales would transfer 
wealth from the mitigated seller to subsequent entities that can charge 
market prices in later transactions.\933\
---------------------------------------------------------------------------

    \931\ MidAmerican at 26; Oregon Commission reply comments at 5; 
see also Westar at 20.
    \932\ MidAmerican at 25-26; see also Dr. Pace at 18-20.
    \933\ MidAmerican at 26; Oregon Commission reply comments at 5.
---------------------------------------------------------------------------

    802. MidAmerican and the Oregon Commission claim that if the 
Commission requires mitigated sellers to mitigate all their sales in 
the mitigated market such an outcome would encourage gaming, such as 
round-trip or ricochet transactions.\934\ MidAmerican maintains that 
such gaming can be eliminated when mitigation applies only to sales 
sinking within the mitigated control area.\935\
---------------------------------------------------------------------------

    \934\ MidAmerican at 26-27; Oregon Commission reply comments at 
6.
    \935\ MidAmerican at 27.
---------------------------------------------------------------------------

    803. Duke, E.ON U.S., Westar, Mid-American, Ameren, and Xcel all 
assert that the availability of supply alternatives to wholesale 
purchasers should be a determining factor when deciding whether to 
permit market-based rates for sales that sink in

[[Page 39999]]

unmitigated markets.\936\ E.ON U.S. points out that the Commission in 
the April 14 Order noted that the foundation of the market power 
analysis under the Delivered Price Test is the ``destination market.'' 
As such, E.ON U.S. asserts that a relevant factor in determining 
whether to permit a sale at market-based rates should be the level of 
choice in supply available to the purchaser, not where the product 
originates.\937\
---------------------------------------------------------------------------

    \936\ Duke at 13; E.ON U.S. at 6; Westar at 20; MidAmerican at 
25; Ameren at 19-20; and Xcel at 13.
    \937\ E.ON U.S. at 6.
---------------------------------------------------------------------------

    804. Westar contends that when the buyer is purchasing to serve 
load in control areas where the seller lacks market power, the buyer 
presumably has access to other competitive alternatives and has 
voluntarily entered into the agreement. Therefore, the Commission 
should not second guess the buyer's decision.\938\ Westar adds that 
prohibiting all sales in the mitigated control area elevates form over 
substance because parties can simply alter the implementing details of 
their transaction to accomplish the same result.\939\
---------------------------------------------------------------------------

    \938\ Westar at 20.
    \939\ Id. at 21.
---------------------------------------------------------------------------

    805. Westar argues that the Commission's stated concern in 
MidAmerican with a seller's ``ability to attempt to exercise market 
power over sales in its control area'' is misplaced; the Commission's 
traditional market power analysis is only concerned with the 
``incentive'' and ``ability'' to exercise market power, not with 
``attempts'' to do so.\940\ As such, it is ``ability'' and not 
``attempts'' to exercise market power that is a key determinant of 
whether an actual market power problem exists.
---------------------------------------------------------------------------

    \940\ Id. at 21 (citing MidAmerican Energy Company, 114 FERC ] 
61,280 (2006), reh'g pending; Exelon Corp., 112 FERC ] 61,011, at P 
134 (``As we have said in numerous contexts, we are concerned about 
a merger's effect on the merged firm's ability and incentive to harm 
competition.''), order on reh'g, 113 FERC ] 61,299 (2005); Oklahoma 
Gas and Electric Company, 105 FERC ] 61,297, at P 35 (2003) (``Both 
the ability and incentive to raise prices by restricting access are 
necessary for a vertical market power problem to exist.''); NiSource 
Inc., 92 FERC ] 61,068, at 61,239 (2000) (``Because the merged 
company must have both the ability and incentive to adversely affect 
electricity prices or output, and the merged company will lack the 
former, no further findings are necessary.'')).
---------------------------------------------------------------------------

    806. Westar further claims that the Commission is not bound by 
precedent to prohibit all market-based rate sales in a mitigated 
control area, pointing out that the Commission has accepted four 
proposals after the July 8 Order that limit mitigation to sales that 
sink in the mitigated control areas.\941\ Moreover, Westar claims that 
the July 8 Order appears to address the question of who may buy power 
from a mitigated seller, not where mitigated sales can occur. This 
leads Westar to conclude that the Commission did not originally intend 
to preclude mitigated sellers from making market-based sales to buyers 
over which the seller lacks generation market power, regardless of 
where the sales occur. Westar urges the Commission to return to this 
principle.\942\
---------------------------------------------------------------------------

    \941\ Id. at 22 (citing American Electric Power Service Corp., 
Docket Nos. ER96-2495-026, et al. (Jan. 13, 2006) (letter order 
accepting uncontested settlement applying mitigation to sales that 
sink in the mitigated control area); AEP Power Marketing, Inc., 112 
FERC ] 61,320 (2005) (dismissing rehearing requests as moot because 
of utility's commitment to mitigate sales ``that sink within AEP-
SPP''); South Carolina Electric and Gas Company, 114 FERC ] 61,143 
(2006) (order accepting utility's commitment to mitigate sales that 
``sink'' in its home control area, subject to a compliance filing); 
LG&E Energy Marketing, Inc., 113 FERC ] 61,229 (2005) (ordering the 
utility to apply the proposed mitigation to sales that sink in the 
mitigated control area)).
    \942\ Westar at 22-23.
---------------------------------------------------------------------------

    807. Xcel urges the Commission to focus on the parties' intent and 
whether alternative supply options are available to the purchaser at 
the time of contracting, rather than focusing on where energy purchased 
in the transaction actually sinks in real time. At the time of the 
transaction, if the purchaser can confirm: (i) It intends to use the 
power outside of the mitigated control area, and (ii) there are 
existing transmission arrangements to actually use the power elsewhere, 
Xcel maintains that it should not matter what the purchaser 
subsequently does with the power in real time.\943\ Xcel and 
MidAmerican also favor adopting market-index or proxy based mitigation 
as a way to reduce the concern about where sales actually sink when 
trying to ensure proper mitigation.\944\
---------------------------------------------------------------------------

    \943\ Xcel at 13. While MidAmerican does not object to Xcel's 
proposal, it submits that its own proposal regarding use of market-
based indices would provide additional assurance that a seller would 
not manipulate prices by arranging round-trip transactions into a 
mitigated control area. MidAmerican reply comments at 19-20.
    \944\ Xcel at 11-138; MidAmerican reply comments at 4.
---------------------------------------------------------------------------

    808. EEI, PPL, PNM/Tucson, and Pinnacle take the position that the 
Commission should consider point of delivery when deciding whether to 
permit market-based rate sales.\945\ EEI asks the Commission to allow 
mitigated sellers to make market-based rate sales if the delivery point 
in the contract or sale confirmation is outside the mitigated market, 
or if the buyer has transmission service to take the power outside the 
mitigated market. In other words, buyers who choose delivery points 
inside the mitigated market and do not move the power out will pay 
mitigated rates, but buyers who choose delivery points inside the 
mitigated market but move the power outside the mitigated market will 
pay market-based rates.\946\
---------------------------------------------------------------------------

    \945\ EEI at 38; PPL at 25 (supporting EEI's comments); Pinnacle 
at 9; PNM/Tucson at 14-15.
    \946\ EEI at 38.
---------------------------------------------------------------------------

    809. EEI asserts that its proposal is consistent with the 
Commission policy that the mitigation must focus on the geographic 
market that is mitigated, not the type of customer purchasing the 
power. EEI concludes that the proposal will minimize the impacts on 
competitive transactions as well as avoid a remedy that will have a 
negative impact on the liquidity of the competitive market.\947\
---------------------------------------------------------------------------

    \947\ EEI at 41.
---------------------------------------------------------------------------

    810. PNM/Tucson agree that the Commission should use the point of 
delivery as a determining factor. They contend that transmission tags 
alone--which they explain are a reliability tool to ensure systems 
balance from a transmission perspective--are inadequate to monitor 
market transactions or ensure that sales sink outside a mitigated 
control area.\948\
---------------------------------------------------------------------------

    \948\ PNM/Tucson at 14-15.
---------------------------------------------------------------------------

    811. PNM/Tucson, Pinnacle, E.ON U.S., MidAmerican and PPL all 
generally argue that sales at or beyond the transmission interface of a 
mitigated control area should not be mitigated if the seller lacks 
market power in the adjacent control area.\949\ MidAmerican asserts 
that the Commission's market power analyses demonstrate that the seller 
has no market power over sales at the border (sales requiring no 
additional transmission to exit the mitigated region).\950\ PNM/Tucson, 
Pinnacle and E.ON U.S. maintain that prohibiting market-based rate 
sales at these transmission interfaces would prevent cross border sales 
at these unique locations and reduce market liquidity in markets where 
the seller does not possess market power.\951\
---------------------------------------------------------------------------

    \949\ PNM/Tucson at 16; Pinnacle at 8-9; E.ON U.S. at 5-8; 
MidAmerican at 29-30; PPL reply comments at 16.
    \950\ MidAmerican at 29-30.
    \951\ PNM/Tucson at 16; Pinnacle at 8-9; E.ON U.S. at 8.
---------------------------------------------------------------------------

    812. E.ON U.S. and MidAmerican urge the Commission to view 
interface/border transactions as fundamentally different from sales in, 
or sinking in, a control area. These commenters reason that, at 
transmission interfaces, a buyer has competitive choices from sellers 
in both control areas that abut the interface, as well as from any 
seller that can transmit power to that interface from any control area. 
As a result, buyers taking title to power at a

[[Page 40000]]

transmission interface for delivery outside the mitigated control area 
have competitive choices that do not require transacting with the 
supplier found to have market power within the mitigated control 
area(s).\952\ Moreover, E.ON U.S. claims that mitigating transactions 
at control area interfaces could reduce a utility's profits from off-
system sales, thereby affecting retail ratepayers by reducing offsets 
that affect the costs of their retail rates.\953\
---------------------------------------------------------------------------

    \952\ E.ON U.S. at 6; MidAmerican reply comments at 22-23.
    \953\ E.ON U.S. at 8.
---------------------------------------------------------------------------

    813. PNM/Tucson, Pinnacle, E.ON U.S., and MidAmerican note that the 
Commission indicated in LG&E that sales at the border need not be 
mitigated along with sales ``wholly in'' a control area.\954\ PNM/
Tucson and MidAmerican urge the Commission to codify in the Final Rule 
LG&E's holding that sales at the transmission interface of a mitigated 
control area are not ``in'' the control area, and therefore need not be 
mitigated.\955\ E.ON U.S. similarly asks the Commission to define sales 
``in'' a control area as those where title to power transfers at a 
physical location wholly within such control area, and should not 
include sales where title transfers at a transmission interface.\956\
---------------------------------------------------------------------------

    \954\ PNM/Tucson at 16; Pinnacle at 8-9; E.ON U.S. at 8; 
MidAmerican reply comments at 23.
    \955\ PNM/Tucson at 16; MidAmerican reply comments at 23.
    \956\ E.ON U.S. at 5.
---------------------------------------------------------------------------

    814. Xcel, in comparison, argues that any buyer purchasing power at 
a generator bus or elsewhere in a mitigated control area for purposes 
of moving that power out of the mitigated market should be treated no 
differently than a buyer who takes delivery of purchased power outside 
of the mitigated region. According to Xcel, mitigation to discipline 
market power is unnecessary in either of these cases and the location 
of the delivery point does not matter.\957\
---------------------------------------------------------------------------

    \957\ Xcel at 12.
---------------------------------------------------------------------------

    815. Both Dalton Utilities and the Carolina Agencies state that it 
would be wrong to assume that every contract involving a mitigated 
supplier is unjust and unreasonable and must be abrogated to protect 
consumers.\958\ Dalton Utilities urge the Commission to clearly state 
in the final rule that it does not generically abrogate existing long-
term market-based rate wholesale requirements and transmission 
contracts, nor is it requiring such abrogation in subsequent 
proceedings that revoke the market-based rate authority of a public 
utility found to possess market power.\959\ Dalton Utilities asks the 
Commission to grandfather existing long-term market-based wholesale 
contracts in the final rule.\960\
---------------------------------------------------------------------------

    \958\ Dalton Utilities reply comments at 4-9; Carolina Agencies 
at 22-23.
    \959\ Dalton Utilities reply comments at 6, 9.
    \960\ Id. at 6-7. Duke notes its support for the Commission's 
current policy of not reforming or abrogating contracts that were 
negotiated prior to the time of any finding of market power. Duke 
reply comments at 8, n.12.
---------------------------------------------------------------------------

    816. The Carolina Agencies add that the effect on existing 
contracts of a decision to retain the current mitigation policy of 
prohibiting sales at market-based rates in a mitigated market should be 
determined on a case-by-case basis. These entities reason that simply 
because market power may exist (or a presumption that it exists has not 
been rebutted) does not in every instance mean that the seller actually 
abused its market position to extract unreasonable terms from its 
purchaser. The circumstances of each contract must be examined to 
determine whether its terms reflect the exercise of market power. The 
Carolina Agencies and Dalton Utilities conclude that generic abrogation 
or reformation of existing agreements is neither warranted nor 
consistent with the Commission's manner of resolving other claims of 
broad-based discrimination.\961\
---------------------------------------------------------------------------

    \961\ Carolina Agencies at 23; Dalton Utilities reply comments 
at 7-9.
---------------------------------------------------------------------------

Commission Determination
    817. In order to protect customers from market power concerns, we 
will continue to apply mitigation to all sales in the balancing 
authority area in which a seller is found, or presumed, to have market 
power. However, as discussed below we will allow mitigated sellers to 
make market-based rate sales at the metered boundary \962\ between a 
mitigated balancing authority area and a balancing authority area in 
which the seller has market-based rate authority under certain 
circumstances.
---------------------------------------------------------------------------

    \962\ North American Electric Reliability Corporation. Glossary 
of Terms Used in Reliability Standards at 2 (2007), available at 
ftp://www.nerc.com/pub/sys/all_updl/standards/rs/Glossary_02May07.pdf
.

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

    818. Commenters advocating allowing market-based rate sales in a 
mitigated market provided the power is intended for an unmitigated 
market (e.g., applying mitigation only to sales that sink in the 
mitigated market) have failed to adequately explain how customers in 
the mitigated market would be protected from the potential exercise of 
market power. In addition, commenters have failed to adequately address 
how the Commission could effectively monitor such sales to ensure that 
improper sales were not being made. Indeed, several commenters have 
noted the complex administrative problems that would be associated with 
trying to monitor compliance with such a policy.\963\
---------------------------------------------------------------------------

    \963\ For example, PNM/Tucson note that transmission tags alone 
are inadequate to monitor market transactions. PNM/Tucson at 14-15.
---------------------------------------------------------------------------

    819. Allowing market-based rate sales by a seller that has been 
found to have market power, or has so conceded, in the very market in 
which market power is a concern is inconsistent with the Commission's 
responsibility under the FPA to ensure that rates are just and 
reasonable and not unduly discriminatory. While we generally agree that 
it is desirable to allow market-based rate sales into markets where the 
seller has not been found to have market power, we do not agree that it 
is reasonable to allow a mitigated seller to make market-based rate 
sales anywhere within a mitigated market. It is unrealistic to believe 
that sales made anywhere in a balancing authority area can be traced to 
ensure that no improper sales are taking place. Such an approach would 
also place customers and competitors at an unreasonable disadvantage 
because the mitigated seller has dominance in the very market in which 
it is making market-based rate sales.
    820. However, we do recognize that sales made at the metered 
boundary for export do lend themselves to being monitored for 
compliance, and the nature of these types of sales do not unduly 
disadvantage customers or competitors. Prohibiting market-based rate 
sales at these metered boundaries of the balancing authority area could 
prevent or adversely impact cross border sales at these unique 
locations and reduce market liquidity in markets where the seller does 
not possess market power. Buyers taking title to power at a metered 
boundary for delivery to serve load in a balancing authority area where 
the seller has market-based rate authority have competitive choices and 
therefore are not required to transact with the seller found to have 
market power within the mitigated balancing authority area(s).
    821. Accordingly, we will allow such sales to be made at market-
based rates. Mitigated sellers making such sales must maintain for a 
period of five years from the date of the sale all data and information 
related to the sale that demonstrates that the sale was made at the 
metered boundary between the mitigated balancing authority area and a 
balancing authority area in which the seller has market-based rate 
authority, that the sale is not intended to serve load in the seller's 
mitigated market,

[[Page 40001]]

and that no affiliate of the mitigated seller will sell the same power 
back into the mitigated seller's mitigated market.
    822. Such an approach properly balances commenters' concerns that 
when a buyer purchases power to serve load in markets where the 
mitigated seller lacks market power the buyer has access to competitive 
alternatives with the Commission's obligation under the FPA to ensure 
that rates are just and reasonable. Further, we find that our approach 
in this regard does not place an unreasonable burden on the customer, 
mitigated seller, or competitors. We also emphasize that the mitigation 
we adopt herein is prospective only. In response to Dalton's concern, 
we clarify that such mitigation does not modify, abrogate, or otherwise 
affect existing contractual agreements.\964\
---------------------------------------------------------------------------

    \964\ See South Carolina Electric and Gas Co., 114 FERC ] 61,143 
at P 18 (2006) (accepting mitigation on a prospective basis; 
existing long-term agreements remain in effect until terminated 
pursuant to their terms); see also April 14 Order, 107 FERC ] 61,018 
at P 154; July 8 Order, 108 FERC ] 61,026 at P 145.
---------------------------------------------------------------------------

    823. Further, we disagree with the Carolina Agencies' contention 
that short of a ``must-offer'' provision unrestricted exports from a 
mitigated market increase the prices charged by other suppliers due to 
scarcity. Carolina Agencies' argument would only apply when the market 
prices in the first-tier markets are higher than the seller's cost-
based rate in the mitigated market. This situation is not necessarily 
always the case and, therefore, the Carolina Agencies' concern may be 
based on an unrealistic assumption.
    824. We disagree with MidAmerican and the Oregon Commission's claim 
that if the Commission requires mitigated sellers to mitigate all their 
sales in the mitigated market this would encourage gaming, such as 
round-trip or ricochet transactions. While the Commission issued an 
order rescinding Market Behavior Rules 2 and 6,\965\ Order No. 670 
finalized regulations prohibiting energy market manipulation pursuant 
to the Commission's new Energy Policy Act of 2005 authority. The 
Commission emphasized in Order No. 670 that ``the specific prohibitions 
of Market Behavior Rule 2 (wash trades, transactions predicated on 
submitting false information, transactions creating and relieving 
artificial congestion, and collusion for the purpose of market 
manipulation), * * * are examples of prohibited manipulation, all of 
which are manipulative or deceptive devices or contrivances, and are 
therefore prohibited activities under this Final Rule, subject to 
punitive and remedial action.'' \966\ Such fraud and manipulative 
conduct therefore remains prohibited and subject to the Commission's 
anti-manipulation and civil penalty authority.
---------------------------------------------------------------------------

    \965\ Investigation of Terms and Conditions of Public Utility 
Market-Based Rate Authorizations, 114 FERC ] 61,165 (2006).
    \966\ Prohibition of Energy Market Manipulation, Order No. 670, 
114 ] FERC 61,047 at P 59 (2006).
---------------------------------------------------------------------------

d. Proposed Tariff Language
Comments
    825. Several commenters have proposed specific tariff language in 
the event the Commission allows market-based rate sales in the 
mitigated market or at the border. For example, PNM/Tucson would 
require a sale to ``have a contractual point of delivery at or beyond 
the transmission interface of the mitigated control area (assuming that 
the point of delivery is not in another control area where the seller 
is also mitigated).'' \967\ They would also require the seller's 
market-based rate tariff to explicitly prohibit efforts to collude with 
a third party to sell to customers in the mitigated control area at 
market-based rates.\968\
---------------------------------------------------------------------------

    \967\ PNM/Tucson at 15.
    \968\ Id.
---------------------------------------------------------------------------

    826. PNM/Tucson point out that their proposal contains a 
significant concession. Under their proposed language, a sale by a 
mitigated seller at the generation bus in the mitigated control area 
must be made at mitigated rates. They believe this concession is fair 
if the Commission insists that market-based rate sales for mitigated 
sellers are based on contractual points of delivery at or beyond the 
transmission interface of the mitigated control area. In these 
companies' view, such an approach would provide needed certainty 
through a bright line rule and limit factual disputes and 
investigations.\969\
---------------------------------------------------------------------------

    \969\ Id. at 16-17; MidAmerican submits that its proposal would 
also provide the ``bright-line'' regulatory certainty sought by PNM/
Tucson. MidAmerican reply comments at 16-18.
---------------------------------------------------------------------------

    827. MidAmerican and Ameren also support using tariff or agreement 
language to ensure power sinks outside of the mitigated market.\970\ 
MidAmerican favors using tariff safeguards and confirmation/oversight 
procedures to mitigate a seller's ability to exercise generation market 
power, prevent gaming, and protect wholesale customers in the mitigated 
region. MidAmerican submits that it has developed and filed market-
based rate tariff provisions and verification and oversight procedures 
that can ensure that export transactions sink outside the mitigated 
seller's control area.\971\ MidAmerican argues that its approach 
correctly focuses on whether the mitigated seller could exercise market 
power over transactions that affect entities that purchase on behalf 
of, or for re-sale to, loads within the market subject to mitigation, 
rather than the geographical location where customers may take 
responsibility for transmitting the power to a final destination. 
Moreover, MidAmerican claims that its proposal would allow the market 
to work efficiently in areas where the mitigated seller's ability to 
exercise market power is not an issue. MidAmerican supports a 
Commission technical conference to further explore this concept with 
interested parties.\972\
---------------------------------------------------------------------------

    \970\ MidAmerican at 28; Ameren at 19-20.
    \971\ Under MidAmerican's proposed tariff revisions: (i) 
Counterparties would be required to affirmatively confirm that the 
energy sold within MidAmerican's control area will not stay inside 
that control area; (ii) MidAmerican energy schedulers will review 
NERC tags associated with in-control area sales on a daily basis to 
ensure transactions indeed sink outside the mitigated control area; 
(iii) if a review of the NERC tags shows that a transaction will 
sink inside the mitigated control area, the sale will be 
renegotiated at cost-based rates; and (iv) if required by the 
Commission, MidAmerican would submit the NERC tag data to the 
appropriate market monitor. MidAmerican at 28-29.
    \972\ MidAmerican at 28-29.
---------------------------------------------------------------------------

    828. Several commenters further propose that mitigated sellers be 
required to add language to their market-based rate tariffs or to 
specific market-based rate contracts to restrict re-sales from sinking 
in the mitigated control area.\973\ FP&L argues that requiring such 
language would reinforce the idea that re-sales into mitigated control 
areas are violations of a Commission-approved tariff that also, 
depending on the facts, might violate the Commission's market 
manipulation regulations.\974\
---------------------------------------------------------------------------

    \973\ FP&L at 6 (proposing the following tariff language: 
``Purchasers are hereby on notice that the sink for any energy or 
capacity sale under this Tariff shall not be in the Seller's control 
area.''); E.ON U.S. at 10 (proposing ``a simple tariff commitment by 
sellers that power sold at a point of delivery within their 
mitigated control area will, to the best of their knowledge, sink 
elsewhere.''); Ameren at 20 (proposing that agreements governing 
market-based rate sales in mitigated markets explicitly state that 
the subject power will sink outside the mitigated region, and that 
the seller be required to report such sales in its EQR).
    \974\ FP&L at 6.
---------------------------------------------------------------------------

    829. Another commenter agrees that restrictive language in the 
market-based rate tariff could prevent re-sales into the mitigated 
control area by helping to ensure that any power purchased at market-
based rates within a mitigated control area is exclusively for export 
to serve loads beyond the mitigated market. Where the Commission is 
concerned that gaming could lead to the

[[Page 40002]]

exercise of market power over wholesale customers in the home control 
area, this commenter suggests that the Commission reemphasize that 
efforts to loop power through an adjacent market area in order to raise 
prices to wholesale customers in mitigated areas above competitive 
levels is a violation of market-based rate tariffs. Further, this 
commenter submits that the Commission may require buyers to confirm 
that power purchased at market-based rates in a mitigated control area 
is for export, use NERC tag data and transmission scheduling 
information to verify when purchased power is being exported from the 
home control area, and require oversight by independent market 
monitors.\975\
---------------------------------------------------------------------------

    \975\ Dr. Pace at 20-21.
---------------------------------------------------------------------------

Commission Determination
    830. Consistent with our decision above, mitigated sellers choosing 
to make market-based rate sales at the metered boundary between a 
mitigated balancing authority area and a balancing authority area in 
which the seller has market-based rate authority will be required to 
commit and maintain sufficient documentation to demonstrate \976\ that: 
(1) Legal title of the power sold transfers at the metered boundary 
between a mitigated balancing authority area and one in which the 
mitigated entity has market-based rate authorization; and (2) any power 
sold is not intended to serve load in the seller's mitigated market and 
(3) no affiliate of the mitigated seller will sell the same power back 
into the mitigated seller's mitigated market. To accomplish these 
requirements, mitigated sellers seeking to make market-based rate sales 
at the metered boundary between their mitigated balancing authority 
area and a balancing authority area in which the sellers have market-
based rate authority must adopt the following tariff provision:

    Sales of energy and capacity are permissible under this tariff 
in all balancing authority areas where the Seller has been granted 
market-based rate authority. Sales of energy and capacity under this 
tariff are also permissible at the metered boundary between the 
Seller's mitigated balancing authority area and a balancing 
authority area where the Seller has been granted market-based rate 
authority provided: (i) Legal title of the power sold transfers at 
the metered boundary of the balancing authority area where the 
seller has market-based rate authority; (ii) any power sold 
hereunder is not intended to serve load in the seller's mitigated 
market; and (iii) no affiliate of the mitigated seller will sell the 
same power back into the mitigated seller's mitigated market. Seller 
must retain, for a period of five years from the date of the sale, 
all data and information related to the sale that demonstrates 
compliance with items (i), (ii) and (iii) above.

    \976\ Reliance solely on NERC tag data as documentation for such 
sales will likely be deemed insufficient as such an approach has not 
yet been shown to be either workable or effective.
---------------------------------------------------------------------------

    831. This approach affords necessary protection from market power 
abuse for customers in the mitigated markets. Such language reminds all 
sellers that gaming resulting in re-sales of any sort by an affiliate 
of the mitigated seller into their mitigated balancing authority 
area(s) (i.e., by looping power through adjacent markets) are 
violations of a Commission-approved tariff that may also, depending on 
the facts, violate the Commission's market manipulation regulations. 
Such violations may result in penalties being imposed under the market 
manipulation regulations and/or the revocation of a mitigated seller's 
market-based authority in all markets.

E. Implementation Process

Commission Proposal
    832. In the NOPR, the Commission put forth several proposals to 
streamline the administration of the market-based rate program while 
maintaining a high degree of oversight. The Commission proposed to 
modify the practice of requiring an updated market power analysis to be 
submitted within three years of any order granting a seller market-
based rate authority and every three years thereafter by, instead, 
putting in place a structured, systematic review based on a coherent 
and consistent set of data. First, the Commission proposed to establish 
two categories of sellers with market-based rate authorization. Sellers 
in the first category, Category 1,\977\ would not be required to file a 
regularly scheduled updated market power analysis. The Commission 
proposed instead to monitor any market power concerns for Category 1 
sellers through the change in status reporting requirement and through 
ongoing monitoring by the Commission's Office of Enforcement. In this 
regard, the Commission noted that failure to timely file a change in 
status report would constitute a violation of the Commission's 
regulations and the seller's market-based rate tariff.
---------------------------------------------------------------------------

    \977\ Category 1 sellers would include power marketers and power 
producers that own or control 500 MW or less of generating capacity 
in aggregate and that are not affiliated with a public utility with 
a franchised service territory. Category 1 sellers also must not own 
or control transmission facilities other than limited equipment 
necessary to connect individual generating facilities to the 
transmission grid (or must have been granted waiver of the 
requirements of Order No. 888 because the facilities are limited and 
discrete and do not constitute an integrated grid), and they must 
not present other vertical market power issues. NOPR at P 152.
---------------------------------------------------------------------------

    833. Sellers in Category 2, consisting of all sellers that do not 
qualify for Category 1, would be required to file regularly scheduled 
updated market power analyses in addition to change in status reports. 
The Commission proposed to codify this requirement in its regulations. 
Failure to timely file an updated market power analysis would 
constitute a violation of the Commission's regulations and the seller's 
market-based rate tariff.
    834. Second, to ensure greater consistency in the data used to 
evaluate Category 2 sellers, the Commission proposed that the required 
updated market power analyses be filed for each seller's relevant 
geographic market(s) on a schedule allowing examination of the 
individual seller at the same time that the Commission examines other 
sellers in the relevant markets and contiguous markets within a region 
from which power could be imported. The Commission appended a proposed 
schedule for the regional review process, rotating by geographic region 
with three regions being reviewed per year. For corporate families that 
own or control generation in multiple control areas and different 
regions, the Commission proposed that the corporate family would be 
required to file an update for each region in which members of the 
corporate family sell power during the time period specified for that 
region.
    835. Finally, the Commission proposed to require that all updated 
market power analyses and all new applications for market-based rate 
authority include an appendix listing all generation assets owned or 
controlled by the corporate family by control area, listing the in-
service date and nameplate and/or seasonal ratings by unit, and all 
electric transmission and natural gas intrastate pipelines and/or gas 
storage facilities owned or controlled by the corporate family and 
their location.
1. Category 1 and 2 Sellers
Comments
a. Establishment of Category 1 and 2 Sellers
    836. A variety of commenters fully support the Commission's 
proposed categorization of sellers into two categories and the 
boundaries of those categories. ELCON comments that the Commission's 
limited resources should be focused on the dominant players and not 
treat every seller as a potential threat. NRECA commends the Commission 
for its attempt to


[[Continued on page 40003]]


From the Federal Register Online via GPO Access [wais.access.gpo.gov]
]                         
 
[[pp. 40003-40046]] Market-Based Rates for Wholesale Sales of Electric Energy, 
Capacity and Ancillary Services by Public Utilities

[[Continued from page 40002]]

[[Page 40003]]

streamline the process.\978\ APPA/TAPS support the proposed categories 
but suggest that the Commission clarify that it retains the ability to 
determine that a Category 1 seller must still adhere to the triennial 
update requirements if, for example, it is dominant in a particular 
load pocket. Explaining that its generation and power marketing 
activities are only incidental to its mining operations, and that its 
market share will likely decline over time, Newmont states that filing 
an updated market analysis every three years would be an unnecessary 
burden to prepare and a waste of the Commission's time to review. 
Newmont finds the 500 MW cutoff a clear, bright line that would be easy 
to administer. If the Commission determines it necessary to adjust the 
threshold, however, Newmont suggests retaining the 500 MW cutoff with a 
further requirement that no more than 250-300 MW be located in any one 
control area. Alternatively, there could be some sliding scale 
delineation between Categories 1 and 2 based on the size of a control 
area, in terms of load, unaffiliated capacity, or both.
---------------------------------------------------------------------------

    \978\ See also EPSA reply comments at 3, 13-14.
---------------------------------------------------------------------------

    837. Financial Companies and Morgan Stanley request that the 
Commission release a list of all sellers in each category and the 
region in which the Commission believes each seller belongs to help 
ensure that sellers have notice of their status and related filing 
obligations. These parties also suggest that the Commission hold a 
technical conference on commenters' proposals about how to organize the 
categories.
    838. FirstEnergy opposes the concept of exempting Category 1 
sellers from triennial reporting while continuing the requirement for 
Category 2 sellers. FirstEnergy states that there is no reason for the 
Commission to require any public utility authorized to sell at market-
based rates to file an updated market power analysis. According to 
FirstEnergy, the showing made in the initial market-based rate 
proceeding and the change in status rules are adequate, and relieving 
Category 1 sellers from filing without abolishing the requirement 
entirely would be unduly discriminatory.
    839. On the other hand, the California Commission believes that all 
sellers should have to continue filing updated market power analyses; 
it states that the assumption that Category 1 sellers do not need the 
same level of scrutiny as larger sellers is erroneous, and argues that 
the NOPR provides no legitimate justification for creating a disparity 
between Category 1 and 2 sellers. The California Commission continues 
by stating that reliance solely on market monitoring would not 
necessarily be effective in California. It notes that in markets 
utilizing LMP, there is a great potential for sellers to exert 
``local'' market power, especially in load pockets. In such load pocket 
areas, it contends that there is no guarantee that a small seller could 
not have market power. Further, it states that a Category 1 seller 
could suddenly gain market power due to another seller's withdrawal 
from the market and asserts that ``given the number of markets and the 
Commission's limited resources, it would seem an enormous task of 
monitoring without requiring regular updated market power analyses from 
all market participants.'' \979\
---------------------------------------------------------------------------

    \979\ California Commission at 4.
---------------------------------------------------------------------------

    840. Similarly, NASUCA states that there is no basis in the record 
to assume that Category 1 sellers would lack market power at all times 
and offers examples of when Category 1 sellers could pose a 
problem.\980\ NASUCA also warns that there is no apparent limit on the 
total amount of exempt generation that could be owned by entities other 
than those affiliated with a franchised utility. Specifically, NASUCA 
argues that:
---------------------------------------------------------------------------

    \980\ For example, NASUCA asserts that there appears to be a 
possibility that a seller with a fleet of newer power plants that 
were initially exempted from review would be totally exempt from 
subsequent review based on the size of the power plants. These 
sellers might at times have market power with respect to ancillary 
services. NASUCA further submits that changed circumstances, such as 
declining reserve margins, might create opportunities for seemingly 
small sellers to exercise market power.

    [U]nder the [Category 1] definition and [change of status] 
notice obligations, a ``Category 1'' seller could qualify for 
exemption from triennial market power reviews even if its holding 
company affiliates--other power marketing and generation entities 
that also have ``Category 1'' status--collectively have a share of 
generation far larger than 500 MW, and even if the seller has a 
retail affiliate without a franchised service territory. Examples 
might include a group of ``Category 1'' peaker plant owners in a 
constrained area, each owned by a separate entity affiliated with 
the same holding company; owners of a fleet of small hydro 
facilities, each a separate entity within a holding company 
structure; or an assemblage of generation control [sic] by numerous 
power marketing subsidiaries, each of which controls less than 500 
MW of generation.\981\
---------------------------------------------------------------------------

    \981\ NASUCA at 12. See also NASUCA reply comments at 9-11 
(stating that neither the 500 MW exemption, nor the expansion to a 
1000 MW exemption, nor the elimination of a horizontal market power 
test, should be adopted).

    841. Thus, NASUCA argues that the regulations should be modified or 
clarified to prevent this scenario. If the Commission proceeds with its 
proposal, NASUCA states that the Commission should consider a much 
lower threshold, such as 75 MW.
    842. State AGs and Advocates state that exempting entities, no 
matter how small, would conflict with the concept that all sellers 
contribute in varying degrees to the existence of market power in a 
market.\982\
---------------------------------------------------------------------------

    \982\ State AGs and Advocates reply comments at 14.
---------------------------------------------------------------------------

    843. NASUCA and the California Commission argue that none of the 
proponents of an exempt category of sellers have shown how the 
exemption meets the Commission's legal requirements.\983\ NASUCA 
expresses concern that the blanket exemption for Category 1 sellers 
from filing updated market power reviews is inconsistent with the 
justification the Commission has previously made to the courts in 
support of market-based rates, namely, that the Commission makes a 
discrete finding or determination as to each seller's market power, and 
periodically reviews it. The California Commission similarly disputes 
that the exemption meets the underlying principle found in Lockyer. It 
states that the Ninth Circuit in that case noted that the Commission's 
authority to grant market-based rates is rooted in the integral nature 
of the reporting requirements. The California Commission asserts that 
the proposed requirement for Category 1 sellers to make a filing only 
upon a change in status is inconsistent with the rationale laid out in 
Lockyer. It further contends that delegation of ongoing monitoring to 
the Commission's Office of Enforcement is vague and contrary to the 
underlying principle found in Lockyer. According to the California 
Commission, the assumptions underlying the proposed Category 1 
exemption (that since Category 1 sellers are smaller in size they do 
not need to be subject to the same requirements and scrutiny as larger 
sellers of energy, and that `` `Category 2 sellers are the larger 
sellers with more of a presence in the market and are more likely to 
fail one or more of the indicative screens or pass by a smaller margin 
than Category 1 sellers'' ') are insufficient to justify a departure 
from the Lockyer rationale.\984\
---------------------------------------------------------------------------

    \983\ NASUCA reply comments at 9-11, California Commission reply 
comments at 1-4.
    \984\ California Commission reply comments at 3-4 (quoting NOPR 
at P 153).
---------------------------------------------------------------------------

    844. PPM refutes the California Commission's arguments. First, PPM 
asserts that the California Commission is wrong in its generalization 
that a seller that controls less than 500 MW in a market that utilizes 
LMP could exert

[[Page 40004]]

local market power. PPM argues that the existence of an LMP market does 
not increase the potential for a small generator or marketer to possess 
market power; LMP is intended to reduce the ability of a party to 
exercise local market power.\985\ Second, PPM states that the 
California Commission is wrong when it asserts that Lockyer requires 
the Commission to require all sellers to file updated market power 
analyses. According to PPM, in Lockyer, the Court found that if the 
Commission is going to grant parties the authority to charge market-
based rates, the Commission must continue to monitor and ensure that 
the rates charged are just and reasonable. PPM submits that creating a 
categorical exemption to reduce the burden on smaller generators and 
marketers does not mean that the Commission is eliminating its ability 
to effectively monitor the wholesale electric market. It states that 
the Commission retains the tools necessary to ensure that all rates are 
just and reasonable: all entities with market-based rate authority must 
submit electric quarterly reports to the Commission regarding their 
transactions; all parties have the right to ask the Commission for 
relief under section 206 of the FPA if they believe that rates are 
improper or unjust; the Commission may take up an independent review of 
any markets which are displaying abnormal characteristics; and finally, 
the Commission may require certain parties to file updated market power 
analyses if the seller is found to have market power even if the seller 
meets the threshold for Category 1 exemption.
---------------------------------------------------------------------------

    \985\ PPM reply comments at 1-3.
---------------------------------------------------------------------------

b. Threshold for Category 1 Sellers and Other Proposed Modifications
    845. While the majority of commenters support the concept of 
exempting smaller, Category 1 sellers from filing updated market power 
analyses, many seek clarification or modification of the proposal. A 
number of commenters propose a threshold other than ownership or 
control of 500 MW or less in aggregate. Suggested thresholds include: 
500 MW or less of uncommitted capacity (therefore including only that 
which is available for sale into markets during peak periods); \986\ 
500 MW within a particular control area; \987\ 500 MW within a 
geographic market; \988\ 500 MW within a particular region; \989\ up to 
1000 MW; \990\ less than 1 percent of the installed capacity in a 
regional market or 1000 MW in that regional market (whichever is 
higher); \991\ or some other formula.\992\ Several commenters urge the 
Commission to consider the size of a particular control area or 
geographic region or market and whether the geographic market is served 
by an RTO/ISO,\993\ and to take into account the difference between 
thermal generating capacity and intermittent or non-dispatchable 
generation for their ability to impact the competitiveness of a 
market.\994\
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    \986\ See Ormet at 9.
    \987\ See, e.g., PPM at 3-4; AWEA at 3-4.
    \988\ See Constellation at 8-9 (noting that this would be 
consistent with the Commission's indicative screen analysis and 
regional approach to updated market power analyses).
    \989\ EPSA at 36-37; AWEA at 3-4; Suez/Chevron at 5-10.
    \990\ See Morgan Stanley at 10-13; Financial Companies at 13-14; 
Financial Companies reply comments at 7-8. See also Mirant at 12 
(recommending 1000 MW per geographic market if the Commission hopes 
to have a minimal impact on sellers' compliance costs caused by 
eliminating the 18 CFR 35.27(a) exemption).
    \991\ EPSA at 36-37.
    \992\ Constellation at 9-11 (supports changing threshold from 
500 MW to the greater of 500 MW or 2 percent of the total generation 
capacity in the relevant geographic market; where the geographic 
market is an RTO or ISO, change threshold to the greater of 1,000 MW 
or 2 percent of the total generation capacity in that market); 
Ameren at 21 (supports exempting a company that owns or controls 
more than 500 MW but owns or controls less than 20 percent of the 
total uncommitted capacity in the relevant geographic market and 
also is not affiliated with an entity that owns transmission 
facilities in that market).
    \993\ Drs. Broehm and Fox-Penner at 13; Constellation at 9; PPM 
at 3-4.
    \994\ AWEA at 3-4 (asserting that companies owning or 
controlling thermal generating capacity have a greater opportunity 
for impacting the competitiveness of a market than those that own or 
control non-dispatchable generation, such as wind power facilities, 
that rarely achieve production at nameplate capacity levels); PPM at 
4 (same); Financial Companies reply comments at 8-9.
---------------------------------------------------------------------------

    846. PPM argues that without certain modifications to the 
Commission's definition of a Category 1 seller, which PPM believes is 
too narrowly defined, many generators and marketers may needlessly have 
to submit an updated market power analysis. According to PPM, the 
Commission should not eliminate the exemption for new generation 
(pursuant to 18 CFR 35.27(a)) without expanding the group of generators 
and marketers eligible for Category 1 status.\995\ Several commenters 
also urge the Commission to allow fact-specific requests for exemption 
from filing requirements for those sellers who otherwise would qualify 
as Category 2 sellers \996\ or other particular exemptions.\997\
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    \995\ PPM at 3-5.
    \996\ See Morgan Stanley; Financial Companies.
    \997\ See, e.g., Ormet at 7-11 (exemption for self use/supply, 
i.e., capacity used to self supply a corporate affiliate and 
presumptively unavailable for sale into markets); TXU at 4-5 (case-
by-case determination of whether a seller's affiliation with an 
entity that owns or controls Commission-jurisdictional transmission 
presents the possibility of vertical market power concerns).
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    847. In addition, Constellation proposes specific modifications to 
the proposal. First, Constellation requests that the Commission change 
the affiliation standard in the definition of Category 1 sellers to be 
consistent with other definitions set forth in the NOPR. Because the 
proposed language would exclude from the definition of Category 1 
sellers any affiliate of a public utility with a franchised service 
territory regardless of whether it has captive customers, Constellation 
suggests using the defined term ``franchised public utility'' \998\ 
instead of ``public utility with a franchised service territory.'' 
Constellation states that the exclusion should only apply to affiliates 
of public utilities with captive customers. Second, Constellation 
argues that a company should be considered to be a Category 1 seller so 
long as it is not affiliated with a ``franchised public utility'' in 
the same geographic region. It explains that, with this change, a 
company would qualify as a Category 1 seller in California despite the 
fact that it is affiliated with a franchised public utility in New 
England because any concerns about affiliate abuse would exist only in 
the New England market and not in California.\999\ Third, Constellation 
suggests that, if operational control over transmission facilities has 
been transferred to an RTO/ISO, then a seller's affiliation with the 
owner of such transmission facilities should not exclude the seller 
from qualifying as a Category 1 seller. Further, Constellation seeks 
clarification that the exclusions for owners of transmission facilities 
that are simply interconnection facilities, are under operational 
control of an RTO/ISO, or are subject to waiver of Order No. 888 and 
889, will also apply to affiliates of those transmission owners.
---------------------------------------------------------------------------

    \998\ Proposed 18 CFR 35.36(a)(5) defines a franchised public 
utility as ``a public utility with a franchised service obligation 
under state law and that has captive customers.''
    \999\ Similarly, Constellation contends that, if a seller and 
its affiliates own more than 500 MW of generation capacity in only 
one region and less in others, then the seller should be required to 
file updated market power analyses in only the region(s) where its 
affiliated generation exceeds the threshold.
---------------------------------------------------------------------------

Commission Determination
Adoption of Category 1/Category 2
    848. We adopt the NOPR proposal to create a category of sellers 
that are exempt from the requirement to automatically submit updated 
market power analyses, with certain modifications. As discussed further

[[Page 40005]]

below, this finding is fully consistent with our statutory obligation 
to ensure just and reasonable rates and with court decisions construing 
that obligation. Moreover, it will streamline the administration of the 
market-based rate program by focusing the Commission's resources on 
sellers that have a significant presence in the market. It also is 
supported by the majority of commenters in this proceeding.
    849. The Commission agrees with Financial Companies and Morgan 
Stanley that sellers should have notice of their status and related 
filing obligations. However, we believe the criteria we adopt herein 
are sufficiently clear so that the vast majority of sellers can easily 
determine in which category they fall. Accordingly, the Commission will 
not initially compile and release a list of sellers in each category. 
Rather, we will require all sellers that believe they fall into 
Category 1 to make a filing with the Commission at the time that 
updated market power analyses for the seller's relevant market would 
otherwise be due (based on the regional schedule for updated market 
power analyses adopted in this Final Rule). That filing should explain 
why the seller meets the Category 1 criteria\1000\ and should include a 
list of all generation assets (including nameplate or seasonal capacity 
amounts) owned or controlled by the seller and its affiliates grouped 
by balancing authority area.\1001\ The Commission will notice these 
filings and provide an opportunity for comment. The Commission will 
then act on the seller's filing, either acknowledging that the seller 
falls within Category 1 or, if it finds that the seller does not 
qualify as a Category 1 seller, directing the seller to file an updated 
market power analysis. Subsequently, all Category 1 sellers will not be 
required to file regularly scheduled updated market power analyses.
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    \1000\ These criteria, as modified in this Final Rule, include 
wholesale power marketers and wholesale power producers that own or 
control 500 MW or less of generation in aggregate per region; that 
do not own, operate or control transmission facilities other than 
limited equipment necessary to connect individual generating 
facilities to the transmission grid (or have been granted waiver of 
the requirements of Order No. 888); that are not affiliated with 
anyone that owns, operates or controls transmission facilities in 
the same region as the seller's generation assets; that are not 
affiliated with a franchised public utility in the same region as 
the seller's generation assets; and that do not raise other vertical 
market power issues.
    \1001\ In the section titled ``Regional Review and Schedule'' we 
discuss further how we implement this approach.
---------------------------------------------------------------------------

    850. With regard to sellers that fall into Category 2, these 
sellers will be required to file an updated market power analysis based 
on the schedule in Appendix D. In our orders acting on the updated 
market power analyses, the Commission will make a finding that the 
seller is a Category 2 seller, as appropriate.
    851. In addition, with regard to new applications for market-based 
rate authority, we also will make a finding regarding the category in 
which the seller falls. However, all sellers submitting initial 
applications for market-based rate authority must submit the indicative 
screens, or accept a presumption of market power in generation, and 
must submit a vertical market power analysis.
    852. We reject FirstEnergy's argument that there should be no 
requirement for any seller to file an updated market power analysis. 
Competitiveness of markets is continuing to change and, therefore, we 
are reluctant to rely only on initial market power analyses, change in 
status filings, and section 206 complaints in all cases. The burden on 
Category 2 sellers is small compared to their market presence and 
activities, and is outweighed by the fact that submission of periodic 
updated market power analyses enhances Commission oversight and public 
confidence in the regulatory process. Thus, we will require the 
submittal of regularly scheduled updated market power analyses by those 
sellers that have more of a presence in the market and are more likely 
to either fail one or more of the indicative screens or pass by a 
smaller margin than those that will qualify as Category 1 sellers, or 
that may present circumstances that could pose vertical market power 
issues, i.e., Category 2 sellers. Through regularly scheduled updated 
market power analyses for Category 2 sellers, the Commission is better 
able to evaluate the ongoing reasonableness of those sellers' charges 
and to provide for an ongoing assessment of their ability to exercise 
market power. In the absence of regularly scheduled updated market 
power analyses from the Category 2 sellers, it would be more difficult 
for the Commission to fulfill its statutory duty to ensure that market-
based rates are just and reasonable and that market-based rate sellers 
continue to lack the potential to exercise market power so that market 
forces are indeed determining the price.
    853. Because Category 1 and 2 sellers occupy different postures in 
terms of their presence in the market, it is not unduly discriminatory 
to eliminate the requirement to file a regularly scheduled updated 
market power analysis for Category 1 sellers but not Category 2 
sellers. Category 1 sellers have been carefully defined by the 
Commission to have attributes that are not likely to present market 
power concerns: ownership or control of relatively small amounts of 
generation capacity; no affiliation with an entity with a franchised 
service territory in the same region as the seller's generation 
facility; little or no ownership or control of transmission facilities 
and no affiliation with an entity that owns or controls transmission in 
the same region as the seller's generation facility; and no indication 
of an ability to exercise vertical market power. Further, based on a 
review of past Commission orders, we are aware of no entity that would 
have qualified as a Category 1 seller under this Final Rule but would 
nevertheless have failed our indicative screens necessitating a more 
thorough analysis. Thus, the Commission has provided a reasoned basis 
to distinguish Category 1 sellers from Category 2 sellers. Moreover, 
the EQR reporting requirements and change in status filings required 
for Category 2 market-based rate sellers will also apply to Category 1 
sellers. This will ensure adequate oversight of Category 1 sellers, 
even without regularly scheduled updated market power analyses. 
Further, we will continue to reserve the right to require an updated 
market power analysis from any market-based rate seller at any time, 
including for those sellers that fall within Category 1.
    854. In this regard, we agree with PPM that the Commission retains 
the tools necessary to ensure that all rates are just and reasonable, 
including initial market power evaluations, and ongoing monitoring by 
the Commission. For example, as noted above, all sellers with market-
based rates must file electronically with the Commission an EQR of 
transactions no later than 30 days after the end of the reporting 
quarter and must comply with the change in status reporting 
requirement. We note that the reporting requirement relied upon by the 
court in Lockyer is the transaction-specific data found in EQRs, which 
we continue to require of all sellers, and not updated market power 
analyses. Thus, exempting Category 1 sellers from routinely filing 
updated market power analyses does not run counter to Lockyer.
    855. With respect to EQR filings, the Commission enhanced and 
updated the post-transaction filing requirements from what they were 
during the period at issue in the Lockyer case, now requiring 
electronic reporting of, among

[[Page 40006]]

other things: \1002\ (1) A summary of the contractual terms and 
conditions in every effective service agreement for market-based power 
sales; and (2) transaction information for effective short-term (less 
than one year) and long-term (one year or greater) market-based power 
sales during the most recent calendar quarter. We also note that the 
Commission has revoked the market-based rate authority of sellers that 
have failed to comply with the EQR filing requirements.\1003\ Further, 
the Commission has utilized EQR data in determinations relating to 
market power. For example, the Commission relied in part on EQR data in 
reaching its determination that an ``alternative'' market power 
analysis submitted by Duke Power was unpersuasive.\1004\
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    \1002\ Revised Public Utility Filing Requirements, Order No. 
2001, 67 FR 31043 (May 8, 2002), FERC Stats. & Regs. ] 31,127 
(2002). Required data sets for contractual and transaction 
information are described in Attachments B and C of Order No. 2001. 
The EQR must be submitted to the Commission using the EQR Submission 
System Software, which may be downloaded from the Commission's Web 
site at http://www.ferc.gov/docs-filing/eqr.asp. The exact dates for 

these reports are prescribed in 18 CFR 35.10b. Failure to file an 
EQR (without an appropriate request for extension), or failure to 
report an agreement in an EQR, may result in forfeiture of market-
based rate authority, requiring filing of a new application for 
market-based rate authority if the seller wishes to resume making 
sales at market-based rates.
    \1003\ See Electric Quarterly Reports, 115 FERC ] 61,073 (2006); 
Electric Quarterly Reports, 114 FERC ] 61,171 (2006); Electric 
Quarterly Reports, 69 FR 57679 (Sept. 27, 2004); Electric Quarterly 
Reports, 105 FERC ] 61,219 (2003).
    \1004\ Duke Power, a Division of Duke Energy Corporation, 111 
FERC ] 61,506 at P 48, 55 (2005).
---------------------------------------------------------------------------

    856. With respect to notices of change in status, in a related 
rulemaking proceeding in early 2005, the Commission clarified and 
standardized market-based rate sellers' reporting requirement for any 
change in status that departs from the characteristics the Commission 
relied on in initially authorizing sales at market-based rates.\1005\ 
In Order No. 652, the Commission required that, as a condition of 
obtaining and retaining market-based rate authority, sellers must file 
notices of such changes no later than 30 days after the change in 
status occurs.\1006\ These requirements are codified in our 
regulations, and failure of a market-based rate seller to timely file a 
change in status report constitutes a tariff violation. If such a 
violation occurs, the Commission has the tools available to impose 
remedies, as necessary and appropriate, from the date on which the 
tariff violation occurred. Such remedies could include disgorgement of 
profits, civil penalties or other remedies the Commission finds 
appropriate based on the specific facts and circumstances.
---------------------------------------------------------------------------

    \1005\ Order No. 652 at P 47.
    \1006\ As discussed below in the Change in Status section, the 
Commission is modifying its regulations to provide that, in the case 
of power sales contracts with future delivery, such contracts are 
reportable 30 days after the physical delivery has begun.
---------------------------------------------------------------------------

    857. We note that any new market-based rate seller must conduct a 
horizontal market power analysis for our review. Furthermore, we 
reiterate that the Commission retains the ability to require an updated 
market power analysis from any seller, Category 1 or 2, at any time.
    858. We also reject those arguments made by the California 
Commission, NASUCA, and State AGs and Advocates that all sellers should 
continue to be required to file regularly scheduled updated market 
power analyses. For the reasons stated above, assertions that the 
Commission will be unable to monitor market-based rate sellers without 
requiring all sellers to file regularly scheduled updated market power 
analyses are unfounded.
    859. In response to the comments of NASUCA and Constellation, we 
make the following clarifications. We clarify that, subject to other 
conditions discussed below, Category 1 sellers include power marketers 
and power producers with 500 MW or less of generation capacity owned or 
controlled by the seller and its affiliates in aggregate per region. 
Our use of the term ``region'' is intended to be as delineated in the 
Regional Review and Schedule attached as Appendix D.
    860. We further clarify that a seller that owns, operates or 
controls, or is affiliated with an entity that owns, operates or 
controls, transmission facilities in the same region as the seller's 
generation assets does not qualify as a Category 1 seller in that 
region. This standard applies regardless of whether the total 
generation capacity owned or controlled by the seller and its 
affiliates is below 500 MW in the region.
    861. Regarding Constellation's point that a company should be 
considered Category 1 so long as it is not affiliated with a franchised 
public utility in the same region (and meets the other requirements for 
Category 1), we concur. Hence, a seller that is affiliated with a 
franchised public utility that is not in the same region in which the 
seller owns or controls generation assets may qualify as a Category 1 
seller for that region if it meets the other Category 1 criteria. 
Likewise, a seller that does not own, operate or control, and is not 
affiliated with an entity that owns, operates or controls, transmission 
in the same region in which the seller owns or controls generation 
assets may qualify as a Category 1 seller for that region.
    862. We do not adopt Constellation's proposal that we carve out an 
exemption for sellers affiliated with a franchised public utility 
without captive customers nor do we adopt the proposal to exempt those 
that are affiliated with transmission owners that have given 
operational control of their transmission facilities to RTOs/
ISOs.\1007\ Constellation has failed to adequately demonstrate that 
sellers affiliated with a franchised public utility without captive 
customers and those that are affiliated with transmission owners that 
have given operational control of their transmission facilities to 
RTOs/ISOs necessarily lack market power in generation.
---------------------------------------------------------------------------

    \1007\ We do, however, replace the term ``public utility with a 
franchised service territory'' with the defined term ``franchised 
public utility.''
---------------------------------------------------------------------------

    863. In addition, we will revise the definition of Category 1 
sellers in the regulations to include those that own, operate or 
control only transmission facilities that are ``limited equipment 
necessary to connect individual generating facilities to the 
transmission grid.'' While the NOPR included this language in the 
preamble, conforming language was inadvertently excluded from the 
definition of Category 1 sellers in Sec.  35.36(a)(2) of the proposed 
regulations.
Threshold for Category 1
    864. After considering all of the comments regarding the proposed 
cutoff between Categories 1 and 2, we believe that 500 MW or less of 
generating capacity per region is an appropriate threshold. We will use 
this value as a cutoff because, during our 15 years of experience 
administering the market-based rate program, there have only rarely 
been allegations that sellers with capacity of 500 MW or less had 
market power, and when those claims have been raised the Commission's 
review has either found no evidence of market power or found that the 
market power identified was adequately mitigated by Commission-enforced 
market power mitigation rules.\1008\ While some commenters urge the 
Commission to adopt either a higher or lower threshold, the Commission 
believes that a 500 MW threshold is both a reasonable balance as well 
as conservative enough to ensure that those unlikely to possess market 
power will be granted market-based rate authority. Moreover, as Newmont 
asserts, 500 MW is a clear, bright line that will be easy to 
administer.
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    \1008\ Moreover, as noted above, the Commission's indicative 
screens are set at conservative levels.

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[[Page 40007]]

    865. In addition and in response to commenter requests, we clarify 
that the 500 MW threshold is determined by adding all the generation 
capacity owned or controlled by the seller and its affiliates within 
the same region (as delineated in the Regional Review and Schedule 
attached as Appendix D). In keeping with our conservative approach with 
regard to which entities qualify for Category 1, we find that aggregate 
capacity in a given region best meets our goal of ensuring that we do 
not create regulatory barriers to small sellers seeking to compete in 
the market while maintaining an ample degree of monitoring and 
oversight that such sellers do not obtain market power. In this regard, 
we also clarify that although we will use aggregate capacity owned or 
controlled in a region to determine which sellers are required to file 
regularly scheduled updated market power analyses, we will continue to 
evaluate the balancing authority area in which the seller is located 
when performing our indicative screens, absent evidence to the 
contrary.\1009\
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    \1009\ As we have stated above, where a generator is 
interconnecting to a non-affiliate owned or controlled transmission 
system, there is only one relevant market (i.e., the balancing 
authority area in which the generator is located).
---------------------------------------------------------------------------

    866. While we recognize the appeal of a test that takes into 
account the size of each geographic market, such as using a percentage 
of all capacity (as opposed to a stated MW) cutoff and the use of 
uncommitted capacity rather than installed capacity, these 
methodologies are inconsistent with a straightforward, conservative 
means of screening sellers and consequently would lead to regulatory 
uncertainty. As markets and market participants can fluctuate, a 
determination of the number of MWs constituting a particular percentage 
of capacity in a regional market would have to be constantly 
recalculated and the assumptions underlying a determination could lead 
to potential challenges. Such an approach would run counter to our 
intention to provide certainty to market participants and to streamline 
the administration of the program.
    867. The Commission rejects as unnecessary suggestions by AWEA and 
PPM that we take into account the differences among generation, 
including that classified as intermittent or non-dispatchable, when 
calculating the generation capacity of a seller. We believe that many 
sellers with wind and other non-thermal capacity will fall below the 
500 MW threshold; those that do not may take advantage of simplifying 
assumptions and other means to minimize the burden of filing an updated 
market power analysis.
    868. With respect to several commenters' desire for fact-specific 
exemptions for sellers who otherwise may qualify for Category 2, we 
note that the Commission will determine on a case-by-case basis the 
category status of each seller with market-based rate authorization. In 
our attempt to keep the Category 1 criteria as simple and 
straightforward as possible, we may have swept under Category 2 
particular sellers whose circumstances make it unlikely that they could 
ever exercise market power. As a result, we will entertain and evaluate 
individual requests for exemption from Category 2 and make a finding on 
the category status of each company. However, if a seller wishes to 
request exemption from Category 2, it must make a filing seeking such 
an exemption no later than 120 days before its next updated market 
power analysis is due. We also will consider any arguments from 
intervenors that a particular seller that contends that it qualifies 
for Category 1 status based on our definition should nevertheless be 
treated as a Category 2 seller and thus be required to continue filing 
updated market power analyses.
2. Regional Review and Schedule
Commission Proposal
    869. To ensure greater consistency in the data used to evaluate 
Category 2 sellers, the Commission proposed to require ongoing updated 
market power analyses to be filed for each seller's relevant geographic 
market on a pre-determined schedule. Such a process would allow 
examination of the individual seller at the same time that the 
Commission examines other sellers in the relevant market and contiguous 
markets within a region from which power could be imported. The 
Commission appended to the NOPR a proposed schedule for the regional 
review process, rotating by geographic region with three regions being 
reviewed per year. For corporate families that own or control 
generation in multiple control areas and different regions, the 
Commission proposed that the corporate family would be required to file 
an update for each region in which members of the corporate family sell 
power during the time period specified for that region.
Comments
    870. Several commenters, including ELCON, APPA/TAPS, NRECA, Suez/
Chevron, and Newmont, support the Commission's proposal. ELCON states 
that the requirement that a seller file its updated market power 
analysis at the same time the Commission examines other sellers in the 
relevant market and region is an excellent idea because it provides a 
better picture to the Commission during its review. APPA/TAPS state 
that the regional approach will lead to data consistency and 
availability, and will allow the Commission to fulfill its obligations 
more completely. Newmont believes that the Commission's proposal 
appropriately balances the need to effectively monitor and mitigate 
market power while avoiding unnecessary and unproductive regulatory 
requirements.\1010\
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    \1010\ Newmont at 1.
---------------------------------------------------------------------------

    871. Alternatively some commenters oppose the proposal entirely, or 
suggest modifications. Reliant states that the regional review and 
schedule would significantly increase the administrative burdens of 
compliance rather than streamline them. According to Reliant, companies 
that engage in business in multiple regions of the United States would 
have to file several times over the three year schedule instead of once 
as is required currently.\1011\ Morgan Stanley and Financial Companies 
state that the Commission should require Category 2 sellers to file 
only once every three years, either with the region where they have a 
franchised service territory or the region in which they own the 
greatest amount of generation. EEI and EPSA maintain that a regional 
review will pose a great burden on utilities operating in multiple 
markets and will lead to confusion over contradictory 
information.\1012\
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    \1011\ Similarly, Allegheny, Mirant, FP&L, EEI, FirstEnergy, 
MidAmerican, TXU, Morgan Stanley, Financial Companies, and EPSA 
argue that large corporate families could find themselves in a 
perpetual triennial review that would place a substantial regulatory 
burden and expense on them.
    \1012\ EEI reply comments at 27-29, EPSA reply comments at 11-
14.
---------------------------------------------------------------------------

    872. State AGs and Advocates warn that the regional approach will 
result in a too infrequent analysis of each area. They and others state 
that, with the combined approach, each specific region will only be 
looked at completely every three years, which is less oversight than 
the Commission has currently.\1013\
---------------------------------------------------------------------------

    \1013\ See, e.g., State AGs and Advocates at 49-51, Reliant at 
9-11, Mirant at 2-6, EPSA at 39-40, EEI reply comments at 27-29, 
EPSA reply comments at 11-14.
---------------------------------------------------------------------------

    873. FirstEnergy notes that the Commission has encouraged PJM and 
Midwest ISO to eliminate ``seams'' between their respective regions and 
comments that the proposal to schedule submittal of updated market 
power analyses for sellers in these two regions

[[Page 40008]]

at different times is inconsistent with the reasons underlying adoption 
of common filing dates. Mirant states that the limited number of 
consultants that perform market power analyses use separate, 
proprietary databases and warns that the market data submitted on a 
regional basis will remain inconsistent. Further, Mirant asserts that 
there may be antitrust issues if a group of competing sellers jointly 
hires one consultant.
    874. NRECA replies that any increase in the burden on sellers does 
not outweigh the substantial benefits of greater data consistency and a 
complete picture of each region under review.\1014\ APPA/TAPS assert 
that the Commission should not sacrifice improvements to its program 
for the interests of a few companies and that any increased cost to 
companies associated with regional reviews is outweighed by the 
companies' profits from market-based rate sales. They dismiss concerns 
regarding a scarcity of consultants, noting that the market should 
respond to an increase in demand for consulting services, and that 
``competition will force efficiency gains to be passed along to 
consultants'' clients.'' \1015\ Further, with respect to a group of 
sellers jointly hiring a consultant to produce a market analysis, they 
comment that antitrust counsel should be able to ensure joint 
representation does not result in improper information sharing.\1016\
---------------------------------------------------------------------------

    \1014\ NRECA reply comments at 28-30.
    \1015\ APPA/TAPS reply comments at 20.
    \1016\ Id. at 19-21.
---------------------------------------------------------------------------

    875. PNM/Tucson state that the updated market power analyses in a 
given region should be deliberately staggered so that utilities are 
able to build upon data sets already submitted in prior proceedings, 
instead of each having to construct its own, which would result in 
varying, competing data sets.
    876. Mirant and FP&L add that with all the entities filing 
concurrently it will be difficult for some, such as non-transmission 
owning entities, to acquire the necessary data (i.e., simultaneous 
import limit data). NRECA, Mirant and Powerex ask the Commission to 
have transmission-owning utilities file their updated market power 
analyses (or information necessary for others to perform preliminary 
screens) at a minimum 90 days prior to the regional due date; 
MidAmerican requests that the Commission require each transmission 
provider to post to its OASIS a simultaneous import study 60 days 
before the filing deadline that could be used by first-tier entities to 
develop their market power analyses. Similarly, Suez/Chevron suggests 
requiring RTOs and/or control area operators in each region to file 
certain information in advance of the filing deadline so that sellers 
can rely on uniform baseline data.\1017\ EEI critiques the proposals 
for sharing of data prior to submission of triennial reviews, stating 
that this would increase the complexity of an already cumbersome 
process.\1018\
---------------------------------------------------------------------------

    \1017\ The data Suez/Chevron refer to include the information 
indicated in proposed Appendix C, Pivotal Supplier Analysis at Rows 
E through J, O, P and Q and also proposed Appendix C, Wholesale 
Market Share Analysis at Rows F through Q, and the accompanying 
workpapers.
    \1018\ EEI reply comments at 27-29.
---------------------------------------------------------------------------

    877. APPA/TAPS state that data sharing by companies should be 
enhanced by regional reviews, not impaired, and that more robust data 
and opportunities to reconcile conflicting submissions with a regional 
review will lead to a better analysis by the Commission.\1019\
---------------------------------------------------------------------------

    \1019\ APPA/TAPS reply comments at 19-21.
---------------------------------------------------------------------------

    878. MidAmerican asserts that the Commission should allow more time 
between the end of the qualification period and the filing of market 
power analyses. It states that these analyses require Form 1 data that 
is not available until several months after the end of the calendar 
year and that control area loads as filed in Form 714 are frequently 
not available until the third quarter following the end of the calendar 
year, usually July. Additionally, it states that generation and load 
data from Forms EIA-860 and EIA-861, respectively, are likewise not 
available until late in the following year. Accordingly, it suggests 
that market analyses should not be due until mid-October following the 
end of the qualification period, allowing roughly 90 days between the 
availability of Form 714 and the deadline for filing.\1020\
---------------------------------------------------------------------------

    \1020\ See MidAmerican at 33.
---------------------------------------------------------------------------

    879. Many commenters also argue that the Commission should extend 
the time until the first regional reviews are due. Suggested beginning 
filing dates include: the first filing period for a region that is no 
earlier than a company's next required updated analysis; \1021\ the 
first filing period that occurs no earlier than two years from the 
latest filed updated analysis; \1022\ the first filing period that is 
no earlier than one year from the latest filed updated analysis; \1023\ 
or 180 days after the Final Rule is published in the Federal 
Register.\1024\ Duke suggests that, rather than extending the first 
filing times, the Commission clarify that those entities due to file 
their next updates before the scheduled regional reviews are due can 
forgo making any interim filings.
---------------------------------------------------------------------------

    \1021\ See Consumers at 2-4, Allegheny at 16-18.
    \1022\ See MidAmerican at 30-33.
    \1023\ See Constellation at 13.
    \1024\ See Allegheny at 16-18.
---------------------------------------------------------------------------

    880. APPA/TAPS ask the Commission to extend the period for 
commenting on the updated market power analyses from the current 21-day 
comment period to 60 days, at a minimum. They state that because 
numerous sellers will file the updated market power analyses 
contemporaneously, intervenors should be given sufficient time to make 
meaningful use of the expanded body of information and to prepare 
multiple pleadings dealing with various sellers in the region. They add 
that the additional time should improve the quality of the analyses 
that the Commission receives from intervenors.
    881. Finally, regarding the Commission's proposal to require all 
updates (and all new applications) to include an appendix listing all 
generation assets owned or controlled by the corporate family, in-
service dates and capacity ratings by unit, Duke agrees with the 
proposal that the appendix should also reflect all electric 
transmission and natural gas intrastate pipelines and/or gas storage 
facilities owned or controlled by the corporate family. It states that 
having such a standardized listing will be helpful both to the 
Commission and to other market participants.\1025\ Duke cautions, 
however, that including the location of transmission and gas pipeline 
facilities in the appendix could conflict with CEII requirements, and 
requests clarification that sellers will have discretion with 
locational descriptions.
---------------------------------------------------------------------------

    \1025\ Duke at 49.
---------------------------------------------------------------------------

Commission Determination
    882. The Commission adopts the NOPR proposal to conduct a regional 
review of updated market power analyses, with certain modifications. We 
agree with commenters such as APPA/TAPS that the regional approach will 
lead to data consistency and availability. In this regard, both the 
Commission and market participants will benefit from greater data 
consistency that will result from regional examination of updated 
market power analyses and a methodical study of all sellers in the same 
region. This will give the Commission a more complete view of market 
forces in each region and the opportunity to reconcile conflicting 
submissions, enhancing our ability to ensure that sellers' rates remain 
just and reasonable.
    883. Although some commenters express concern that a regional 
review approach will increase administrative

[[Page 40009]]

burdens, particularly for sellers operating in multiple regions, we 
believe that the Commission's proposal properly and fairly balances the 
need to effectively monitor and mitigate market power in wholesale 
markets with the desire to minimize any administrative burden 
associated with the filing and review of updated market power analyses. 
While we recognize that some sellers may have to file updates more 
frequently than they do currently, we have carefully balanced the 
interests of all involved, and we believe that regional reviews of 
updated market analyses is both needed and desirable and will enhance 
the Commission's ability to continue to ensure that sellers either lack 
market power or have adequately mitigated such market power.
    884. We note that sellers currently must prepare a market power 
analysis for all of their generation assets nationwide. Some sellers 
with assets in multiple regions have chosen to submit their individual 
updated market power analyses when each is due (every three years) 
rather than combining them into a single updated market power analysis. 
Others file one updated market power analysis for the entire corporate 
family, with individual analyses of the different markets in which 
their assets are located. Either way, the same analyses must be filed 
under the status quo and the approach adopted in this Final Rule. The 
timing may differ, but the increased burden is minimal.\1026\
---------------------------------------------------------------------------

    \1026\ In this regard, we note that preparation of multiple 
market power analyses is likely less burdensome and less expensive 
than what would otherwise be required under cost-based regulation 
which can result in extended administrative litigation to determine 
the just and reasonable rate.
---------------------------------------------------------------------------

    885. Nevertheless, considering the comments received and upon 
further review of the Commission's proposal, we believe that some of 
the proposed regions should be consolidated. Therefore, we will reduce 
the number of regions from the proposed nine to six. In Appendix D we 
identify the six regions (Northeast, Southeast, Central, Southwest 
Power Pool, Southwest, and Northwest), and will require Category 2 
sellers that own or control generation assets in each region to file an 
updated market power analysis for that region every three years based 
on a rotating schedule shown in the Appendix.\1027\ We believe that, 
with fewer and larger regions, some sellers will likely be present in 
fewer regions and administrative burdens for those sellers accordingly 
will be reduced. In addition, the decrease in the number of regions 
will also extend the time period between filings. In the NOPR, the 
Commission stated that three regions would be reviewed per year, with 
four months between each set of filings. Here we adopt review of two 
regions per year, with the filing periods six months apart.
---------------------------------------------------------------------------

    \1027\ Concerning power marketers that may not own or control 
generation assets in any region, we will require the submission of a 
filing explaining why the seller meets the Category 1 criteria, as 
discussed above. Power marketers must submit such a filing with the 
first scheduled geographic region in which they make any sales.
---------------------------------------------------------------------------

    886. Regarding FirstEnergy's argument that PJM and Midwest ISO 
should be placed in the same region, we continue to encourage PJM and 
the Midwest ISO to address ``seams'' issues. However, we find that 
placing them in different regions for the purpose of determining when 
an updated market power analysis is submitted should in no way affect 
or discourage efforts to address seams between these two regions. Other 
considerations (such as balancing RTO/ISO and non-RTO/ISO filings, and 
scheduling approximately the same number of filings each year) outweigh 
FirstEnergy's concerns.
    887. The Commission rejects the arguments by some commenters that 
the regional approach will result in too infrequent an analysis of each 
area. As a practical matter, currently sellers are required to file an 
updated market power analysis every three years. In the intervening 
years between updated market power analyses, most utilities either 
enjoy the 18 CFR 35.27(a) exemption from filing a generation market 
power analysis or rely on the previously filed updated market power 
analysis. The regional approach will provide the Commission with a 
snapshot of sellers across a larger area and will provide a more 
accurate view of simultaneous import capability into the relevant 
geographic markets under review. Accordingly, contrary to claims that 
the regional approach will result in less Commission oversight, the 
regional approach will enhance the Commission's ability to analyze 
market power using better data with less opportunity for conflicting 
claims of ownership or control of generation assets.
    888. Regarding concerns about the scarcity of consulting firms, we 
note that our proposal will not necessarily increase the number of 
market power analyses to be performed (indeed, by exempting all 
Category 1 sellers from submitting updated market power analyses, the 
number may be decreased). We agree with APPA/TAPS that any shortage of 
consultants performing market power analyses should be temporary as 
firms adjust to a new schedule reflecting the regional review timetable 
and take precautions to prevent improper information sharing.
    889. We agree with commenters that transmission-owning entities 
should file their updated market power analyses in advance of others in 
each region. Thus, the Commission will modify the schedule proposed in 
the NOPR to better allow sellers to rely on the transmission-owning 
utilities' information, and we will adopt a staggered filing approach 
for each region which will require different types of entities to file 
at different times. The transmission-owning utilities, which have the 
information necessary to perform SIL studies, will be required to file 
their updated market power analyses first. Six months later, all others 
in that region will be required to file their updated market power 
analyses.\1028\
---------------------------------------------------------------------------

    \1028\ If the Commission has not processed a particular SIL 
study before six months have passed and non-transmission owning 
entities must file their updated market power analyses, then those 
entities should rely on the filed SIL study. If the initial SIL 
study subsequently changes, the Commission will make conforming 
adjustments as needed.
---------------------------------------------------------------------------

    890. Staggering the time periods within which transmission-owning 
and non-transmission-owning utilities will be required to submit their 
updated market power analyses will provide an opportunity for those 
non-transmission owning sellers that need simultaneous transmission 
import limits to perform the screens to rely on the SIL studies 
performed by the transmission-owning utilities rather than rely on a 
``proxy'' for the import limits.
    891. Our experience is that sellers located in RTOs/ISOs typically 
do not need to rely on a SIL study in performing the screens, and 
transmission-owning utilities in RTOs/ISOs typically do not prepare or 
submit such studies. Accordingly, staggered filings for sellers in 
RTOs/ISOs may not be necessary for purposes of data availability. 
Nevertheless, we will retain the staggered filing deadlines for all 
regions for consistency and to avoid any confusion in this regard. If a 
particular seller that is located in an RTO/ISO finds that it needs 
import data in order to complete its market power analysis, we expect 
the RTO/ISO to assist such sellers if requested.
    892. In response to MidAmerican's suggestion that the Commission 
allow adequate time between the date that all data is available and the 
date that a region's analyses are due, we will schedule the updates to 
be filed in December (12 months after the study year), and June (18 
months after the study year). We note that studies due in

[[Page 40010]]

December and June may be filed anytime during the applicable month. 
Such a schedule will allow adequate time for the data to be available 
(at least 6 weeks after EIA Forms 860 and 861 become public) and the 
analyses to be completed.
    893. In response to commenters' requests that the Commission extend 
the time until the first analyses are due, we will commence the 
schedule in December 2007. The Commission believes this will provide 
adequate notice and time to prepare the analyses. In addition, we 
clarify that sellers that otherwise would have been required to file an 
updated market power analysis before the effective date of this rule 
should submit their updated market power analyses in accordance with 
past orders directing them to do so. Starting with the effective date 
of this rule, sellers should submit their updated market power analyses 
in accordance with the schedule set forth in Appendix D.
    894. We also agree with the suggestion of APPA/TAPS to extend the 
period for intervenors to comment on the updates. We agree that 
extending the comment period will allow intervenors a better 
opportunity to review and comment on filings, especially considering 
the large number of filings that will be submitted at one time. For 
that reason, the Commission will establish a 60-day comment period for 
updated market power analyses. Further, we adopt the NOPR proposal to 
require that with each new application and updated market power 
analysis, the seller must list in an appendix, among other things, all 
affiliates that have market-based rate authority and identify any 
generation assets owned or controlled by the seller and any such 
affiliate. In addition, we extend this obligation to relevant change in 
status notifications.\1029\ We believe that requiring the submission of 
such data will provide the Commission with more accurate and up-to-date 
information about each corporate family and will address some of our 
concerns regarding confusion that has occurred with respect to 
corporate families and, in particular, what sellers are authorized to 
transact at market-based rates in each corporate family.
---------------------------------------------------------------------------

    \1029\ Relevant change in status notifications would include, 
for example, the addition of new facilities, but not a name change.
---------------------------------------------------------------------------

    895. Accordingly, the appendix must list all generation assets 
owned (clearly identifying which affiliate owns which asset) or 
controlled (clearly identifying which affiliate controls which asset) 
by the corporate family by balancing authority area, and by geographic 
region, and provide the in-service date and nameplate and/or seasonal 
ratings by unit. As a general rule, any generation assets included in a 
seller's or a seller's affiliate's market study should be listed in the 
asset appendix. We find that the in-service date and nameplate and/or 
seasonal ratings help identify and provide the Commission and market 
participants with critical market information. In addition, the 
appendix must reflect all electric transmission and natural gas 
intrastate pipelines and/or gas storage facilities owned or controlled 
by the corporate family and the location of such facilities.
    896. In response to Duke, we clarify that CEII data is more 
detailed than ``simply [giving] the general location of the critical 
infrastructure.'' \1030\ As the location of the facilities listed in 
the appendix need only include the balancing authority area and 
geographic region (see sample appendix attached as Appendix B) in which 
they are located, we do not anticipate that any CEII will be disclosed.
---------------------------------------------------------------------------

    \1030\ 18 CFR 388.113(c)(1)(iv).
---------------------------------------------------------------------------

F. MBR Tariff

Commission Proposal
    897. In the NOPR, the Commission proposed to adopt a market-based 
rate tariff of general applicability (MBR tariff), applicable to all 
sellers authorized to sell electric energy, capacity or ancillary 
services at wholesale at market-based rates, as a condition of market-
based rate authority. The MBR tariff, as proposed, would require each 
seller to comply with the applicable provisions of the market-based 
rate regulations to be codified at 18 CFR Part 35, Subpart H. The 
Commission proposed that each seller would be required to list on the 
MBR tariff the docket numbers and case citations, where applicable, of 
any proceedings where the seller received authorization to make sales 
of energy between affiliates or where its market-based rate authority 
was otherwise restricted or limited.
    898. The Commission explained that not all of the provisions of the 
proposed regulations may be applicable to all sellers. For example, a 
seller may not wish to offer ancillary services under the tariff. The 
Commission sought comments regarding whether a placeholder should be 
reserved in the MBR tariff for the seller to indicate those parts of 
the regulations that are not applicable to it.
    899. The Commission stated that this streamlining effort is not 
intended to reduce the flexibility of sellers and customers in 
negotiating the terms of individual transactions. The Commission noted 
that sellers would continue to negotiate the terms and conditions of 
sales entered into under their MBR tariff, and the terms and conditions 
of those underlying agreements and the transaction data would be 
reflected in the quarterly EQRs. The Commission stated that if sellers 
wish to offer or require certain ``generic'' terms and conditions that 
in the past were contained in their market-based rate tariff, they may 
place customers on notice of such requirements by including such 
information on a company Web site and include any related provisions in 
individual transaction agreements. The Commission explained its desire 
that the MBR tariff reflect, in a consistent manner, only those matters 
that are required to be on file.\1031\
---------------------------------------------------------------------------

    \1031\ NOPR at P 163.
---------------------------------------------------------------------------

    900. Further, rather than each entity having its own MBR tariff, 
which can result in dozens of tariffs for each corporate family with 
potentially conflicting provisions, the Commission proposed that each 
corporate family have only one tariff, with all affiliates with market-
based rate authority separately identified in the tariff.\1032\ The 
Commission stated that this would reduce the administrative burden and 
confusion that occurs when there are multiple, and potentially 
conflicting, tariffs in a single corporate family, and would allow the 
Commission and customers to know what sellers are in each corporate 
family.
---------------------------------------------------------------------------

    \1032\ Id. at P 164.
---------------------------------------------------------------------------

1. Tariff of General Applicability
Comments
    901. Several commenters do not support the adoption of a tariff of 
general applicability. Allegheny argues that ``the Commission is 
without legal authority to impose a one-size-fits-all market-based rate 
tariff.'' \1033\ It argues that the Commission has made no finding of 
undue discrimination and is not proposing to act under FPA section 206, 
and asserts that administrative efficiency is an insufficient 
justification to impose a standardized tariff on market-based rate 
sellers. Similarly, FirstEnergy asserts that requiring a uniform MBR 
tariff would impose undue administrative burdens on sellers, as each 
would have to make a compliance filing modifying its currently 
effective tariff and would also

[[Page 40011]]

have to expand its compliance program to confirm that its tariff was in 
conformance with the uniform tariff.
---------------------------------------------------------------------------

    \1033\ Allegheny at 20.
---------------------------------------------------------------------------

    902. Xcel states that the Commission has not made clear its basis 
for and expected benefit from a pro forma tariff. Xcel suggests that, 
if it is adopted, then the Commission should describe any limitations 
on a seller's market-based rate authority, in addition to identifying 
any docket numbers where they were imposed.\1034\
---------------------------------------------------------------------------

    \1034\ Xcel at 17.
---------------------------------------------------------------------------

    903. Similarly, Avista Corporation believes that all of the terms 
and conditions of a tariff should be included in one easily accessible 
place. Requiring that certain terms and conditions be posted on a 
company Web site, rather than the tariff, is bound to cause unnecessary 
confusion as to which terms and conditions apply, and will increase the 
burden on both the utilities to notify, and customers to remain 
apprised, of when those terms and conditions change.\1035\ 
Additionally, FirstEnergy states that a process by which a seller 
places customers on notice of such terms and conditions beyond the 
minimum by including such information on a company Web site, and 
including related provisions in individual transaction agreements, 
would be cumbersome at best, and would deprive sellers and customers of 
the benefit of having the ``generic'' terms and conditions in one 
document.\1036\
---------------------------------------------------------------------------

    \1035\ Avista at 10-12.
    \1036\ First Energy at 27-31.
---------------------------------------------------------------------------

    904. Commenters who responded to the question of whether a 
placeholder should be reserved in the tariff to indicate parts of the 
regulations that are not applicable to the seller, support the idea of 
a placeholder.\1037\
---------------------------------------------------------------------------

    \1037\ Avista at 10; MidAmerican at 33 (suggesting that the 
placeholder could be included as an attachment to each seller's 
tariff in order to preserve the generic nature of the tariff 
itself); Progress Energy at 19.
---------------------------------------------------------------------------

    905. Mirant notes that the sample MBR tariff attached to the NOPR 
did not provide for specific RTO/ISO ancillary service products and 
states that it is unclear how the Commission would identify which 
seller under the corporate tariff is permitted to sell the specific 
ancillary services traded in each region. Mirant asks whether the 
Commission would require each seller of ancillary services to maintain 
an ancillary services tariff on file with the Commission. Mirant 
further notes that some sellers not located in an RTO/ISO have been 
granted authorization to sell ancillary services at market-based rates 
if they post those services on their Web sites and suggests that the 
requirement that sellers maintain such a Web site would have to be 
cross-referenced in the corporate tariff.
    906. EEI states that companies with operations in multiple markets 
may need to tailor their market-based rate tariffs to reflect the 
particular circumstances of each market. This will be true for RTO and 
ISO markets as well as non-RTO markets. In each of these cases, 
participants in the markets typically must agree to abide by specific 
market terms and conditions that may need to be reflected in the 
tariff. Therefore, EEI encourages the Commission to allow each company 
to file multiple tariffs, as may be necessary to reflect these market 
differences.\1038\
---------------------------------------------------------------------------

    \1038\ EEI at 49.
---------------------------------------------------------------------------

    907. Regarding the timing of tariff implementation, MidAmerican 
comments that the Commission should apply the new tariff prospectively 
only to future transactions, and urges that existing tariffs should be 
unaffected until existing transactions expire. MidAmerican observes 
that if existing tariffs containing terms and conditions are replaced 
by the proposed generic tariff, then neither the new tariff nor the 
existing service agreements will reflect the terms and conditions of 
ongoing transactions.
    908. ELCON supports the proposed MBR tariff, believing that it will 
be more customer-friendly. APPA/TAPS agree, stating that a pro forma 
tariff will help by addressing variations in MBR tariffs that increase 
transaction costs by creating potential confusion about applicable 
terms and conditions.\1039\ A number of commenters find some merit in 
the concept of the MBR tariff, but request clarifications or 
revisions.\1040\ Some of these entities comment that companies with 
operations in multiple markets may need to tailor their tariffs to 
reflect the particular circumstances of each market, and state that 
participants in organized markets typically must agree to abide by 
specific terms that may need to be reflected in their tariffs.
---------------------------------------------------------------------------

    \1039\ EEI counters APPA/TAPS, asserting that each seller's MBR 
tariff in a given market is fully available to market participants, 
so there should be no confusion. EEI reply comments at 30-31.
    \1040\ FirstEnergy at 27-29; Constellation at 27-29; Progress 
Energy at 19-23.
---------------------------------------------------------------------------

    909. Indianapolis P&L asserts that any restrictions on market-based 
rate authority should be in a tariff, rather than in Commission orders. 
It believes that ``converting concepts (e.g., all sales in a control 
area will be mitigated) into precise contract-worthy terms and 
conditions can be very difficult'' and argues that the best way to 
prevent misunderstandings between parties is to have ``precise, 
transparent and, publicly-available language in a tariff explaining the 
precise conditions on an entity's market-based rate authority.'' \1041\ 
Indianapolis P&L further warns that ``having restrictions on an 
entity's market-based rate authorization contained in a tariff only 
through cross-reference to a Commission order may run afoul of the FPA 
requirement that rates be `on file' with the Commission.'' \1042\
---------------------------------------------------------------------------

    \1041\ Indianapolis P&L at 15.
    \1042\ Id.
---------------------------------------------------------------------------

    910. Constellation seeks clarification that a seller that has 
received waiver from the code of conduct need not report in its MBR 
tariff that the affiliate restrictions in proposed Sec.  35.39 do not 
apply to it. Alternatively, Constellation suggests that the Commission 
allow sellers to list the appropriate docket numbers in which the 
Commission has granted waivers of the code of conduct or provide a 
place to indicate that the provisions are not applicable. Constellation 
notes that many market-based rate sellers have included provisions in 
their tariffs regarding reassignment of transmission capacity and sale 
of firm transmission rights, congestion contracts, or fixed 
transmission rights (as a group, ``FTRs''), and requests that the 
Commission either provide for inclusion of such provisions in the MBR 
tariff or state affirmatively that they will not be required.
Commission Determination
    911. In the NOPR, the Commission explained that it was acting 
pursuant to sections 205 and 206 of the FPA in proposing to amend its 
regulations to govern market-based rate authorizations for wholesale 
sales of electric energy, capacity and ancillary services by public 
utilities, ``including modifying all existing market-based rate 
authorizations and tariffs so they will be expressly conditioned on or 
revised to reflect certain new requirements proposed herein.'' \1043\ 
Section 205 of the FPA requires that all rates for sales subject to our 
jurisdiction, and all rules and regulations pertaining to such rates, 
be just and reasonable. Section 206 of the FPA provides that, when the 
Commission finds that a rate or a rule, regulation or practice 
affecting a rate, is unjust or unreasonable, the Commission shall 
determine the just and reasonable rate, rule or regulation and order it 
so.
---------------------------------------------------------------------------

    \1043\ NOPR at P 1.
---------------------------------------------------------------------------

    912. Based on careful consideration of the comments received, the 
Commission agrees that complete uniformity of market-based rate tariffs 
is not necessary. However, pursuant to our

[[Page 40012]]

authority under sections 205 and 206, we conclude that the lack of 
consistent tariff form and content has hampered our ability to manage 
the market-based rate program in an efficient manner and has introduced 
uncertainty for potential customers. We find that continuing to allow 
basic inconsistencies in the market-based rate tariffs on file with the 
Commission is unjust and unreasonable. Nevertheless, we find that we 
can achieve our goal without imposing a uniform tariff requirement on 
all sellers by, instead, requiring that all sellers revise their 
market-based rate tariffs to contain certain standard provisions, as 
discussed below.
    913. We believe the approach we adopt here addresses the concerns 
of commenters that the Commission not impose a one-size-fits-all 
approach while, at the same time, presenting a uniform set of required 
provisions that will provide adequate certainty and will be more 
customer friendly. In addition, we believe that allowing sellers to 
include seller specific terms and conditions in their market-based rate 
tariffs will offer a greater degree of transparency and serve customers 
by providing for the opportunity to have all terms and conditions 
identified and in one place. As Progress Energy asserts, ``[g]reater 
consistency of tariffs within the industry * * * will not only reduce 
customer confusion, it also will reduce the administrative burden of 
those responsible for the implementation and administration of the 
tariff.'' \1044\
---------------------------------------------------------------------------

    \1044\ Progress Energy at 19-20.
---------------------------------------------------------------------------

    914. Accordingly, in this Final Rule, we adopt two standard 
``required'' provisions that each seller must include in its market-
based rate tariff: a provision requiring compliance with the 
Commission's regulations and a provision identifying any limitations 
and exemptions regarding the seller's market-based rate authority.
    915. In particular, with regard to compliance with the Commission's 
regulations, we will require each seller to include the following 
provision in its market-based rate tariff:

    Seller shall comply with the provisions of 18 CFR Part 35, 
Subpart H, as applicable, and with any conditions the Commission 
imposes in its orders concerning seller's market-based rate 
authority, including orders in which the Commission authorizes 
seller to engage in affiliate sales under this tariff or otherwise 
restricts or limits the seller's market-based rate authority. 
Failure to comply with the applicable provisions of 18 CFR Part 35, 
Subpart H, and with any orders of the Commission concerning seller's 
market-based rate authority, will constitute a violation of this 
tariff.

    916. We also will require that the seller include a provision 
identifying all limitations on its market-based rate authority 
(including markets where the seller does not have market-based rate 
authority) and any exemptions from, or waivers of, or blanket 
authorizations under the Commission's regulations that the seller has 
been granted (such as exemption from affiliate sales restrictions; 
waiver of the accounting regulations; blanket authority under Part 34 
for the issuances of securities and liabilities, etc.), including cites 
to the relevant Commission orders.
    917. In addition to the required tariff provisions, we also will 
adopt a set of standard provisions (which we reference herein as 
``applicable provisions'') that must be included in a seller's market-
based rate tariff to the extent that they are applicable based on the 
services provided by the seller. For example, if the seller's sales 
under its market-based rate tariff are subject to mitigation, it must 
include the standard provision governing mitigated sales. Similarly, if 
the seller makes sales of certain ancillary services in certain RTOs/
ISOs, or if it makes sales of ancillary services as a third-party 
provider, it must include the standard ancillary services provisions, 
as applicable.
    918. Attached hereto as Appendix C is a listing of the standard 
required provisions and the standard applicable provisions. The 
Commission will post these provisions on its web site and will update 
them as appropriate.
    919. In addition, as discussed more fully below, we will permit 
sellers to list in their market-based rate tariffs additional seller-
specific terms and conditions that go beyond the standard provisions 
set forth in Appendix C.
    920. As Constellation observes, the uniform MBR tariff proposed in 
the NOPR did not provide for sellers to offer reassignment of 
transmission capacity or FTRs. As revised in this Final Rule, Appendix 
C does not contain a standard provision for the reassignment of 
transmission capacity. The Commission believes that, although these 
items have historically been offered in the context of sales of 
electric energy and capacity, they are transmission-related rather than 
generation services. Accordingly, the Commission has made provision for 
reassignment of transmission capacity in the revised OATT, as discussed 
in Order No. 890.\1045\ Thus, we state affirmatively here that 
provisions concerning the reassignment or sale of transmission capacity 
or FTRs are not required to be included in a seller's market-based rate 
tariff, nor is it appropriate to include transmission-related services 
in the seller's market-based rate tariff. Sellers seeking to reassign 
transmission capacity should adhere to the provisions of Order No. 890 
\1046\ and should revise their market-based rate tariffs to remove 
provisions governing these services at the time they otherwise revise 
their tariffs to conform them to the standard provisions discussed 
herein.
---------------------------------------------------------------------------

    \1045\ Order No. 890, FERC Stats. & Regs. ] 31,241 at P 814-816 
& n.496.
    \1046\ Id. at P 816.
---------------------------------------------------------------------------

    921. Regarding FTRs and, incidentally, virtual trading,\1047\ we 
note that Commission-approved market rules for RTOs/ISOs address 
resales of FTRs and virtual trading to ensure that no market power is 
exercised in such trades. In addition, sellers engaging in these 
activities sign a participation agreement with RTOs/ISOs which require 
them to abide by those market rules. Hence, the approval of the market 
rules in conjunction with approval of the generic participation 
agreement by the Commission constitutes authorization for public 
utilities to engage in the resale of FTRs and virtual transactions, and 
no separate authorization is required under the FPA. The Commission's 
monitoring of the effectiveness of the market rules and oversight of 
participants engaging in FTR resales and virtual trading in the RTO/ISO 
markets provide sufficient protections against the exercise of market 
power. Nevertheless, if the Commission concludes in the future that a 
separate section 205 authorization would better enable us to ensure 
that FTR resales or virtual trading do not result in unjust and 
unreasonable

[[Page 40013]]

wholesale rates, the Commission may change the filing requirements for 
engaging in these activities.\1048\
---------------------------------------------------------------------------

    \1047\ Virtual trading involves sales or purchases in an RTO/ISO 
day-ahead market that do not go to physical delivery. For example, 
virtual bidding allows entities that do not serve load to make 
purchases in the day-ahead market. Such purchases are subsequently 
sold in the real-time spot market. Likewise, entities without 
physical generating assets can make power sales in the day-ahead 
market that are subsequently purchased in the real-time market. By 
making virtual energy sales or purchases in the day-ahead market and 
settling these positions in the real-time, any market participant 
can arbitrage price differences between the two markets. For 
example, a participant can make virtual purchases in the day-ahead 
if the prices are lower than it expects in the real-time market, and 
then sell the purchased energy back into the real-time market. The 
result of this transaction would be to raise the day-ahead price 
slightly due to additional demand and, thus, improve the convergence 
of the day-ahead and real-time energy prices due to additional 
supply in the real-time. Virtual trading is not limited to entities 
without assets. For example, generators or loads that prefer to 
transact at the real-time price may use virtual trading to 
accomplish this without having to under-schedule load or withhold 
generation from the day-ahead market by submitting matching virtual 
trades.
    \1048\ To the extent that this position departs from our holding 
in California Independent System Operator, Inc., 89 FERC ] 61,153 at 
61,435-36 (1999) (requiring, among other things, that all public 
utility resellers of FTRs file a rate schedule for authorization to 
make resales) we note that that analysis rested on Order No. 888's 
filing requirements for resales of transmission capacity. As Order 
No. 890 has modified the filing requirements with respect to 
reassignments of transmission capacity (in addition to the reasons 
cited above) we find it appropriate not to require a separate rate 
schedule for FTRs or virtual trading at this time.
---------------------------------------------------------------------------

    922. To the extent that individual companies within a corporate 
family need or desire a tariff separate from their affiliates, the 
Commission will allow this, as discussed below. Although EEI asserts 
that participants in organized markets may need to meet the 
requirements of various organized markets, EEI offers no specific 
examples in this regard. Nevertheless, we believe that our action to 
replace the uniform MBR tariff proposed in the NOPR with standard 
provisions that we will require to be included in a seller's market-
based rate tariff and the allowance of seller specific terms and 
conditions in the market-based rate tariff should meet the needs of all 
sellers with market-based rate authority.
    923. We will require all market-based rate sellers to make section 
206 compliance filings to modify their existing tariffs to include the 
standard required provisions set forth in Appendix C as well as any of 
the standard applicable provisions. These compliance filings are to be 
made by each seller the next time the seller proposes a tariff change, 
makes a change in status filing, or submits an updated market power 
analysis (or a demonstration that Category 1 status is appropriate) in 
accordance with the schedule in Appendix D.
    924. One of the required standard provisions (the compliance with 
Commission regulations provision) states that failure to comply with 
the applicable provisions of the regulations adopted in this Final Rule 
or with any Commission orders concerning a seller's market-based rate 
authority will constitute a violation of the seller's tariff. As 
provided in this Final Rule, the regulations at 18 CFR Part 35, Subpart 
H will become effective 60 days after publication of this Final Rule in 
the Federal Register. Accordingly, this provision will be considered 
part of each seller's market-based rate tariff effective as of the 
effective date of this Final Rule. As noted above, all sellers will be 
required to amend their market-based rate tariffs to include the 
required standard provisions, as well as the required applicable 
provisions, either at the time that they file any other amendment to 
their current tariffs, when they report a change in status, or when 
they file their updated market power analysis, whichever occurs first. 
However, regardless of the date on which sellers make their compliance 
filing, the provision providing that failure to abide by the 
regulations will constitute a tariff violation will be considered part 
of each seller's current market-based rate tariff as of 60 days after 
the date of publication of this Final Rule in the Federal Register.
2. Placement of Terms and Conditions
Comments
    925. In the NOPR, the Commission observed that the purpose of an 
MBR tariff of general applicability is not to direct the terms and 
conditions of particular sales but to ensure that the tariff on file 
reflects in a consistent manner only those matters that are required to 
be on file, namely, the identity of the seller(s), the docket number(s) 
of the market-based rate authorization, the seller's requirement to 
follow the conditions of market-based rate authorization contained in 
the proposed regulations, and that the rates, terms and conditions of 
any particular sale will be negotiated between the seller and 
individual purchasers. The Commission stated that sellers could offer 
other ``generic'' terms and conditions as information on a company Web 
site.
    926. In response, several commenters state that requiring companies 
to move generic terms and conditions to a company Web site, or to 
replicate them in individual agreements or rely on Commission orders, 
would be confusing and/or overly cumbersome.\1049\ Avista and 
FirstEnergy believe that all of the terms and conditions of a tariff 
should be in one easily accessible place; otherwise, sellers and 
customers would be deprived of the benefit of having them in one 
document. According to FirstEnergy, this ``would be contrary to the 
goal of establishing a `customer-friendly tariff' as contemplated in 
the NOPR.'' \1050\ Further, FirstEnergy states that the fact that the 
Commission may not review individualized commercial terms included in 
tariffs does not make it unjust and unreasonable for sellers to include 
such terms in their tariffs; thus, there is no basis for the Commission 
to exercise its authority under FPA Sec.  206 to require changes to 
existing market-based rate tariffs. However, Progress Energy agrees 
with the Commission that commercial terms and conditions for sales 
under the MBR tariff should not be filed for Commission review.
---------------------------------------------------------------------------

    \1049\ Avista at 10-12; Indianapolis P&L at 14-15; FirstEnergy 
at 27-31.
    \1050\ FirstEnergy at 29.
---------------------------------------------------------------------------

Commission Determination
    927. As discussed above, we find consistency of standard market-
based rate tariff provisions to be essential, and we modify the 
proposal in the NOPR by adopting a set of standard tariff provisions 
that we will require each seller to include in its market-based rate 
tariff, but we do not adopt the NOPR proposal that all sellers adopt 
the uniform MBR tariff of general applicability set forth in the NOPR. 
After careful consideration of the comments, we also will not adopt the 
NOPR proposal that sellers offer other generic terms and conditions as 
information on a company Web site. We agree with commenters as to the 
benefits to sellers and customers of having all terms and conditions 
relevant to a seller's market-based rate power sales available in one 
document. Thus, we will permit sellers to list in their market-based 
rate tariffs additional terms and conditions that go beyond the 
standard provisions required in Appendix C (with the exception of 
transmission-related services, as discussed above), as modified in this 
Final Rule. As has been our practice in many instances, we will not 
evaluate the justness and reasonableness of such additional provisions, 
but will allow them to be included in the market-based rate tariff that 
is on file with the Commission. Our reasoning is that such additional 
provisions are presumptively just and reasonable. A seller granted 
market-based rate authority has been found not to have, or to have 
adequately mitigated, market power; thus, if a customer is not 
satisfied with the terms and conditions offered by a seller, the 
customer can choose to purchase from a different supplier.
3. Single Corporate Tariff
Comments
    928. ELCON supports the NOPR proposal that each corporate family 
have one tariff on file, stating that it will lead to better 
transparency regarding what each seller in a corporate family owns or 
controls. APPA/TAPS agree, commenting that a single corporate tariff 
addresses recurring problems with determining exactly who is affiliated 
with whom.\1051\ Sempra agrees in

[[Page 40014]]

general that the single tariff structure should eliminate confusion 
that results when entities within the same corporate family have 
tariffs with terms that differ.
---------------------------------------------------------------------------

    \1051\ EEI disagrees, contending that, since companies already 
disclose affiliations in their individual market-based rate filings 
and are separately subject to the Commission's affiliate 
transactions rules, any confusion about affiliations does not 
justify a single tariff requirement. EEI reply comments at 30-31.
---------------------------------------------------------------------------

    929. However, a number of commenters raise potential implementation 
issues and believe that having all entities in a corporate family 
selling under the same tariff should be optional and not 
mandatory.\1052\ Several of these commenters state that the Commission 
has not demonstrated the need for a single corporate tariff and believe 
that the added burden of implementation would outweigh any 
benefits.\1053\
---------------------------------------------------------------------------

    \1052\ See, e.g., EPSA at 41; Duke at 45-48; MidAmerican at 33-
35; FirstEnergy at 27-31; Constellation at 27-29; Progress Energy at 
19-23; EEI at 49. Cogentrix also expresses reservations about 
requiring a single corporate tariff. See Cogentrix/Goldman at 6-8.
    \1053\ See, e.g., Mirant at 6-10; FirstEnergy at 27-31.
---------------------------------------------------------------------------

    930. Some of the problems with the single corporate tariff proposal 
identified by commenters include the following:
     The proposal does not make sense for diversified energy 
companies with a variety of non-utility generator or power marketer 
affiliates because it would require increased regulatory and legal 
coordination among affiliates;
     The burden of replacing multiple market-based rate tariffs 
with one umbrella tariff would be significant, requiring amendment and 
re-execution of many documents with many trading counterparties, as 
well as extensive changes to the existing quarterly reporting process;
     A single tariff listing all affiliates could create 
confusion regarding which affiliates may be bound by certain executed 
service agreements, or which terms and conditions apply to certain 
affiliates;
     Confusion would result when trying to create a single 
tariff per corporate family when sellers can have multiple corporate 
families; listing the same seller on the MBR tariffs of multiple 
corporate groups would not improve transparency; and
     Given that some sellers' upstream ownership can include 
multiple investors, passive investors, and limited partners, the 
proposal could impose a filing requirement on entities that have only a 
passive role and may not otherwise be engaged in the energy business.
    931. Several commenters assert that, while they support the 
objective of simplifying tariff administration, the Commission has not 
considered the administrative and commercial ramifications of mandating 
one tariff per family. For instance, Duke cites the possibility that 
any seller under the corporate tariff could be sued for an affiliate's 
alleged breach, and the complications of Company A selling Subsidiary X 
to Company B and the status of X's sales under Company A's tariff. 
Mirant questions how the sale of a subsidiary's MBR tariff to a non-
affiliate would be handled, given that the tariffs are assets that can 
be bought and sold. In a related comment, Ameren asks for which company 
or companies would the tariff be a jurisdictional facility for purposes 
of FPA section 203. EPSA and Sempra request clarification regarding how 
an enforcement action would be affected by the presence of other 
members of a corporate family on the same tariff, and Ameren seeks 
clarification on the effect of a revocation of market-based rate 
authority of only some companies in a corporate family. MidAmerican 
suggests that, since different affiliates within a corporate family may 
have authority to offer different services, a service schedule to the 
tariff should specify the products that each affiliate is authorized to 
offer and any restrictions or limitations on a seller's market-based 
rate authorization. Morgan Stanley notes that, in many cases, the 
``parent'' is not a jurisdictional entity or is a holding company, and 
recommends requiring each corporate family to designate a lead company 
that will submit its filing and those of its affiliates, rather than 
specifically appointing the ``parent corporation'' as the filing 
entity. Duke urges the Commission to consider what legal means would be 
required to ensure that the tariff is legally a separate and severable 
tariff for each member of a family.
    932. Further, commenters state that there are transitional issues 
that the Commission should consider, such as whether existing tariffs 
will be superseded or cancelled and all existing service agreements 
migrated to the joint tariff; which corporate entity would be required 
to file and maintain the MBR tariff; and the extent to which affiliates 
may have to file separate quarterly reports due to the fact that the 
responsible employees are not shared (e.g., regulated versus 
unregulated merchant employees).
    933. In reply comments, EPSA reiterates its opposition to a 
mandatory single corporate tariff, urging the Commission to abandon the 
proposal because it ``poses major practical obstacles for corporate 
parents that own vastly differing affiliates.'' \1054\ EPSA contends 
that the Commission's premise for adopting the proposal, i.e., entities 
within a corporate family can have conflicting tariff provisions, is 
mooted by the adoption of a standardized tariff. In addition, EPSA 
echoes implementation concerns raised by other parties, in particular: 
(1) The situation where a seller is a member of two corporate families; 
and (2) increased regulatory burden from frequent tariff amendments 
each time ownership changes and corporate affiliations are terminated 
or created.
---------------------------------------------------------------------------

    \1054\ EPSA reply comments at 3-4.
---------------------------------------------------------------------------

    934. Indianapolis P&L argues that affiliates should be permitted to 
maintain separate market-based rate tariffs for many of the reasons 
already cited. In addition, it contends that consolidation will 
increase the burden on many entities by requiring increased regulatory 
and legal coordination between affiliates. Whereas many utilities 
presently separate their utility and non-utility operations in part to 
comply with Commission regulations, Indianapolis P&L asserts that 
mandating a single tariff per corporate family would necessarily 
require utility and non-utility affiliates to operate in closer 
coordination. FirstEnergy agrees, stating that ``[t]he Commission 
should not expect franchised public utilities with captive customers to 
market power totally independently of their affiliates where they are 
all required to sell power to wholesale purchasers under the same 
tariff.'' \1055\
---------------------------------------------------------------------------

    \1055\ FirstEnergy at 30.
---------------------------------------------------------------------------

    935. Finally, some commenters state that the Commission's concerns 
can be satisfied through means other than a single tariff per corporate 
family. Duke recommends allowing affiliated utilities to operate with 
separate but uniform tariffs while posting on their corporate Web sites 
a centralized list of each of the affiliates' market-based rate 
tariffs. Similarly, Progress Energy suggests requiring sellers to use 
the standardized tariff but having them include a section identifying 
all affiliates with market-based rate authority and any restrictions on 
that authority.
Commission Determination
    936. We will modify the NOPR proposal and allow sellers to elect 
whether to transact under a single market-based rate tariff for an 
entire corporate family or under separate tariffs. The benefits that 
the Commission hoped to realize by requiring all corporate families to 
consolidate their operations under one tariff will be achievable by 
other means, namely, by

[[Page 40015]]

having each individual seller revise its existing market-based rate 
tariff to include the standard tariff provisions we require in this 
Final Rule and by maintaining up-to-date information on sellers' 
affiliates through the submission of asset appendices.\1056\
---------------------------------------------------------------------------

    \1056\ The asset appendix is discussed above in Implementation 
Process.
---------------------------------------------------------------------------

    937. For the benefit of those sellers that choose a single 
corporate tariff, we clarify that each seller should continue to report 
its own transactions using the docket number under which it initially 
received market-based rate authority.

G. Legal Authority

1. Whether Market-Based Rates Can Satisfy the Just and Reasonable 
Standard Under the FPA
Comments
    938. A number of commenters challenge the Commission's authority to 
adopt a market-based rate regime.\1057\ State AGs and Advocates contend 
that the courts have never actually reviewed the Commission's market-
based rate program and found that it satisfies the FPA. They contend 
that the Commission in the NOPR cited dictum in Louisiana Energy and 
Power Authority v. FERC,\1058\ noting that the petitioner in that case 
did not challenge the Commission's general policy of permitting market-
based rates in the absence of market power. They further argue that the 
D.C. Circuit in Elizabethtown Gas Company v. FERC,\1059\ relied on 
dictum in a prior gas case to the effect that, where markets are 
competitive, it is ``rational'' to assume that a seller will make 
``only a normal return on its investment.'' State AGs and Advocates 
then criticize the D.C. Circuit's opinion, arguing that ``this sort of 
judicial economic theorizing does not constitute either the substantial 
evidence required to support orders of this Commission under the [FPA], 
or the `empirical proof' required by the courts when an agency attempts 
to substitute competition for statutorily required regulation.'' \1060\
---------------------------------------------------------------------------

    \1057\ E.g., State AGs and Advocates at 3-13, 18-28, 38-40; 
NASUCA at 33-37.
    \1058\ 141 F.3d 364, 365 (D.C. Cir. 1998) (LEPA).
    \1059\ 10 F.3d 866, 870 (D.C. Cir. 1993) (Elizabethtown Gas).
    \1060\ State AGs and Advocates at 8-9.
---------------------------------------------------------------------------

    939. NASUCA similarly questions the Commission's reliance on 
Elizabethtown Gas as the legal foundation for its market-based rate 
regime. NASUCA suggests that the Supreme Court's decision in MCI v. 
AT&T,\1061\ casts considerable doubt on the vitality of Elizabethtown 
Gas and cases that follow its apparent endorsement of market-based 
rates that did not consider the statutory filing issues found crucial 
in MCI. NASUCA also notes that, in another case the Commission relied 
on, Mobil Oil Exploration v. United Distribution Co.,\1062\ the Supreme 
Court cited to FPC v. Texaco, where it held that just and reasonable 
rates cannot be determined solely by reference to market prices.\1063\
---------------------------------------------------------------------------

    \1061\ 512 U.S. 218 (1994) (MCI).
    \1062\ 498 U.S. 211 (1991).
    \1063\ 417 U.S. 380, 397 (1974).
---------------------------------------------------------------------------

    940. Some commenters argue that a finding that competitive markets 
exist is a prerequisite to relying upon market-based rate authority to 
satisfy the mandates of the FPA.\1064\ Industrial Customers contend 
that the Commission may rely on market-based rate authority to produce 
just and reasonable rates if it finds that a competitive market exists 
and the seller lacks or has adequately mitigated market power. They 
submit that the duty to determine that a competitive market exists is 
separate and independent of the determination that a seller lacks, or 
has adequately mitigated, market power.
---------------------------------------------------------------------------

    \1064\ Industrial Customers at 3-12; NRECA at 6-10; State AGs 
and Advocates reply comments at 17-22.
---------------------------------------------------------------------------

    State AGs and Advocates contend that the market-based rate program 
offers no way to monitor whether existing competition results in just 
and reasonable rates, nor a way to check rates if it does not.\1065\
---------------------------------------------------------------------------

    \1065\ State AGs and Advocates reply comments at 18-19, citing 
Farmers Union (finding reliance on existing competition, with no 
monitoring or mitigation, unacceptable).
---------------------------------------------------------------------------

    941. In reply, PNM/Tucson argues that the Commission need not 
entertain attacks on the existence of competitive power markets and the 
legality of market-based rates under the FPA, as they constitute 
collateral attacks on recent Commission decisions and the Lockyer 
opinion, and because a theoretical debate on the subject is beyond the 
scope of this rulemaking proceeding. PNM/Tucson asserts that those 
cases found that market-based rates are permissible by law and urges 
the Commission to reject any attacks on market-based rates 
generally.\1066\
---------------------------------------------------------------------------

    \1066\ PNM/Tucson reply comments at 3-4 (citing Lockyer and the 
underlying Commission orders, State of California, ex rel. Bill 
Lockyer v. British Columbia Power Exchange Corp., 99 FERC ] 61,247, 
order on reh'g, 100 FERC ] 61,295 (2002)).
---------------------------------------------------------------------------

    942. Financial Companies respond to State AGs and Advocates' 
assertion that the Commission should suspend or revoke all market-based 
rates and return to cost-of-service ratemaking by commenting that the 
complaining parties mischaracterize the state of the wholesale market. 
Financial Companies enumerate the ``myriad of approval, reporting and 
other obligations'' \1067\ that constitute the Commission's oversight 
and point out that ISOs and RTOs provide another layer of market 
monitoring and mitigation. They state that it is preferable to shape 
market power remedies addressing specific circumstances than to revoke 
market-based rate tariffs for all sellers.
---------------------------------------------------------------------------

    \1067\ Financial Companies reply comments at 10.
---------------------------------------------------------------------------

Commission Determination
    943. The Commission rejects arguments that it has no authority to 
adopt market-based rates or that the market-based rate program it is 
adopting in this rule does not comply with the FPA. The Supreme Court 
has held that ``[f]ar from binding the Commission, the FPA's just and 
reasonable requirement accords it broad ratemaking authority.* * * The 
Court has repeatedly held that the just and reasonable standard does 
not compel the Commission to use any single pricing formula in general. 
* * *'' \1068\ It is settled law that market-based rates can satisfy 
the just and reasonable standard of the FPA, as most recently 
reaffirmed by the Ninth Circuit in Lockyer and Snohomish,\1069\ and the 
court in Lockyer expressly denied a ``facial challenge to the market-
based [rate] tariffs,'' as discussed below.
---------------------------------------------------------------------------

    \1068\ See Mobil Oil Exploration v. United Distribution Co., 498 
U.S. 211, 224 (1991) (Mobil Oil Exploration), citing FPC v. Hope 
Natural Gas Co., 320 U.S. 591, 602 (1944); FPC v. Natural Gas 
Pipeline Co., 315 U.S. 575, 586 (1942); Permian Basin Area Rate 
Cases, 390 U.S. 747, 776-77 (1968) (Permian); Texaco; Mobil Oil 
Corp. v. FPC, 417 U.S. 283, 308 (1974).
    \1069\ Public Utility District No. 1 of Snohomish County, 
Washington v. FERC, 471 F.3d 1053 (9th Cir. 2006) (Snohomish).
---------------------------------------------------------------------------

    944. In the Lockyer court's analysis of the Commission's market-
based rate authority, the Ninth Circuit cited the Supreme Court's 
determination in Mobil Oil Exploration. It also noted that the use of 
market-based rate tariffs was first approved (by the courts) as to 
sellers of natural gas in Elizabethtown Gas, then as to wholesale 
sellers of electricity in LEPA.
    945. Commenters have also argued that the proposed rule 
impermissibly relies solely on the market to determine just and 
reasonable rates, as was the case in Texaco. We reject these arguments 
as well.
    946. In Texaco, the Supreme Court found that the Natural Gas Act 
(NGA) permits the indirect regulation of small-producer rates.\1070\ 
The Supreme Court

[[Page 40016]]

explained that ``[t]he Act directs that all producer rates be just and 
reasonable but it does not specify the means by which that regulatory 
prescription is to be attained. That every rate of every natural gas 
company must be just and reasonable does not require that the cost of 
each company be ascertained and its rates fixed with respect to its own 
costs.'' \1071\ The Supreme Court noted that it had sustained rate 
regulation based on setting area rates that were based on composite 
cost considerations, citing its decision in FPC v. Hope Natural Gas Co. 
\1072\ The Supreme Court further explained, with respect to the prior 
area rate cases, ``we recognized that encouraging the exploration for 
and development of new sources of natural gas was one of the aims of 
the Act and one of the functions of the Commission. The performance of 
this role obviously involved the rate structure and implied a broad 
discretion for the Commission.'' \1073\ Quoting Permian Basin, the 
Supreme Court added that ``[i]t follows that ratemaking agencies are 
not bound to the service of any single regulatory formula; they are 
permitted, unless their statutory authority otherwise plainly 
indicates, `to make the pragmatic adjustments which may be called for 
by particular circumstances.' '' \1074\
---------------------------------------------------------------------------

    \1070\ Cases under the NGA and the FPA are typically read in 
pari materia. See, e.g., FPC v. Sierra Pacific Power Company, 350 
U.S. 348, 353 (1956); Arkansas-Louisiana Gas Company v. Hall, 453 
U.S. 571, 578 n.7 (1981).
    \1071\ 417 U.S. at 387.
    \1072\ 320 U.S. at 602 (``Under the statutory standard of `just 
and reasonable' it is the result reached not the method employed 
which is controlling.'').
    \1073\ Id. at 388.
    \1074\ Id. at 389, citing Permian, 390 U.S. at 776-777.
---------------------------------------------------------------------------

    947. The Texaco Court further stated that ``the prevailing price in 
the marketplace cannot be the final measure of `just and reasonable' 
rates mandated by the Act.'' \1075\ But, ``[t]his does not mean that 
the market price of gas would never, in an individual case, coincide 
with just and reasonable rates or not be a relevant consideration in 
the setting of area rates.'' \1076\
---------------------------------------------------------------------------

    \1075\ Id.
    \1076\ Id.
---------------------------------------------------------------------------

    948. In Elizabethtown Gas, a decision relying on Texaco, the D.C. 
Circuit addressed a Commission order approving a restructuring 
settlement under which Transcontinental Gas Pipeline Corporation 
(Transco) would no longer sell gas bundled with transportation, but 
would sell gas at the wellhead or pipeline receipt point, to be 
transported as the buyer sees fit. The sales would be market-based 
(negotiated) and the rates for transportation on Transco's system would 
be cost-of-service based. In approving the settlement, the Commission 
had ``determined that Transco's markets are sufficiently competitive to 
preclude the pipeline from exercising significant market power in its 
merchant function and to assure that gas prices are `just and 
reasonable' within the meaning of the NGA section 4.'' \1077\ The 
Commission also ``authorized Transco in advance `to establish and to 
change' individually negotiated rates free of customer challenge under 
section 4 of the NGA; the `only further regulatory action' possible 
under the settlement is the Commission's review of Transco's prices 
under section 5 of the Act, upon the Commission's own motion or upon 
the complaint of a customer that is not a party to the settlement.'' 
\1078\
---------------------------------------------------------------------------

    \1077\ 10 F.3d at 869.
    \1078\ Id.
---------------------------------------------------------------------------

    949. In Elizabethtown Gas, the D.C. Circuit upheld the Commission's 
approval of market-based pricing, holding that ``nothing in FPC v. 
Texaco precludes the FERC from relying upon market-based pricing.'' 
\1079\ The D.C. Circuit explained that in Texaco, the Commission had 
failed to even mention the ``just and reasonable'' standard and 
appeared to apply only the ``standard of the marketplace'' in reviewing 
the reasonableness of the rate (which the Supreme Court had found to be 
unacceptable). Thus, the D.C. Circuit explained with approval, ``the 
FERC has made it clear that it will exercise its section 5 authority 
(upon its own motion or upon that of a complainant) to assure that a 
market (i.e., negotiated) rate is just and reasonable.'' \1080\
---------------------------------------------------------------------------

    \1079\ Id. at 870.
    \1080\ Id.
---------------------------------------------------------------------------

    950. The D.C. Circuit noted that the Commission had specifically 
found that Transco's markets are sufficiently competitive to preclude 
it from exercising significant market power. It further noted that the 
Commission had explained that Transco would be providing comparable 
transportation for all gas supplies and that ``adequate divertible gas 
supplies exist'' to assure that Transco would have to sell at 
competitive prices. Thus, the D.C. Circuit concluded that Transco would 
not be able to raise its price above the competitive level without 
losing substantial business. ``Such market discipline provides strong 
reason to believe that Transco will be able to charge only a price that 
is `just and reasonable' within the meaning of section 4 of the NGA.'' 
\1081\
---------------------------------------------------------------------------

    \1081\ Id. at 871.
---------------------------------------------------------------------------

    951. Likewise in LEPA, the D.C. Circuit affirmed the Commission's 
approval of an application by Central Louisiana Electric Company 
(CLECO) to sell electric energy at market-based rates. The D.C. Circuit 
found reasonable the Commission's conclusion that there are no market 
power considerations that should bar CLECO's application to sell at 
market-based rates. It also found reasonable the Commission's 
conclusion that even if CLECO had participated in oligopolistic 
behavior in the past, the Commission's new open access transmission 
rules had transformed the competitive environment. The D.C. Circuit 
noted that ``competitors outside the current, alleged oligopoly will 
now be able to transmit power into CLECO's territory on 
nondiscriminatory terms.'' \1082\ Thus, according to the D.C. Circuit, 
the Commission reasonably predicted that it was ``unlikely that `energy 
suppliers will decline to participate in the emerging competitive 
markets.' '' \1083\ Finally, the D.C. Circuit viewed favorably the 
Commission's provision of a safeguard in the event that its predictions 
are wrong:
---------------------------------------------------------------------------

    \1082\ 141 F.3d at 370.
    \1083\ Id. (quoting Commission order).

    FERC notes that should the Commission's sanguine predictions 
about market conduct turn out to be incorrect, LEPA can file a new 
complaint for any abuses of market power that do occur. While this 
escape hatch might be insufficient if LEPA had shown a substantial 
likelihood that FERC's predictions would prove incorrect, it 
provides an appropriate safeguard against the uncertainties of 
FERC's prognostications where there has been no such 
showing.\[1084]\
---------------------------------------------------------------------------

    \1084\ Id. at 370-71 (footnotes and citations omitted).

    952. In the market-based rate program adopted in this rule and 
through other Commission actions, unlike the situation in Texaco, the 
Commission is not relying solely on the market, without adequate 
regulatory oversight, to set rates. Rather, it has adopted filing 
requirements (EQRs and change in status filings for all market-based 
rate sellers, regularly scheduled updated market power analyses for all 
Category 2 market-based rate sellers, \1085\), new

[[Page 40017]]

market manipulation rules, and a significantly enhanced market 
oversight and enforcement division to help oversee potential market 
manipulation. In addition, for sellers in RTO/ISO organized markets, 
Commission-approved tariffs contain specific market rules designed to 
prevent or mitigate exercises of market power.
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    \1085\ In this Final Rule, the Commission creates two categories 
of sellers. Category 1 sellers (wholesale power marketers and 
wholesale power producers that own or control 500 MW or less of 
generation in aggregate per region; that do not own, operate or 
control transmission facilities other than limited equipment 
necessary to connect individual generation facilities to the 
transmission grid (or have been granted waiver of the requirements 
of Order No. 888); that are not affiliated with anyone that owns, 
operates or controls transmission facilities in the same region as 
the seller's generation assets; that are not affiliated with a 
franchised public utility in the same region as the seller's 
generation assets; and that do not raise other vertical market power 
issues) would not be required to file a regularly scheduled updated 
market power analysis, but would be subject to the change in status 
requirement. Category 2 sellers consist of all sellers that do not 
qualify as Category 1 sellers.
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    953. In Lockyer, the Ninth Circuit cited with approval the 
Commission's dual requirement of an ex ante finding of the absence of 
market power and sufficient post-approval reporting requirements and 
found that the Commission did not rely on market forces alone in 
approving market-based rate tariffs. The Ninth Circuit held that this 
dual requirement was ``the crucial difference'' between the 
Commission's regulatory scheme and the FCC's regulatory scheme, 
remanded in MCI, which had relied on market forces alone in approving 
market-based rate tariffs.\1086\ The Ninth Circuit thus held that 
``California's facial challenge to market-based tariffs fails'' and 
``agree[d] with FERC that both the Congressionally enacted statutory 
scheme, and the pertinent case law, indicate that market-based tariffs 
do not per se violate the FPA.'' \1087\ The Ninth Circuit determined 
that initial grant of market-based rate authority, together with 
ongoing oversight and timely reconsideration of market-based rate 
authorization under section 206 of the FPA, enables the Commission to 
meet its statutory duty to ensure that all rates are just and 
reasonable.\1088\ While the court in Lockyer found that the 
Commission's market-based rate reporting requirements were not followed 
in that particular case, it did not find those reporting requirements 
invalid and, in fact, upheld the Commission's market program as 
complying with the FPA. The market-based rate requirements and 
oversight adopted in this rule are more rigorous than those reviewed by 
the Lockyer court.
---------------------------------------------------------------------------

    \1086\ Id. at 1013.
    \1087\ Id. at 1013 & n.5; id. at 1014 (``The structure of the 
tariff complied with the FPA, so long as it was coupled with 
enforceable post-approval reporting that would enable FERC to 
determine whether the rates were `just and reasonable' and whether 
market forces were truly determining the price.'').
    \1088\ See Snohomish, 471 F.3d at 1080 (in which the Ninth 
Circuit discusses its decision in Lockyer). In Snohomish, the Ninth 
Circuit explained, ``As in Lockyer, we do not dispute that FERC may 
adopt a regulatory regime that differs from the historical cost-
based regime of the energy market, or that market-based rate 
authorization may be a tenable choice if sufficient safeguards are 
taken to provide for sufficient oversight.'' Id. at 1086.
---------------------------------------------------------------------------

    954. Accordingly, the Commission rejects the position of commenters 
arguing that the Commission lacks authority to continue to permit 
market-based rates for wholesale sales of electricity. The courts have 
sustained the Commission's finding that market-based rates are one 
method of setting just and reasonable rates under the FPA. As 
supplemented by this Final Rule, the Commission finds that the market-
based rate program complies with the statutory and judicial standards 
for acceptable market-based rates. We will retain our policy of 
granting market-based rate authority to sellers without market power 
under the terms and conditions set forth in this Final Rule and the 
Commission's regulations.
    955. Further, we will retain our approach to determining whether a 
seller should receive authorization to charge market-based rates, as 
modified by the Final Rule, by analyzing seller-specific market power. 
The Commission has a long-established approach when a seller applies 
for market-based rate authority of focusing on whether the seller lacks 
market power.\1089\ This approach, combined with our filing 
requirements (EQRs, change of status filings, and regularly scheduled 
updated market power analyses for Category 2 sellers) and ongoing 
monitoring through our enforcement office and complaints filed pursuant 
to FPA section 206, allows us to ensure that market-based rates remain 
just and reasonable. Moreover, for sellers in RTO/ISO organized 
markets, the Commission has in place market rules to help mitigate the 
exercise of market power, price caps where appropriate, and RTO/ISO 
market monitors to help oversee market behavior and conditions. As 
explained in our earlier discussion, we believe that the market-based 
rate program fully complies with judicial precedent.
---------------------------------------------------------------------------

    \1089\ See, e.g., Heartland Energy Services, Inc., 68 FERC ] 
61,223, at 62,060-61 (1994); Louisville Gas and Electric Co., 62 
FERC ] 61,016, at 61,143 n.16 (1993) (and the cases cited therein); 
Citizens Power & Light Corp., 48 FERC ] 61,210, at 61,776 & n.11 
(1989); Pacific Gas and Electric Co. (Turlock), 42 FERC ] 61,406, at 
62,194-98, order on reh'g, 43 FERC ] 61,403 (1988); Pacific Gas and 
Electric Co. (Modesto), 44 FERC ] 61,010, at 61,048-49, order on 
reh'g, 45 FERC ] 61,061 (1988). See also, e.g., LEPA, 141 F.3d at 
365; Consumers Energy Co., 367 F.3d 915 at 922-23 (D.C. Cir. 2004) 
(upholding Commission orders granting market-based rate authority, 
noting that the Commission's longstanding approach is to assess 
whether applicants for market-based rate authority do not have, or 
have adequately mitigated, market power).
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Consistency of Market-Based Rate Program With FPA Filing Requirements
Comments
    956. State AGs and Advocates contend that the Commission's market-
based rate program fails to comply with the FPA in several ways: (1) It 
ignores the FPA mandate that all rates and contracts, as well as all 
changes in rates and contracts, must be filed in advance and made open 
to the public for prior review, and instead allows a seller to simply 
report rates after-the-fact or, in some cases, not at all; (2) it 
eliminates the statutory mandate that all rate increases must be 
noticed by filing 60 days in advance so that they can be reviewed and, 
if warranted, suspended for up to five months, set for hearing with the 
burden of proof on the seller, and made subject to refund pending the 
outcome of the hearing; (3) it provides no objective or independent 
standard for determining whether ``competitive'' market-based rates are 
in fact ``just and reasonable;''\1090\ (4) it provides no standard for 
determining whether market rates are unduly preferential or 
discriminatory; and (5) it provides no way for consumers in most cases 
to know what the ``just and reasonable'' rate will be in advance.\1091\ 
They also contend that the legal presumptions that follow from the 
Commission's market power screens would unduly shift the burden of 
demonstrating the existence of market power to intervenors and away 
from the Commission. They argue that, until an appropriate methodology 
for predicting and checking market power is in place, the Commission 
must suspend its market-based rate regime and return to cost-of-service 
rates for all wholesale sales of electric power.
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    \1090\ State AGs and Advocates express doubt that the rate of 
return for power sold from a highly depreciated coal plant in an 
auction process at a market price equal to the marginal cost of a 
new, gas-fired plant could be within a zone of reasonableness. State 
AGs and Advocates at 25-26.
    \1091\ Id. at 19-20.
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    957. NASUCA objects that the proposed rules would prohibit 
utilities from filing new wholesale energy contracts,\1092\ an apparent 
reference to the Commission's policy, since the issuance of Order No. 
2001,\1093\ that long-term affiliate sales contracts under a seller's 
market-based rate tariff are not to be filed.\1094\ According to 
NASUCA, by not requiring sellers to file long-term market-based rate 
sales contracts, the Commission effectively precludes the

[[Page 40018]]

public and others from objecting before the rates take effect. 
Additionally, NASUCA states that there is no statutory basis for a 
Commission rule directing sellers not to file their rates when the 
statute says exactly the opposite.\1095\ AARP similarly comments that 
the Commission's policy of monitoring long-term market-based sales 
through quarterly reports is too little oversight too late to ensure 
that such rates are just and reasonable. AARP argues that the 
Commission should reconsider its policy on affiliate transactions and 
asserts that all affiliate contracts should be filed and reviewed under 
section 205 to comply with the express requirements under the 
FPA.\1096\
---------------------------------------------------------------------------

    \1092\ NASUCA at 32-33.
    \1093\ Revised Public Utility Filing Requirements, Order No. 
2001, 67 FR 31043 (May 8, 2002), FERC Stats. & Regs., Regs. 
Preambles 2001-2005 ] 31,127 (2002). See 18 CFR 35.10b.
    \1094\ NASUCA at 27-29.
    \1095\ Id. at 28.
    \1096\ AARP at 12.
---------------------------------------------------------------------------

    958. NASUCA also argues that the proposed rule allows sellers with 
cost-based rates to declare their own rates without filing them, 
subject to Commission review when the sales are for less than one year. 
It contends that the burden of proof, under Farmers Union Central 
Exchange, Inc. v. FERC \1097\ and Texaco,\1098\ is on the Commission to 
demonstrate empirical proof that consumers are provided the ``complete, 
effective and permanent bond of protection from excessive rates'' that 
the statute anticipates.\1099\
---------------------------------------------------------------------------

    \1097\ 734 F.2d 1486 (D.C. Cir. 1984), cert. denied sub nom. 
Williams Pipe Line Company v. Farmers Union Central Exchange, Inc., 
469 U.S. 1034 (1984) (Farmers Union).
    \1098\ 417 U.S. 380 (1974).
    \1099\ NASUCA cites Atlantic Ref. Co. v. Pub. Serv. Comm'n of 
State of N.Y., 360 U.S. 378, 388 (1959).
---------------------------------------------------------------------------

Commission Determination
    959. We reject State AGs and Advocates' arguments that the 
Commission's market-based rate program fails to comply with the FPA. 
Contrary to State AGs and Advocates' contention that the Commission's 
market-based rate program ``ignores the FPA mandate that all rates and 
contracts, as well as all changes in rates and contracts, must be filed 
in advance and made open to the public for prior review'' and instead 
``allows sellers to simply `report' rates after-the-fact, or in some 
cases, not at all,''\1100\ as the courts have found, the Commission's 
market-based rate program does not violate the FPA's filing 
requirements. The FPA requires that every public utility file with the 
Commission ``schedules showing all rates and charges for any 
transmission or sale subject to the jurisdiction of the 
Commission,''\1101\ but it explicitly leaves the timing and form of 
those filings to the Commission's discretion. Public utilities must 
file ``schedules showing all rates and charges'' under ``such rules and 
regulations as the Commission may prescribe,'' and ``within such time 
and in such form as the Commission may designate.''\1102\
---------------------------------------------------------------------------

    \1100\ State AGs and Advocates at 19.
    \1101\ 16 U.S.C. 824d(c).
    \1102\ Id.
---------------------------------------------------------------------------

    960. We note that the courts have recognized the Commission's 
discretion in establishing its procedures to carry out its statutory 
functions. For example, the Ninth Circuit, in denying a California 
Commission request to order the Commission to adopt different market-
based rate tariff reporting requirements, observed:

    Congress specified that filings be made ``within such time and 
with such form'' and under ``such rules and regulations as the 
Commission may prescribe.'' 16 U.S.C. Sec.  824d(c). Thus, so long 
as FERC has approved a tariff within the scope of its FPA authority, 
it has broad discretion to establish effective reporting 
requirements for administration of the tariff.[\1103\]
---------------------------------------------------------------------------

    \1103\ Lockyer, 383 F.3d at 1013. See also Wabash Valley Power 
Association v. FERC, 268 F.3d 1105, 1115 (citing with approval the 
Commission's authority to fix just and reasonable rates under 
section 206 as a condition of its market-based rate authorization); 
Environmental Action v. FERC, 996 F.2d 401, 407-08 (D.C. Cir. 1993) 
(in which the D.C. Circuit recognized ``the Commission's 
determination to streamline its regulatory process to keep pace with 
advances in information technology. Ratemaking is a time-consuming 
process.'').
---------------------------------------------------------------------------

    961. The market-based rate tariff, with its appurtenant conditions 
and requirement for filing transaction-specific data in EQRs, is the 
filed rate. As the Commission has held, if every service agreement 
under a previously-granted market-based rate authorization had to be 
filed for prior approval, then the original market-based rate 
authorization would be a pointless exercise.\1104\
---------------------------------------------------------------------------

    \1104\ GWF Energy LLC, 98 FERC ] 61,330, at 62,390 (2002).
---------------------------------------------------------------------------

    962. We also disagree with State AGs and Advocates' argument that 
the market-based rate program eliminates the statutory mandate that all 
rate increases be noticed by filing 60 days in advance and, if 
warranted, suspended for up to five months, set for hearing with the 
burden of proof on the seller, and made subject to refund pending the 
outcome of the hearing. The Commission has developed a thorough process 
to evaluate the sellers that it authorizes to enter into transactions 
at market-based rates. Under the market-based rate program, the rate 
change is initiated when a seller applies for authorization of market-
based rate pricing. All applications are publicly noticed, entitling 
parties to challenge a seller's claims. At that time, there is an 
opportunity for a hearing, with the burden of proof on the seller to 
show that it lacks, or has adequately mitigated, market power, and for 
the imposition of a refund obligation. In addition, if a seller is 
granted market-based rate authority, it must comply with post-approval 
reporting requirements, including the quarterly filing of transaction-
specific data in EQRs,\1105\ change of status filings for all sellers, 
and regularly-scheduled updated market power analyses for Category 2 
sellers.
---------------------------------------------------------------------------

    \1105\ The Ninth Circuit found the pre-EQR quarterly reporting 
requirements to be ``integral to the [market-based rate] tariff'' 
and that they, together with the Commission's initial approval of 
market-based rate authority, comply with the FPA's requirements. 
Lockyer, 383 F.3d at 1016. As discussed elsewhere in this Final 
Rule, through the EQRs, the Commission has enhanced and updated the 
post-transaction quarterly reporting filing requirements that were 
in place during the period at issue in Lockyer.
---------------------------------------------------------------------------

    963. In addition, we disagree with State AGs and Advocates' 
arguments that the Commission failed to show how competitive market-
based rates are just and reasonable and not unduly discriminatory or 
preferential. The standard for judging undue discrimination or 
preference remains what it has always been: Disparate rates or service 
for similarly situated customers.\1106\ As the Commission has held in 
prior cases, and as the courts have upheld, rates that are established 
in a competitive market can be just, reasonable and not unduly 
discriminatory.\1107\ Rates do not have to be set by reference to an 
accounting cost of service to be just, reasonable and not unduly 
discriminatory. When the Commission determines that a seller lacks 
market power, it is therefore making a determination that the resulting 
rates will be established through competition, not the exercise of 
market power. Furthermore, the Commission's market-based rate program 
includes many ongoing regulatory protections designed to ensure that 
rates are just and reasonable and not unduly discriminatory or 
preferential. The filing and reporting requirements incorporated into 
the market-based rate program (EQRs, change in status filings, 
regularly-scheduled updated market power analyses) help the Commission 
to prevent, to discover and to remedy exercises of market power and 
unduly discriminatory rates. In addition, the adoption of pro forma 
transmission tariff provisions that apply industry-

[[Page 40019]]

wide ensures that potential customers are treated similarly in 
obtaining transmission access to energy providers. Moreover, 
Commission-approved RTOs and ISOs run real-time energy markets under 
Commission-approved tariffs.\1108\ These single price auction markets 
set clearing prices on economic dispatch principles, to which various 
safeguards have been added to protect against anomalous bidding.
---------------------------------------------------------------------------

    \1106\ See, e.g., Southwestern Electric Cooperative, Inc. v. 
FERC, 347 F.3d 975, 981 (D.C. Cir. 2003).
    \1107\ See, e.g., Lockyer, 383 F.3d at 1012-13; Tejas Power 
Corp. v. FERC, 980 F.2d 998, 1004 (D.C. Cir. 1990).
    \1108\ In response to State AGs and Advocates' argument about 
the rate of return for a seller receiving a market clearing price 
for power sold in an auction process, the issue does not concern 
whether a particular seller should have market-based rate authority, 
and it is more appropriately addressed in the context of an RTO/ISO 
proceeding rather than in this rulemaking proceeding.
---------------------------------------------------------------------------

    964. Thus, the Commission, through its ongoing oversight of market-
based rate authorizations and market conditions, may take steps to 
address seller market power or modify rates should those steps be 
necessary. For example, based on its review of updated market power 
updates, its review of EQR filings made by market-based rate sellers, 
and its review of required notices of change in status, the Commission 
may institute a section 206 proceeding to revoke a seller's market-
based rate authorization if it determines that the seller may have 
gained market power since its original market-based rate authorization. 
The Commission may also, based on its review of EQR filings or daily 
market price information, investigate a specific utility or anomalous 
market circumstances to determine whether there has been any conduct in 
violation of RTO/ISO market rules or Commission orders or tariffs, or 
any prohibited market manipulation, and take steps to remedy any 
violations. These steps could include, among other things, disgorgement 
of profits and refunds to customers if a seller is found to have 
violated Commission orders, tariffs or rules, or a civil penalty paid 
to the United States Treasury if a seller is found to have engaged in 
prohibited market manipulation or to have violated Commission orders, 
tariffs or rules.
    965. In the NOPR that preceded Order No. 2001, the Commission noted 
that it needed to make changes to keep abreast of developments in the 
industry, e.g., it had approved umbrella tariffs for market-based rates 
by public utilities and there had been a significant increase in the 
number of section 205 filings after the Commission's open access 
initiatives in Order Nos. 888 and 889.\1109\ The Commission explained:

    \1109\ Open Access Same-Time Information System and Standards of 
Conduct, Order No. 889, 61 FR 21737 (1996), FERC Stats. & Regs., 
Regs. Preambles ] 31,037 (1996), order on reh'g, Order No. 889-A, 62 
FR 12484 (1997), FERC Stats. & Regs., Regs. Preambles ] 31,049 
(1997), reh'g denied, Order No. 889-B, 81 FERC ] 61,253 (1997), 
aff'd in part and rev'd in part sub nom Transmission Access Policy 
Study Group v. FERC, 225 F.3d 667 (D.C. Cir. 2000), aff'd sub nom. 
New York v. FERC, 535 U.S. 1 (2002).
---------------------------------------------------------------------------

    Under the Commission's current filing requirements in 18 C.F.R. 
Part 35, individual service agreement filings associated with 
approved tariffs require a significant amount of time, effort, and 
expense on the part of public utilities to prepare and serve on 
their customers and the Commission. These individual filings also 
require a significant amount of staff time and effort associated 
with docketing, noticing, loading the information onto RIMS, and 
other processing tasks. Further, the information contained in such 
filings that is most relevant to customers and the Commission could 
also be provided in an alternative, streamlined form, thus 
continuing to satisfy the requirements of FPA section 205(c), but in 
a more efficient manner. Accordingly, we propose to replace the 
filing of individual service agreements and Quarterly Transaction 
Reports with the filing of an electronic Index of Customers. This 
format will greatly increase the accessibility and usefulness of the 
relevant data, which will confer greater benefits to the 
public.\1110\
---------------------------------------------------------------------------

    \1110\ Revised Public Utility Filing Requirements, Notice of 
Proposed Rulemaking, FERC Stats. & Regs., Proposed Regulations 1999-
2003, ] 32,554 at 34,062 (2001).

    966. The Commission implemented the revised filing requirements in 
---------------------------------------------------------------------------
Order No. 2001. In so doing, it further explained that:

    The revised filing public utility requirements adopted in this 
Final Rule create a level playing field vis-[agrave]-vis the filing 
requirements applicable to traditional utilities and power 
marketers. While the data to be reported in the data sets reduces 
public utilities' overall reporting burden as compared to existing 
requirements, it is hoped that the Electric Quarterly Reports' more 
accessible format will make the information more useful to the 
public and the Commission will better fulfill the public utilities' 
responsibility under FPA section 205(c) to have rates on file in a 
convenient form and place. The data should provide greater price 
transparency, promote competition, enhance confidence in the 
fairness of markets, and provide a better means to detect and 
discourage discriminatory practices.\1111\

    \1111\ Order No. 2001, FERC Stats. & Regs., Regs. Preambles 
2001-2005 ] 31,127 at P 31.
---------------------------------------------------------------------------

    967. Thus, we find that the multiple layers of filing and reporting 
requirements incorporated into the market-based rate program meet the 
filing requirements of the FPA and, in conjunction with our enhanced 
market oversight and enforcement functions within the Commission, as 
well as the ability of the public to file section 206 complaints, 
provide adequate protection from excessive rates. Given our broad 
discretion to determine the procedures to carry out our statutory 
duties, our market-based rate program fully complies with the 
requirements of the FPA.\1112\
---------------------------------------------------------------------------

    \1112\ Moreover, the decision to eliminate the filing of market-
based rate contracts was made almost five years ago in a generic 
rulemaking proceeding that was open to participation by all 
interested parties. Commenters' failure to raise this concern in 
that proceeding precludes them from attacking the Commission's well-
settled practice here.
---------------------------------------------------------------------------

    968. Although State AGs and Advocates also argue that the legal 
presumptions that follow from the Commission's market power screens 
would unduly shift the burden of demonstrating the existence of market 
power to intervenors, the Commission previously addressed and rejected 
this argument. On rehearing of the April 14 Order, the Commission 
explained that nothing in that order shifts the burden of proof that 
section 205 imposes on the filing utility. Passing both screens or 
failing one merely establishes a rebuttable presumption. To challenge a 
seller who passes both screens, the intervenor need not conclusively 
prove that the seller possesses market power. Rather, the intervenor 
need only meet a burden of going forward with evidence that rebuts the 
results of the screens. At that point, the burden of going forward 
would revert back to the seller to prove that it lacks market 
power.\1113\ Ultimately, the burden of proof under section 205 belongs 
to the seller.
---------------------------------------------------------------------------

    \1113\ July 8 Order, 108 FERC ] 61,026 at P 29.
---------------------------------------------------------------------------

    969. With respect to NASUCA's and AARP's concern about long-term 
affiliate sales contracts not being filed, we note that since 2002, the 
Commission's regulations have provided that long-term market-based rate 
power sales service agreements, with affiliates or otherwise, are not 
to be filed with the Commission.\1114\ Although commenters acknowledge 
that the Commission first considers in a separate proceeding whether to 
authorize affiliate transactions, they believe that the Commission 
should nevertheless review the resulting rates in a proceeding under 
FPA section 205 before they go into effect.
---------------------------------------------------------------------------

    \1114\ See 18 CFR 35.1(g) (``[A]ny market-based rate agreement 
pursuant to a tariff shall not be filed with the Commission'').
---------------------------------------------------------------------------

    970. NASUCA and AARP have not convinced us that this practice needs 
to be modified as a legal or policy matter. Our market-based rate 
program incorporates numerous protections against excessive rates, 
regardless of the identities of the parties to a transaction, and 
commenters do not provide any compelling reason why affiliate 
transactions should be treated any differently. To the extent that a

[[Page 40020]]

particular affiliate relationship presents issues of concern, they will 
be considered in the context of our determination whether to authorize 
any affiliate sales. Accordingly, we will continue to direct sellers 
not to file long-term market-based rate sales contracts, unless 
otherwise permitted by Commission rule or order.
    971. Regarding NASUCA's assertion that our proposals would allow 
sellers with cost-based rates to declare their own rates without filing 
them, we emphasize that all mitigation proposals, whether based on the 
default cost-based rates or some other cost-based rates, must be filed 
with the Commission for review. As we make clear above in the 
Mitigation section of this Final Rule, any such filings are noticed, 
and interested parties are given an opportunity to intervene, comment 
on, or protest the submittal.
 2. Whether Existing Tariffs Must Be Found To Be Unjust and 
Unreasonable, and Whether the Commission Must Establish a Refund 
Effective Date
Comments
    972. NASUCA states that the Commission invokes sections 205 and 206 
of the FPA as authority for the proposed action, including modifying 
all existing market-based rate authorizations and tariffs so they will 
be expressly conditioned on or revised to reflect certain new 
requirements. NASUCA submits that any action taken under section 206 
must be prefaced by a Commission finding that existing rates are unjust 
and unreasonable and the fixing of a refund effective date. It argues 
that the Commission has failed to make express findings necessary to 
support its proposal to modify all existing market-based rate tariffs 
under section 206 or to explain how it can modify the existing tariffs 
without finding that they are not just and reasonable and establishing 
a refund effective date.\1115\
---------------------------------------------------------------------------

    \1115\ NASUCA at 32.
---------------------------------------------------------------------------

Commission Determination
    973. As discussed above in the MBR Tariff section, in requiring all 
sellers to revise their existing market-based rate tariffs to include 
certain standard provisions, the Final Rule finds that continuing to 
allow basic inconsistencies in the market-based rate tariffs on file 
with the Commission is unjust and unreasonable. Thus, NASUCA's concern 
in that regard is addressed.
    974. We disagree with NASUCA that we must establish a refund 
effective date because we are establishing rules under section 206. 
Even if section 206 were read to require the establishment of a refund 
effective date in rulemakings initiated under section 206, rather than 
only in case-specific section 206 investigations initiated by 
complaints or sua sponte by the Commission,\1116\ we have broad 
discretion to adopt generic policy or make generic findings through 
either a rulemaking or adjudication, and we have discretion whether to 
order refunds.\1117\ This proceeding is not an adjudicatory 
investigation of public utilities' existing market-based rate tariffs 
for which refunds will be required. Rather, we are modifying existing 
market-based rate tariffs prospectively only through this 
rulemaking.\1118\ Accordingly, the establishment of a refund effective 
date in this rulemaking would be meaningless.
---------------------------------------------------------------------------

    \1116\ The Congressional intent of the Regulatory Fairness Act 
of 1988 (RFA), which added the refund effective date provision to 
section 206, was to expedite the resolution of complaint 
proceedings. Congress believed that, pre-RFA, public utilities had 
little incentive to settle meritorious section 206 complaints since 
any relief was prospective only, and the public utilities kept any 
revenues collected during the pendency of a section 206 proceeding. 
The purpose of the legislation was to ``correct this problem by 
giving FERC the authority to order refunds, subject to certain 
limitations.'' S. Rep. No. 491, 100th Cong., 2d Sess. 3 (1988), 
reprinted in 1988 U.S.C.C.A.N. 2684, 2685. In so doing, Congress 
left it to the Commission's discretion to determine when the public 
interest would be served by requiring refunds under section 206, 
stating ``Because the potential range of these situations cannot be 
fully anticipated, no attempt has been made to enumerate them 
here.'' S. Rep. No. 491, 100th Cong., 2d Sess. 6, reprinted in 1988 
U.S.C.C.A.N. 2688. Nowhere in the Senate Report does Congress 
mention setting refund effective dates in rulemakings.
    \1117\ See, e.g., Lockyer, 383 F.3d at 1016.
    \1118\ E.g., Wisconsin Gas Co. v. FERC, 770 F.2d 1144, 1166 
(D.C. Cir. 1985); SEC v. Chenery, 332 U.S. 194, 202-03, reh'g 
denied, 332 U.S. 747 (1947).
---------------------------------------------------------------------------

 H. Miscellaneous

1. Waivers
Commission Proposal
    975. The Commission has granted certain entities with market-based 
rate authority, such as power marketers and independent or affiliated 
power producers, waiver of the Commission's Uniform System of Accounts 
(USofA) requirements, specifically waiver of Parts 41, 101, and 141 of 
the Commission's regulations.\1119\ The Commission has also granted 
blanket approval under Part 34 of the Commission's regulations for 
future issuances of securities and assumptions of liability where the 
entity seeking market-based rate authority, such as a power marketer or 
power producer, is not a franchised public utility.
---------------------------------------------------------------------------

    \1119\ Part 41 pertains to adjustments of accounts and reports; 
Part 101 contains the Uniform System of Accounts for public 
utilities and licensees; Part 141 describes required forms and 
reports.
---------------------------------------------------------------------------

    976. In the NOPR, the Commission noted that, as the development of 
competitive wholesale power markets continues, independent and 
affiliated power marketers and power producers are playing more 
significant roles in the electric power industry. In light of the 
evolving nature of the electric power industry, the Commission sought 
comment on the extent to which these entities with market-based rate 
authority should be required to follow the USofA; what financial 
information, if any, should be reported by these entities; how 
frequently it should be reported; and whether the Part 34 blanket 
authorizations continue to be appropriate.
    977. The Commission noted that some sellers have had their market-
based rate authority revoked, or have elected to relinquish their 
market-based rate authority after a presumption of market power, and 
have begun or resumed selling power at cost-based rates. As discussed 
in the April 14 Order, any waivers previously granted in connection 
with those sellers' market-based rate authority are no longer 
applicable. Thus, the Commission currently rescinds any accounting and 
reporting \1120\ waivers for mitigated sellers in the mitigated control 
area. Similarly, the Commission stated in the April 14 Order that it 
would rescind any blanket authorizations under Part 34 for the 
mitigated seller and its affiliates. In the NOPR, the Commission 
proposed that, in the case of any affiliates, this would entail 
rescission of blanket authorizations in all geographic areas, not just 
the mitigated control area.
---------------------------------------------------------------------------

    \1120\ See 18 CFR 41.10-41.12, 141.1, 141.2 and 141.400.
---------------------------------------------------------------------------

    978. The Commission proposed in the NOPR that any repeal of 
previously granted waivers become effective 60 days from the date of an 
order repealing such waivers in order to provide the affected utility 
with time to make the necessary filings with the Commission and to 
allow for an orderly transition from selling under market-based rates 
to cost-based rates. The Commission sought comment on that proposal. 
The Commission also sought input regarding any difficulties sellers may 
have when transitioning to cost-based rates and whether a prior waiver 
of the accounting regulations would leave them without adequate data to 
come into conformance with the accounting rules.

[[Page 40021]]

a. Accounting Waivers
Comments
    979. The majority of commenters who comment on this topic urge the 
Commission to retain existing waivers of the accounting 
regulations.\1121\ They submit that the Commission's accounting 
requirements are only relevant when the utility or marketer that is 
being regulated charges cost-based rates. EPSA states that where a 
market-based rate seller neither has cost-of-service rates nor captive 
customers from which to recover cost-of-service rates, requiring such 
entities to comply with the USofA would be burdensomely expensive and 
would serve no purpose. The commenters explain that there has been no 
change in the industry that warrants a departure from the Commission's 
precedent. Commenters state that a change in policy would serve no 
public benefit, and the costs that such market-based rate sellers would 
have to incur in order to collect and report such data would 
substantially outweigh the benefit of collecting and reporting it.
---------------------------------------------------------------------------

    \1121\ See, e.g., Ameren at 23-24; EPSA at 33-36; Constellation 
at 23-27; EEI at 49-52; Morgan Stanley at 9-10; Ormet at 15-17; PPM 
at 6-7.
---------------------------------------------------------------------------

    980. Financial Companies state that there is no reason for the 
Commission to run the risk of discouraging participation in the energy 
markets and chilling investment by requiring power marketers and power 
producers who currently lack market power to comply with the USofA 
absent concrete evidence that the wholesale power markets are being 
harmed by the Commission's current practice of granting waivers or 
blanket authority.\1122\
---------------------------------------------------------------------------

    \1122\ Financial Companies at 18.
---------------------------------------------------------------------------

    981. Absent special circumstances, Sempra supports the current 
waivers and explains that the electric quarterly transaction reports 
submitted pursuant to Order No. 2001 \1123\ provide detailed 
information regarding transactions entered into by entities authorized 
to make market-based rate sales. Sempra also notes that the retention 
of these waivers for market-based rate entities is also consistent with 
the treatment of power marketers and exempt wholesale generators (EWGs) 
under the Public Utility Holding Company Act of 2005 and the 
Commission's regulations promulgated thereunder.\1124\
---------------------------------------------------------------------------

    \1123\ Revised Public Utility Filing Requirements, Order No. 
2001, 67 FR 31043 (May 8, 2002), FERC Stats. & Regs. ] 31,127 
(2002); reh'g denied, Order 2001-A, 100 FERC ] 61,074 (2002); 
reconsideration and clarification denied, Order No. 2001-B, 100 FERC 
] 61,342 (2002); further order, Order No. 2001-C, 101 FERC ] 61,314 
(2002).
    \1124\ Sempra at 8-9, citing Public Utility Holding Company Act 
of 2005, Pub. L. No. 109-58 1261 et seq., 119 Stat. 594 (2005) 
(PUHCA 2005).
---------------------------------------------------------------------------

    982. APPA/TAPS suggest that the Commission provide waivers to 
Category 1 sellers, but not for Category 2 sellers.\1125\ In response 
to the Commission's question about the orderly transition from market-
based to cost-based rates and the role that waivers may play in making 
that transition more difficult, APPA/TAPS suggest that Category 2 
sellers are more likely than Category 1 sellers to lose market-based 
rate authority and find themselves subject to cost-based rates; 
accordingly, not providing the waivers for Category 2 sellers should 
address these transition concerns.
---------------------------------------------------------------------------

    \1125\ However, any such waivers should not exempt a holding 
company or service company from applicable reporting requirements 
under the Commission's PUHCA 2005 regulations. APPA/TAPS at 29-30.
---------------------------------------------------------------------------

Commission Determination
    983. We will continue the Commission's historical practice of 
granting waiver of Parts 41, 101, and 141 of the Commission's 
regulations to certain entities with market-based rate authority. We 
agree with EPSA that little purpose would be served to require 
compliance with accounting regulations for entities that do not sell at 
cost-based rates and do not have captive customers. Such entities 
typically include power marketers and independent and affiliated power 
producers that are not franchised public utilities.\1126\
---------------------------------------------------------------------------

    \1126\ Likewise, we will continue to grant waiver of Subparts B 
and C of Part 35 of the Commission's regulations requiring the 
filing of cost-of-service information, except for 18 CFR 35.12(a), 
35.13(b), 35.15 and 35.16. We note that this waiver would not be 
granted to an entity that makes sales at cost-based rates.
---------------------------------------------------------------------------

    984. We conclude that the costs of complying with the Commission's 
USofA requirements and, specifically Parts 41, 101, and 141 of the 
Commission's regulations, outweigh any incremental benefits of such 
compliance where the seller only transacts at market-based rates.\1127\ 
Further, the risk of discouraging participation in the energy markets 
and the potential chilling effect on investment caused by requiring 
power marketers and power producers, who do not otherwise have a cost-
based rate on file with the Commission, to comply with the USofA 
outweigh the added oversight the Commission might gain in this regard.
---------------------------------------------------------------------------

    \1127\ We have previously stated that Parts 41, 101 and 141 
prescribe certain accounting and reporting requirements that focus 
on the assets that a utility owns, and waiver of these requirements 
is appropriate where the utility ``will not own any such assets, its 
jurisdictional facilities will be only corporate and documentary, 
its costs will be determined by utilities that sell power to it, and 
its earnings will not be defined and regulated in terms of an 
authorized return on invested capital.'' Citizens Power & Light 
Corp., 48 FERC ] 61,210 at 61,780 (1989).
---------------------------------------------------------------------------

    985. As we have done in the past, previously granted waivers of the 
accounting requirements will continue to be rescinded where a seller is 
found to have market power (or where the seller accepts a presumption 
of market power) and the seller proposes cost-based rate mitigation or 
the Commission imposes cost-based rate mitigation. Although the 
Commission stated in the NOPR that it would also revoke the accounting 
waivers for any of the mitigated seller's affiliates with market-based 
rates in the mitigated balancing authority area, we clarify that we 
will not require revocation of the accounting and reporting waivers for 
a power marketer affiliated with a mitigated seller where such power 
marketer has no assets, no cost-based rate on file, and its applicable 
tariff prohibits sales in the mitigated balancing authority area.\1128\
---------------------------------------------------------------------------

    \1128\ See, e.g., APS Energy Services Company, Inc., 117 FERC ] 
61,158 (2006).
---------------------------------------------------------------------------

    986. With regard to APPA/TAPS's suggestion that the Commission 
provide waivers to sellers that qualify for Category 1 and not to 
sellers that qualify for Category 2, we decline to adopt such an 
approach. While APPA/TAPS may be correct that Category 2 sellers are 
more likely than Category 1 sellers to possess market power, we do not 
grant such accounting waivers based on the size of the seller (which 
is, to a great extent, the critical factor in determining in which 
category the seller is placed). Rather, as discussed above, the waivers 
are granted on the basis of whether the seller is a franchised public 
utility or otherwise is selling at cost-based rates.
    987. Finally, we note that all sellers, irrespective of accounting 
or other waivers, must file EQRs regarding their transactions. In 
addition, we agree with APPA/TAPS that any waivers in this rule do not 
exempt a holding company or service company from applicable reporting 
requirements under the Commission's PUHCA 2005 regulations.
b. Timing
Comments
    988. Regarding the proposal that rescission of accounting and 
reporting waivers become effective 60 days from the date of an order 
rescinding such waivers, several commenters state that 60 days may not 
be enough time for sellers who have their market-based rate authority 
revoked, or have elected to relinquish their market-based rate

[[Page 40022]]

authority after a presumption of market power and have begun or resumed 
selling power at cost-based rates, to conform to the Commission's 
accounting requirements.\1129\
---------------------------------------------------------------------------

    \1129\ See Ameren at 24; EEI at 48-49; Mirant at 15-16.
---------------------------------------------------------------------------

    989. EEI supports providing such companies at least six months post 
revocation to comply with USofA recordkeeping requirements.\1130\ EEI 
states that the Commission should allow the companies to begin keeping 
records under the USofA starting at the beginning of the next calendar 
year, or the companies' fiscal year, if different, and to report the 
information the following year.\1131\ argues that to put USofA in place 
and begin complying with the Commission's reporting requirements such 
as the annual FERC Form 1 and quarterly FERC Form No. 3-Q takes 
substantial company time and resources. EEI explains that companies 
must put the necessary accounts and reporting formats in place within 
their accounting systems. This involves substantial training of staff, 
modification of accounting software, testing to ensure proper internal 
controls under the Sarbanes Oxley Act of 2002,\1132\ and review by 
company management and internal and external auditors to ensure 
accuracy under the securities laws and the Sarbanes Oxley Act. EEI 
submits that these measures can be quite costly--in the millions of 
dollars for larger companies--and they take time to implement.
---------------------------------------------------------------------------

    \1130\ Mirant also supports providing six months to comply with 
the reporting requirements and states that, in addition, the 
Commission should grant extensions to that deadline based upon a 
demonstration that the entity is working in good faith to comply 
with the deadline but, due to factors beyond the entity's control, 
the deadline needs to be extended. Mirant at 15-16.
    \1131\ EEI at 48-49.
    \1132\ Sarbanes Oxley Act of 2002, Pub. L. 107-204, 116 Stat. 
745.
---------------------------------------------------------------------------

    990. Constellation supports the 60-day transition period as 
reasonable but seeks clarification that under this approach the entity 
would be required to (1) Maintain its accounts in accordance with the 
Commission's USofA only for periods beginning at the end of such 
transition period, and (2) obtain specific authorization for securities 
to be issued, or liabilities to be assumed, subsequent to the end of 
such transition period.\1133\
---------------------------------------------------------------------------

    \1133\ Constellation at 33. See also PPL at 26-27 (supports 
proposal to keep waivers effective for 60 days from date of order 
revoking market-based rate authority).
---------------------------------------------------------------------------

Commission Determination
    991. We adopt the NOPR proposal that rescission of waivers of Parts 
41, 101 and 141 of the Commission's regulations granted in connection 
with a seller's market-based rate authority will become effective 60 
days from the date of an order revoking such waivers. We believe that 
this strikes a reasonable balance between the need to have adequate 
financial information on file with the Commission and the desire to 
provide sellers adequate time to comply.
    992. In our consideration of the transition period for complying 
with the accounting and reporting requirements, the Commission finds 
that commenters have not sufficiently supported their request for a 
transition period of six months or more. EEI's arguments with respect 
to the time and money required to train staff and modify and test 
accounting software do not outweigh the need for the Commission to 
obtain financial information with regard to mitigated sellers so that 
we can meet our obligation under the FPA to ensure that rates remain 
just and reasonable and not unduly discriminatory or preferential. We 
note that our experience has shown that a 60-day transition period is 
sufficient time for a mitigated seller to comply with the accounting 
requirements.\1134\
---------------------------------------------------------------------------

    \1134\ See Entergy Services, Inc, 115 ] FERC 61,260 (2006) 
(revoking waivers and authorizations previously granted to certain 
Entergy Affiliates). Accounting systems were in place within 60-days 
from the effective date of the order rescinding the waivers and the 
company was granted an additional 30-day extension to file the 
upcoming quarterly report. See Entergy Services, Inc., Docket No. 
AC06-257-000 (Nov. 21, 2006) (unpublished letter order).
---------------------------------------------------------------------------

    993. In response to Constellation's request for clarification, we 
clarify that a seller losing or relinquishing its market-based rate 
authority will be required to maintain its accounts in accordance with 
the Commission's USofA \1135\ and will be subject to quarterly and 
annual reporting requirements (FERC Form Nos. 3-Q, 1, or 1-F) \1136\ as 
of the effective date of the rescission of such waivers, i.e., 60 days 
from the date of the order rescinding the waivers. In this regard, such 
sellers will be required to comply with our accounting regulations 
(Part 101) beginning with the effective date of the rescission of such 
waiver. For quarterly reporting in FERC Form No. 3-Q, the seller will 
be required to submit FERC Form No. 3-Q beginning with the quarter in 
which the rescission of the accounting and reporting waivers becomes 
effective.\1137\ The seller will also be required to submit a FERC Form 
No. 1 or 1-F, as applicable, beginning in the year in which the 
rescission of the accounting and reporting waivers becomes 
effective.\1138\ For example, if the effective date of rescission 
occurs on May 15, the seller must make the 3-Q filing for the second 
quarter (April-June) at its regularly scheduled time even though it has 
not previously filed a Form 1.\1139\ If a particular seller is unable 
to meet the applicable filing dates, it may petition the Commission for 
an extension. We will consider such requests on a case-by-case basis.
---------------------------------------------------------------------------

    \1135\ 18 CFR Part 101.
    \1136\ See 18 CFR 141.1, 141.2, 141.400.
    \1137\ The first quarterly filing made by the seller will 
include information from the effective date of the rescission 
through the end of the calendar quarter.
    \1138\ The first annual filing of FERC Form No. 1 or 1-F will 
include information beginning with the effective date of the 
rescission through the end of the calendar year. Additionally, there 
is a requirement that goes along with these forms that requires the 
submission of a CPA Certification Statement (18 CFR 41.10-41.12).
    \1139\ In this example, the seller's 3-Q for the second quarter 
must reflect our accounting regulations as of May 15, the effective 
date of rescission of such waivers.
---------------------------------------------------------------------------

c. Part 34 Waivers Blanket Authorizations
Comments
    994. In response to the Commission's inquiry regarding whether Part 
34 blanket authorizations (pertaining to issuances of securities or 
assumptions of liabilities) continue to be appropriate, all commenters 
addressing the issue urge the Commission to retain its current 
policy.\1140\ They submit that Commission oversight of securities 
issuances and assumptions of liabilities is only relevant for 
franchised public utilities and that prior authorization under section 
204 is not necessary for market-based rate sellers that do not intend 
to ``become a public service franchised providing electricity to 
consumers dependent upon [their] services.'' \1141\ Financial Companies 
state that there is no reason for the Commission to risk adversely 
affecting energy markets by requiring entities that currently lack 
market power to secure agency approval each time they want to issue 
securities or assume liabilities.
---------------------------------------------------------------------------

    \1140\ See, e.g., Cogentrix at 3-6; PPL at 25-27; TXU at 5-7; 
AWEA at 4-5; Duke supplemental comments at 1-8; Powerex at 26-28.
    \1141\ See Cogentrix at 5, citing Citizens Energy Corp., 35 FERC 
] 61,336 at 61,455 (1986). Cogentrix notes that entities with such 
blanket authorizations do not provide the service that franchised 
utilities are obligated to offer to their captive customers and that 
FPA section 204 and 18 CFR Part 34 are intended to protect.
---------------------------------------------------------------------------

    995. With regard to the statement in the NOPR that the Commission 
will rescind blanket authorizations for the mitigated seller and its 
affiliates in all geographic areas, not just the mitigated control 
area, Duke strongly opposes rescission of blanket section 204 
authorizations for all affiliates of the mitigated seller in all 
markets. Duke

[[Page 40023]]

urges the Commission to limit such rescission only to those market-
based rate sellers making sales to captive customers in areas where 
there is a finding of market power.\1142\ Duke states that the purpose 
of section 204 is to ensure the financial viability of franchised 
public utilities. As a result, prior authorization is appropriate for 
independent and affiliated power marketers with market-based rate 
authority who do not intend to assume public service franchise 
obligations.
---------------------------------------------------------------------------

    \1142\ Duke supplemental comments at 1-8. See also PPL at 26 
(loss of any waiver should apply only to the seller or affiliates 
that make wholesale sales in the control area where market-based 
rate authority is lost, but not to affiliates that do not conduct 
business in that control area).
---------------------------------------------------------------------------

    996. Duke argues that the Commission has not explained how issuance 
of a security or assumption of a liability by an affiliated marketer or 
merchant generator could be contrary to the public interest merely 
because an affiliate is deemed to have market power in power sales 
markets in a particular geographic area. Duke asserts that there is no 
evidence presented in the NOPR that would support the presumed linkage 
between a determination of a seller's market power in a particular 
geographic market and the ability of that seller's affiliates to 
leverage such market power in other geographic markets through their 
issuances of securities or debt. Duke says that this is especially true 
in the case of entities such as the Duke affiliates, which have amended 
their tariffs to preclude market-based rate sales in the Duke Power 
control area, the only geographic market where the company was 
determined to have market power. Given that no market-based rate sales 
will be made by the affiliates in the only geographic area where there 
was even an issue of market power, Duke states that there is no 
possible nexus between securities issuances by these entities and 
protecting the franchised customers of Duke's traditional utility 
affiliates.
    997. Duke concludes that the Commission should determine that 
blanket authorizations under section 204 for market-based rate sellers 
should not be affected by a finding that a utility affiliate can 
exercise market power in its control area or other geographic markets. 
In the alternative, Duke asks the Commission to determine that, in 
cases where sellers cannot sell power at market-based rates in the 
geographic market(s) where an affiliated traditional utility is found 
to have market power, there can be no anti-competitive effects or need 
to protect franchise customers, and thus affiliated sellers should be 
able to obtain (or retain) blanket section 204 authorizations.
Commission Determination
    998. We will continue to grant blanket approval under Part 34 for 
future issuances of securities and assumptions of liability where the 
entity seeking market-based rate authority, such as a power marketer or 
power producer, is not a franchised public utility or does not 
otherwise provide requirements service at cost-based rates.\1143\ The 
Commission traditionally has granted blanket authorization for the 
issuance of securities and assumptions of liability to power sellers 
not subject to cost-based rate regulation, i.e., power sellers that 
have market-based rate authority.\1144\ As the Commission has explained 
in previous cases involving market-based rate authority in which the 
sellers sought blanket authorization of issuances of securities or 
assumptions of liability, the purpose of section 204 of the FPA, which 
Part 34 implements, is to ensure the financial viability of public 
utilities obligated to serve consumers of electricity.\1145\ 
Accordingly, where the seller is not a franchised public utility 
providing electric service to customers under cost-based regulation and 
has market-based rate authority, the Commission's practice is to grant 
the blanket authorization, subject to consideration of objections by an 
interested party.
---------------------------------------------------------------------------

    \1143\ See, e.g., Golden Spread Electric Coop., Inc., 97 FERC ] 
61,025 at 61,070 (2001) (``While Golden Spread has been granted 
market-based rate authority, it also makes requirements sales under 
Commission-accepted, cost-based rates. Since Golden Spread sells 
power at cost-based rates and not solely at market-based rates, it 
fails to qualify for blanket approval to issue securities.'').
    \1144\ Merrill Lynch Commodities, Inc., 108 FERC ] 61,233 at P 
16 (2004).
    \1145\ Id. (citing Citizens Energy Corp., 35 FERC ] 61,198 at p. 
61,455 (1986); Howell Gas Management Co., 40 FERC ] 61,336 at p. 
62,026 (1987)).
---------------------------------------------------------------------------

    999. We do not adopt the NOPR proposal concerning the rescission of 
blanket authorizations for affiliates of mitigated sellers. After 
careful consideration of the comments received, we will limit such 
rescission to the mitigated seller and its affiliates making sales 
within the mitigated balancing authority area. Our decision here takes 
into account Duke's and PPL's arguments against rescission of blanket 
authorization for all affiliates in all markets. We conclude that it is 
not necessary to rescind such blanket authorizations in the case of 
affiliates that make sales outside of the mitigated balancing authority 
area because the seller retains its market-based rate authority in 
unmitigated markets. We clarify that the effective date for rescinding 
blanket authorization under Part 34 will be commensurate with the date 
on which a mitigated seller begins to sell power at cost-based rates. 
Further, sellers losing their market-based rate authority must file 
with the Commission to obtain specific authorization for securities to 
be issued, or liabilities to be assumed, prior to the date the seller 
first sells at cost-based rates.
2. Sellers Affiliated With a Foreign Utility
Commission Proposal
    1000. Under existing policy, a seller affiliated with a foreign 
utility selling in the United States (and each of its affiliates) must 
not have, or must have mitigated, market power in generation and 
transmission and not control other barriers to entry. In addition, the 
Commission considers whether there is evidence of affiliate abuse or 
reciprocal dealing. However, for sellers affiliated with a foreign 
utility, the Commission has allowed a modified approach to the current 
four prongs.
    1001. With regard to generation market power, should any of the 
seller's first-tier markets include a United States market, the seller 
performs the market power screens in that control area(s). With regard 
to transmission market power, the Commission requires the seller 
affiliated with a foreign utility seeking market-based rate authority 
to demonstrate that its transmission-owning affiliate offers non-
discriminatory access to its transmission system that can be used by 
its competitors to reach United States markets. The Commission does not 
consider transmission and generation facilities that are located 
exclusively outside of the United States and that are not directly 
interconnected to the United States. However, the Commission would 
consider transmission facilities that are exclusively outside the 
United States but nevertheless interconnected to an affiliate's 
transmission system that is directly interconnected to the United 
States. A seller affiliated with a foreign utility must inform the 
Commission of any potential barriers to entry that can be exercised by 
either it or its affiliates in the same manner as a seller located 
within the United States. Regarding affiliate abuse, the requirement 
that a power marketer with market-based rate authority file for 
approval under section 205 of the FPA before selling power to a utility 
affiliate does not apply to situations involving sales of power to a

[[Page 40024]]

foreign utility outside of the Commission's jurisdiction.
    1002. The Commission proposed in the NOPR to retain its current 
policy when reviewing the application for market-based rate 
authorization by a seller affiliated with a foreign utility, and sought 
comment regarding whether the current policy is adequate to grant 
market-based rate authorization to such sellers. No comments were 
submitted on the broad question of whether our current policy, in 
general, is adequate. However, Powerex and NL Hydro \1146\ raise 
specific issues that are addressed below. As discussed below, we 
conclude that our current approach needs no modification. Accordingly, 
we will adopt the NOPR proposal to retain our current policy when 
reviewing an application for market-based rate authority by a seller 
affiliated with a foreign utility.
---------------------------------------------------------------------------

    \1146\ NL Hydro is a Crown Corporation owned by the Government 
of Newfoundland and Labrador.
---------------------------------------------------------------------------

Comments
    1003. Powerex notes that comparability for non-jurisdictional 
United States-based transmission providers (``unregulated transmitting 
utilities'' under the FPA) is now defined by statute to mean service 
``at rates that are comparable to those that the unregulated 
transmitting utility charges itself'' and ``on terms and conditions 
that are comparable to those under which the unregulated transmitting 
utility provides transmission services to itself and that are not 
unduly discriminatory or preferential.'' \1147\ Powerex notes that, in 
the OATT Reform NOPR, the Commission proposed to apply the 
comparability requirement of FPA section 211A on a case-by-case basis, 
i.e., by complaint.\1148\ Powerex states that, under principles of 
national treatment as set out in the North American Free Trade 
Agreement (NAFTA), the Commission should impose no more stringent a 
burden on similarly non-jurisdictional Canadian and Mexican 
transmission-owning utilities. For that reason, Powerex urges the 
Commission to clarify that it will presume that Canadian and Mexican 
transmitting utilities are providing comparable and not unduly 
discriminatory or preferential transmission service unless this 
presumption is otherwise rebutted by third party or Commission-
instituted complaint.\1149\
---------------------------------------------------------------------------

    \1147\ 16 U.S.C. 824j-1(b).
    \1148\ OATT NOPR at P 111.
    \1149\ Powerex at 32.
---------------------------------------------------------------------------

    1004. NL Hydro urges the Commission to reject Powerex's suggestion 
that the Commission no longer should require market-based rate sellers 
to affirmatively demonstrate that non-discriminatory access is offered 
on transmission facilities that they or their affiliates own, control, 
or operate outside of the United States. NL Hydro argues that the 
comparability standard of FPA section 211A does not govern the 
Commission's market-based rate analysis of transmission market 
power.\1150\ It states that the Commission has not suggested, in either 
this proceeding or the OATT rulemaking, that the comparability standard 
in FPA section 211A should create a presumption that any market-based 
rate seller (domestic or affiliated with a foreign utility) should be 
presumed to have passed the transmission market power test.\1151\
---------------------------------------------------------------------------

    \1150\ NL Hydro reply comments at 3.
    \1151\ Id. at 5.
---------------------------------------------------------------------------

    1005. NL Hydro supports the Commission's proposal to retain its 
existing requirements with respect to the mitigation of transmission 
market power when reviewing the market-based rate applications of 
sellers affiliated with a foreign utility. According to NL Hydro, these 
requirements establish a reasonable balance among important regulatory 
objectives by: (1) Requiring non-discriminatory access to foreign 
transmission facilities for access to United States markets as a 
condition of market-based rate authority; (2) complying with the 
national treatment requirements of NAFTA; and (3) applying principles 
of comity to the jurisdiction of foreign regulatory authorities with 
direct regulatory jurisdiction over foreign transmission 
entities.\1152\ Accordingly, NL Hydro believes that the Commission 
should codify in its regulations the requirement that a market-based 
rate seller, or its affiliate, that owns, controls, or operates 
transmission facilities outside of the United States must demonstrate 
that non-discriminatory access is offered on those facilities so that 
competitors of the seller may reach United States markets.
---------------------------------------------------------------------------

    \1152\ NL Hydro at 13.
---------------------------------------------------------------------------

Commission Determination
    1006. We will continue to require a seller seeking market-based 
rate authority that is a foreign utility or is affiliated with a 
foreign utility to affirmatively demonstrate that any owned or 
affiliated transmission is offered on a non-discriminatory basis that 
can be used by competitors of the seller or its affiliate to reach 
United States markets. Accordingly, we reject Powerex's suggestion that 
the Commission should presume that foreign transmitting utilities are 
providing comparable and not unduly discriminatory or preferential 
transmission service unless this presumption is rebutted. The 
Commission did not propose to implement section 211A of the FPA in 
Order No. 890 and section 211A is not relevant to the Commission's 
analysis for purposes of granting or denying market-based rate 
authority.\1153\
---------------------------------------------------------------------------

    \1153\ Order No. 890, FERC Stats. & Regs. ] 31,241 at P 192.
---------------------------------------------------------------------------

    1007. We will codify in Sec.  35.37(d) of the Commission's 
regulations the requirement that a market-based rate seller affiliated 
with a foreign utility, or its affiliate, that owns, controls, or 
operates transmission facilities outside of the United States and is 
interconnected with the United States must demonstrate that comparable, 
non-discriminatory access is offered on those facilities so that 
competitors of the seller may reach United States markets.
3. Change in Status
Commission Proposal
    1008. In early 2005, the Commission clarified and standardized 
market-based rate sellers' reporting requirements for any change in 
status that departed from the characteristics the Commission relied on 
in initially authorizing sales at market-based rates. In Order No. 
652,\1154\ the Commission required, as a condition of obtaining and 
retaining market-base rate authority, that sellers file notices of such 
changes no later than 30 days after the change in status occurs. In the 
NOPR, the Commission sought comment on a number of issues that the 
Commission identified in Order No. 652 as issues that could be pursued 
in this proceeding. The Commission solicited comment on whether 
ownership of any new inputs to electric power production, including 
fuel supplies, should be reportable. To the extent that any such 
information is deemed reportable, the Commission proposed to align this 
reporting requirement to reflect the consideration of other barriers to 
entry as part of the vertical market power analysis.
---------------------------------------------------------------------------

    \1154\ Order No. 652 at P 47.
---------------------------------------------------------------------------

    1009. The Commission proposed, consistent with Order No. 652, not 
to require the reporting of transmission outages per se as a change in 
status. However, to the extent a transmission outage affects on a long-
term basis whether the seller satisfies the Commission's concerns 
regarding horizontal or vertical market power, a change of status 
filing would be required. The Commission sought comment on this 
proposal.

[[Page 40025]]

    The Commission declined in Order No. 652 to narrow or delineate the 
definition of control. The Commission concluded that it is not possible 
to predict every contractual agreement that could result in a change of 
control of an asset; however, the Commission indicated that to the 
extent that parties wish to propose specific definitions or 
clarifications to the Commission's historical definition of control, 
they may do so in the course of the instant rulemaking.\1155\
---------------------------------------------------------------------------

    \1155\ Id. at P 47.
---------------------------------------------------------------------------

    1010. As proposed in the NOPR (Sec.  35.43 of the proposed 
regulations), events that constitute a change in status include the 
following: First, ownership or control of generation capacity that 
results in net increases of 100 MW or more, or of transmission 
facilities, or of inputs to electric power production other than fuel 
supplies; or, second, affiliation with any entity not disclosed in an 
application for market-based rate authority that owns, operates, or 
controls generation or transmission facilities or inputs to electric 
power production, or affiliation with any entity that has a franchised 
service area.\1156\ The Commission invited comment generally on whether 
the Commission should expand the triggering events for a change in 
status filing beyond what was adopted in Order No. 652. In Order No. 
652, we concluded that the reporting obligation should extend only to 
changes in circumstances within the knowledge and control of the 
seller.
---------------------------------------------------------------------------

    \1156\ NOPR at P 179-182.
---------------------------------------------------------------------------

a. Fuel Supplies
Comments
    1011. Some commenters in general support the idea that ownership of 
fuel supplies should not be a factor in the vertical market power 
analysis and should not trigger a requirement to file a notice of 
change in status.\1157\ APPA/TAPS support the reporting of the 
acquisition of the means of production or transportation of fuel but 
not the reporting of the acquisition of fuel itself. APPA/TAPS explain 
that acquisition or control over companies that produce or deliver fuel 
and acquisitions of, or affiliations (including through joint ventures) 
with, production or transportation resources (including LNG facilities) 
are inputs into electric power production that can raise significant 
competitive concerns. APPA/TAPS submit that, unlike fuel, the means of 
production or transportation of fuel are not so readily obtainable from 
alternative sources.\1158\ They argue that while entry from new storage 
or transportation facilities/transporters is possible, such entry 
involves sufficient siting difficulties and capital requirements that 
it cannot be assumed to be timely, likely or sufficient to remove 
competitive concerns.
---------------------------------------------------------------------------

    \1157\ APPA/TAPS at 90-91; EEI at 21; Constellation at 23.
    \1158\ APPA/TAPS at 90-91, citing San Diego Gas & Elec. Co., 83 
FERC ] 61,199 (1998) (gas/electric merger).
---------------------------------------------------------------------------

    1012. Constellation suggests that the Commission should clearly 
distinguish between fuel supplies (including the capacity to produce 
and process them) and physical facilities used to transport or 
distribute fuel supplies. Constellation believes that ownership of fuel 
supply does not contribute to market power because of the availability 
of alternative suppliers. Constellation states that, while ownership or 
control of physical facilities to transport or distribute fuel has the 
potential to contribute to market power in some cases, such potential 
generally is blunted by regulation or by the availability of 
substitutes. Constellation asserts that ownership of facilities for the 
production or processing of coal or other fuels should not be 
reportable because alternative sources of supply can substitute for the 
coal or other fuels that can be produced or processed by such 
facilities. Constellation states that in specific instances, if any 
intervenor believes that fuel supplies (or fuel production or 
processing facilities) are not available from alternative suppliers for 
delivery in the relevant geographic region, the party could provide 
appropriate information in an attempt to rebut a market-based rate 
seller's statement that it cannot erect barriers to entry in relevant 
markets.\1159\
---------------------------------------------------------------------------

    \1159\ Constellation at 24-25.
---------------------------------------------------------------------------

    1013. Constellation believes that the purchase of natural gas 
transportation or storage on intrastate or interstate pipelines should 
not trigger any change in status reporting requirement. It states that 
these transactions do not involve ownership or control of physical 
facilities for the transportation or storage of natural gas. Moreover, 
because capacity is available from the natural gas transportation and 
storage providers themselves, and through capacity release programs 
from other customers of such providers, Constellation believes that the 
purchase of such capacity does not contribute to the seller's vertical 
market power.\1160\
---------------------------------------------------------------------------

    \1160\ Id. at 25.
---------------------------------------------------------------------------

Commission Determination
    1014. The Commission will not expand the change in status reporting 
requirement to include the reporting of a change in ownership or 
control of natural gas and oil supplies, or affiliation with an entity 
that owns or controls such fuel supplies. However, we will require the 
reporting of a change in status with regard to the ownership or control 
of, or affiliation with, any entity not disclosed in the application 
for market-based rate authority that owns, or controls ``inputs to 
electric power production,'' where that term is defined as ``intrastate 
natural gas transportation, intrastate natural gas storage or 
distribution facilities; sites for new generation capacity development; 
sources of coal supplies and the transportation of coal supplies such 
as barges and railcars.'' The Commission adopts this approach to align 
the change in status reporting requirement to reflect the other 
barriers to entry part of the vertical market power analysis.
    1015. We will adopt the current change in status requirement with 
the following modifications.\1161\ We will delete the phrase ``other 
than fuel supplies'' from proposed Sec.  35.43(a)(1) (now Sec.  
35.42(a)(1)). We originally proposed that events that constitute a 
change in status include ``[o]wnership or control of generation 
capacity that results in net increases of 100 MW or more, or 
transmission facilities or inputs to electric power production other 
than fuel supplies.'' In light of the definition of ``inputs to 
electric power production'' that we adopt in this Final Rule, there is 
no longer a need in Sec.  35.42(a)(1) for the phrase ``other than fuel 
supplies.'' As noted above in the discussion on vertical market power, 
in this Final Rule we modify the definition of ``inputs to electric 
power production'' to mean ``intrastate natural gas transportation, 
intrastate natural gas storage or distribution facilities; sites for 
new generation capacity development; sources of coal supplies and the 
transportation of coal supplies such as barges and railcars.'' The 
definition of ``inputs to electric power production'' includes 
``sources of coal supplies,'' and therefore, including the phrase 
``other than fuel supplies'' would be inaccurate. However, we note that 
the ownership or control of certain other fuel supplies (i.e., gas and 
oil supplies) will not require a notice of change in status.
---------------------------------------------------------------------------

    \1161\ Another change to 18 CFR 35.42 is described above in the 
implementation section.
---------------------------------------------------------------------------

    1016. Next, we are modifying the change in status provisions to be 
consistent with the horizontal and vertical market power provisions 
which we are adopting. Section 35.42, as adopted herein, differs from 
the NOPR

[[Page 40026]]

proposal in that we will require change in status notifications for 
changes in ownership or control of inputs to electric power production. 
Additionally, change in status notifications will be required for 
changes in operation, in addition to ownership and control, of 
transmission facilities. Similarly, we will require a change in status 
notification for affiliation with any entity not disclosed in the 
application for market-based rate authority that owns or controls 
generation facilities or inputs to electric power production and any 
entity not disclosed in the application for market-based rate authority 
that owns, operates or controls transmission facilities.
    1017. In response to APPA/TAPS, we clarify that the Commission's 
change in status requirements are intended to track the requirements 
embedded in the horizontal and vertical analysis as well as the 
affiliate abuse representations. As clarified in the other barriers to 
entry part of the vertical market power analysis described in this 
Final Rule, the Commission will not require an analysis or affirmative 
statement with regard to ownership or control of, or affiliation with, 
an entity that owns or controls natural gas and oil supplies, the 
interstate transportation of natural gas, or the transportation of oil. 
In contrast, we will require a seller to provide a description of its 
ownership or control of, or affiliation with, an entity that owns or 
controls intrastate natural gas transportation; intrastate natural gas 
storage or distribution facilities; sites for generation capacity 
development; and sources of coal supplies and the transportation of 
coal supplies (defined as ``inputs to electric power production'' in 
the regulations); however, we adopt a rebuttable presumption that 
sellers cannot erect barriers to entry with regard to inputs to 
electric power production. Thus, while a seller is required to describe 
in a change in status filing any ownership of, control of or 
affiliation with entities that own or control inputs to electric power 
production (just as it must do in an initial application for market-
based rate authority and an updated market power analysis), we will 
rebuttably presume that such ownership, control or affiliation does not 
allow a seller to raise entry barriers. We will, however, allow 
intervenors to demonstrate otherwise.
    1018. Further, in response to Constellation, we note that we 
presently do not require the reporting of capacity contracted for, but 
for which control is not transferred, with regard to interstate or 
intrastate natural gas pipeline or storage capacity and we agree that 
there is no compelling reason to begin doing so.
b. Transmission Outages
Comments
    1019. Numerous commenters support the Commission's current policy 
and proposal not to require the reporting of transmission outages per 
se as a change in status.\1162\
    1020. Some commenters support the proposal not to require the 
reporting of all transmission outages per se because they believe that 
requiring sellers to report all transmission outages as changes in 
status would prove an overwhelming administrative burden with no market 
benefits.\1163\ Indianapolis P&L states that this approach balances the 
need for the Commission to have updated information with the need for 
sellers to focus on their business, rather than administrative 
filings.\1164\ EEI supports the current policy that only long-term 
transmission outages that could affect the Commission's analysis of 
vertical and horizontal market power should be reportable.\1165\
---------------------------------------------------------------------------

    \1162\ APPA/TAPS at 87-89; Indianapolis P&L at 15; EEI at 21; 
MidAmerican at 35-36; and Powerex at 34.
    \1163\ MidAmerican at 36; Indianapolis P&L at 15; EEI at 21.
    \1164\ Indianapolis P&L at 15.
    \1165\ EEI at 21.
---------------------------------------------------------------------------

    1021. APPA/TAPS state that at least some transmission outage 
information is (or should be) publicly available on OASIS sites, 
suggesting less of a need to impose a separate reporting requirement 
for such outages.\1166\ However, APPA/TAPS urge that certain outages be 
reported to the Commission's Office of Enforcement on a non-public 
basis and that the Commission reserve its authority to require change 
of status reports for other, significant outages.\1167\ We note, 
however, that APPA/TAPS fail to provide examples of the types of 
outages that they believe should be reportable.
---------------------------------------------------------------------------

    \1166\ APPA/TAPS at 88.
    \1167\ Id. at 87-88.
---------------------------------------------------------------------------

    1022. APPA/TAPS also suggest that the Commission identify for 
specific market-based rate sellers generation and transmission 
facilities that, if there is an extended or repeated outage, could 
produce significant transmission constraints or reductions in the 
amount of available generation in that seller's market(s). They suggest 
that the Commission, in conjunction with an RTO/ISO market monitor 
(where one exists), could identify and designate in that seller's 
market-based rate authorization the key transmission facilities and/or 
generation units that are likely to increase competitive concerns if 
they go out of service. Because of the increased potential for market 
power harm associated with the outage of these facilities, APPA/TAPS 
suggest that the Commission could require a market-based rate seller 
under the terms of its market-based rate authorization to report 
publicly as a change in status outages of these specified 
facilities.\1168\
---------------------------------------------------------------------------

    \1168\ APPA/TAPS at 88-89.
---------------------------------------------------------------------------

    1023. Powerex believes that additional clarification is necessary 
to determine what the Commission means by ``long-term outages'' that 
may affect a seller's market power analysis. Powerex also requests that 
the Commission consider whether transmission outages on a non-
jurisdictional or foreign affiliate's transmission system should be 
considered a change in status that is reportable under Order No. 652, 
given the limits of the Commission's jurisdictional interests.
Commission Determination
    1024. We adopt the NOPR proposal not to require the reporting of 
transmission outages per se as a change in status. We agree that the 
reporting of all transmission outages, including the most routine, 
would be an excessive burden on sellers with no apparent countervailing 
benefit. However, consistent with Order No. 652, we reiterate that to 
the extent a long-term transmission outage affects one or more of the 
factors of the Commission's market-based rate analysis (e.g., if it 
reduces imports of capacity by competitors that, if reflected in the 
generation market power screens, would change the results of the 
screens from a ``pass'' to a ``fail''), a change of status filing is 
required.\1169\
---------------------------------------------------------------------------

    \1169\ In response to Powerex's request for clarification on 
what the Commission means by ``long-term outages'' that may affect a 
seller's market power analysis, we clarify that the Commission uses 
the term ``long-term'' to mean one year or longer.
---------------------------------------------------------------------------

    1025. We reject APPA/TAPS's suggestion that the Commission should 
require the automatic reporting of some transmission outages to the 
Office of Enforcement. APPA/TAPS fails to adequately explain why we 
should assume certain transmission outages are, as a matter of routine, 
an enforcement matter to be investigated for wrongdoing.
    1026. We also reject APPA/TAPS' suggestion that the Commission 
identify certain generation and transmission facilities that could 
produce significant transmission constraints or reductions in the 
amount of generation available in

[[Page 40027]]

that market-based rate seller's market(s). Public identification of 
such generation and transmission facilities could cause CEII and 
security concerns. In addition, outages that could affect a seller's 
market-based rate analysis will change over time. The burden remains on 
the market-based rate seller to identify the outages that should be 
reported as a change in status. We also remind commenters that entities 
may file a complaint or call the Office of Enforcement hotline if they 
are concerned that an outage provides the opportunity for a seller to 
exercise market power. Regarding Powerex's request that the Commission 
consider whether transmission outages on a non-jurisdictional or 
foreign affiliate's transmission system should be considered reportable 
under Order No. 652, given the limits of the Commission's 
jurisdictional interests, we clarify that, consistent with our change 
in status reporting requirement in general, to the extent that a 
transmission outage reflects a change in the characteristics that the 
Commission relied on (e.g., if it reduces imports of capacity by 
competitors that, if reflected in the generation market power screens 
for U.S. markets, would change the results of the screens from a 
``pass'' to a ``fail''), a change of status filing would be required. 
The change in status requirement is an important element of the 
Commission's market power oversight. If a seller affiliated with a 
foreign utility wishes to retain market-based rate authority in the 
United States, such seller must comply with the notice of change in 
status requirements, including the reporting of transmission outages 
that may change the results of the screens from a ``pass'' to a 
``fail.'' The Commission finds no reason to exempt a seller affiliated 
with a foreign utility from this requirement.
c. Control
Comments
    1027. Several commenters note that increased precision in the 
Commission's definition of control would be particularly helpful to 
sellers, especially in light of the increased emphasis on reporting 
accuracy and completeness and the Commission's general practice of 
accepting change in status filings in letter orders, without providing 
much detailed analysis or explanation as to whether the filings were 
required in the first place.\1170\ These commenters seek clarification 
that energy contracts that are not associated with a specific resource 
(do not specify a ``source'') do not transfer control. EEI and SoCal 
Edison argue that such contracts or liquidated damages call option 
contracts do not transfer control because, at their core, they are 
financial transactions used to mitigate the buyer's price risk.\1171\ 
According to commenters, the option holder does not actually control 
any particular capacity that might be used to meet the contract needs. 
The energy could come from the seller, from the market through the 
seller, or directly from the market to the buyer if the seller opts to 
pay liquidated damages. They submit that if such a contract were deemed 
to transfer ``control,'' execution of such routine contracts would 
trigger a change in status filing for each incremental 100 MW purchased 
thereby, which is most likely not what the Commission intended.
---------------------------------------------------------------------------

    \1170\ EEI at 21-22; SoCal Edison at 10-14; Williams at 1; and 
Powerex at 33.
    \1171\ EEI offers an example of a firm energy call option that, 
in response to a day-ahead call by the buyer, gives the seller the 
option of delivering energy from its own facilities or buying energy 
from the competitive market, with the obligation to pay liquidated 
damages equal to the difference in price between the pre-agreed 
price and the cost to the buyer of buying replacement power from 
another source for failure to deliver. EEI argues such contract 
should not be deemed to transfer ``control'' and therefore should 
not be reportable.
---------------------------------------------------------------------------

    1028. APPA/TAPS support a reporting obligation for all of the types 
of contractual arrangements that could confer control, as consistent 
with the discussion in the horizontal market power section of the NOPR. 
They argue that these arrangements could provide a market-based seller 
with the means to determine whether capacity is offered into a market 
and whether a competitor can or will enter a market. They state that 
these arrangements also create opportunities for sellers to coordinate 
their behavior with other competitors. If the contracts do not raise 
competitive concerns, the seller could explain the factors supporting 
that conclusion in its report.\1172\
---------------------------------------------------------------------------

    \1172\ APPA/TAPS at 89.
---------------------------------------------------------------------------

    1029. SoCal Edison urges the Commission to consider whether, and to 
clarify how, the emerging, non-traditional capacity and electrical 
energy products that are routinely transacted in hybrid electricity 
markets today would fit within its construction of its test for control 
(`` * * * affecting ability of the capacity to reach the relevant 
market''). It warns that buyers may be hesitant to routinely purchase 
products that require continual change in status filings.\1173\
---------------------------------------------------------------------------

    \1173\ SoCal Edison at 14-16.
---------------------------------------------------------------------------

Commission Determination
    1030. Pursuant to the change in status reporting requirement, a 
market-based rate seller is required to report a change in control to 
the extent the seller acquires a net 100 MW or more generation capacity 
through contract. Our determination of what constitutes control is 
discussed above in the horizontal market power analysis section and we 
adopt that discussion for purposes of the change in status requirement. 
That is, the Commission concludes that the determination of control is 
appropriately based on a review of the totality of circumstances on a 
fact specific basis. No single factor or factors necessarily results in 
control. If a seller has control over certain capacity such that the 
seller can affect the ability of the capacity to reach the relevant 
market, then that capacity should be attributed to the seller for 
purposes of complying with the change in status requirement.
    1031. Further, as the Commission has previously clarified, sellers 
making a change in status filing to report an energy management 
agreement are required to make an affirmative statement in their filing 
as to whether the agreement at issue transfers control of any assets 
and whether the agreement results in any material effect on the 
conditions that the Commission relied upon for the grant of market-
based rate authority. On some occasions, and at the Commission's 
discretion, the Commission may request the seller to submit a copy of 
the agreement and provide supporting documentation.\1174\
---------------------------------------------------------------------------

    \1174\ Calpine Energy Services, L.P., 113 FERC ] 61,158 at P 13 
(2005) (Calpine).
---------------------------------------------------------------------------

    1032. We reiterate here that a seller making a change in status 
filing is required to state whether it has made a filing pursuant to 
section 203 of the FPA.\1175\ To the extent the seller has made a 
section 203 filing that it submits is being made out of an abundance of 
caution without conceding that the Commission has section 203 
jurisdiction, the seller will be required to incorporate this same 
assumption in its market-based rate change in status filing (e.g., if 
the seller assumes that it will control a jurisdictional facility in a 
section 203 filing, it should make that same assumption in its market-
based rate change in status filing and, on that basis, inform the 
Commission as to whether there is any material effect on its market-
based rate authority).\1176\
---------------------------------------------------------------------------

    \1175\ 16 U.S.C. 824b.
    \1176\ Calpine, 113 FERC ]61,158 at P 14.
---------------------------------------------------------------------------

d. Triggering Events
Comments
    1033. In the NOPR, the Commission invited comments on whether it 
should expand the triggering events for a change in status filing 
beyond

[[Page 40028]]

ownership or control of facilities or inputs and affiliation with 
entities that own or control facilities or inputs or that have a 
franchised service territory, as set forth in Order No. 652. No 
commenters suggest additional triggering events, and several commenters 
oppose any general expansion of categories.\1177\ Several commenters 
specifically oppose any requirement to report actions taken by 
competitors or natural events as a change in status. They argue that, 
in many cases, the seller may be unaware of actions taken by a 
competitor, making compliance virtually impossible.\1178\
---------------------------------------------------------------------------

    \1177\ MidAmerican at 36; Powerex at 34.
    \1178\ MidAmerican at 36-37; Powerex at 34.
---------------------------------------------------------------------------

Commission Determination
    1034. We will not expand the events that trigger a change in status 
filing. Further, we will not expand triggering events to include 
actions taken by a competitor (such as a decision to retire a 
generation unit or take transmission capacity out of service) or 
natural events (such as hydro-year level, higher wind generation, or 
load disruptions due to adverse weather conditions) beyond those 
adopted in Order No. 652. As we describe above in the vertical market 
power analysis discussion, with regard to barriers to entry erected or 
controlled by other than the seller, we find that it is not reasonable 
to routinely require sellers to make a showing regarding potential 
barriers to entry that others might erect and that are beyond the 
seller's control. However, we will entertain on a case-by-case basis 
claims that the existence of barriers to entry beyond the seller's 
control may affect the seller's ability to exercise market power. For 
similar reasons we will not expand the events that trigger a change in 
status filing to include actions taken by a competitor or natural 
events. However, we will entertain on a case-by-case basis claims that 
such actions may affect the seller's ability to exercise market power.
e. Timing of Reporting
Comments
    1035. At present, the Commission requires the reporting of changes 
in status to be ``filed no later than 30 days after the legal or 
effective date of the change in status, including a change in ownership 
or control, whichever is earlier.'' \1179\ The proposed regulatory text 
maintains this requirement.
---------------------------------------------------------------------------

    \1179\ Order No. 652 at P 106. The Commission clarified that for 
power sales contracts, ``it is irrelevant for the purposes of 
compliance with the reporting obligation if the effective date on 
which control is transferred occurs prior to the date on which the 
purchaser is contractually bound to commence physical delivery.'' 
Order No. 652-A at P 31.
---------------------------------------------------------------------------

    1036. CAISO supports the current requirement that entities with 
market-based rate authority must report changes of status no later than 
30 days after the change has occurred. CAISO proposes that any change 
in status be reported not only to the Commission but also to the 
relevant market monitor where the facilities are located. CAISO states 
that this minimal additional burden on the supplier will ensure that 
RTO and ISO staff are operating with the latest possible 
information.\1180\
---------------------------------------------------------------------------

    \1180\ CAISO at 15.
---------------------------------------------------------------------------

    1037. SoCal Edison recommends that the Commission revise the change 
in status reporting requirement to focus upon the actual acquisition of 
the resources in question--for power sales contracts, the date of 
physical power delivery. SoCal Edison states that the Commission's 
current policies make it virtually impossible for a seller to provide a 
meaningful evaluation of whether or not a forward contract with 
delivery months or years in the future creates a departure from the 
characteristics the Commission relied upon in granting market-based 
rate authority as much as three years previously. SoCal Edison notes 
that, as currently written, the policy requires reporting of 
procurement activities potentially years in advance of any power 
delivery because the effective date of the contract--usually the 
execution date--may significantly precede the date of physical 
delivery--that is, the actual transfer of control over generation 
resources.\1181\
---------------------------------------------------------------------------

    \1181\ SoCal Edison at 17-19.
---------------------------------------------------------------------------

Commission Determination
    1038. We provide clarification regarding when a change in status 
filing should be filed. In Order No. 652, we determined that reports of 
changes in status must be filed no later than 30 days after the legal 
or effective date of the change in status, including a change in 
ownership or control, whichever is earlier.\1182\ However, it was not 
the Commission's intention, as SoCal Edison notes, to require reporting 
of procurement activities potentially years in advance of any power 
delivery. We agree with SoCal Edison that the current policy may be 
unclear and may cause an entity to file a notice of change in status 
years in advance of the actual transaction, i.e., change in ownership 
or transfer of control. The Commission requires a meaningful evaluation 
of whether a change creates a departure from the characteristics the 
Commission relied upon in granting market-based rate authority. It 
would be difficult for the Commission to accurately evaluate whether or 
not, for example, a forward contract with delivery months or years in 
the future will affect the conditions the Commission relied upon for 
the market-based rate authorization. Accordingly, we will modify Sec.  
35.42(b) (formerly Sec.  35.43(b)) to provide that, in the case of 
power sales contracts with future delivery, such contracts are 
reportable 30 days after the physical delivery has begun.
---------------------------------------------------------------------------

    \1182\ Order No. 652 at 106.
---------------------------------------------------------------------------

    1039. We reject CAISO's proposal that any change in status also be 
reported to the relevant market monitor where the facilities are 
located. We find that informing the Commission of changes in status is 
sufficient. Change in status filings are noticed and therefore 
interested entities will have notice of any such filing.
f. Sellers Affiliated With a Foreign Utility
    1040. The change in status requirement is applicable to all market-
based rate sellers regardless whether they are domestic or affiliated 
with a foreign utility.
Comments
    1041. Powerex notes that the Commission stated in the NOPR that it 
``does not consider transmission and generation facilities that are 
located exclusively out of the United States and that are not directly 
interconnected to the United States [but] would consider transmission 
facilities that are exclusively outside the United States but 
nevertheless interconnected to an affiliate's transmission system that 
is directly interconnected to the United States.'' \1183\ Powerex 
submits that the NOPR fails to clarify the Commission's proposed 
treatment of foreign-sited generation facilities interconnected to an 
affiliated transmission system that, in turn, is directly 
interconnected to the United States transmission grid. Powerex argues 
that, based on the nature of the Commission's concerns with respect to 
facilities outside the United States, the details concerning such 
generation capacity should not be relevant to the Commission's 
determination in circumstances where the affiliated uncommitted 
capacity exceeds the transmission limits of the intertie(s) directly 
interconnecting the affiliated foreign transmission system to the 
United States grid. Powerex states that foreign sellers with foreign 
generating facilities can make that generation available to United 
States

[[Page 40029]]

markets only to the extent that transmission capacity is available on 
the interties crossing the international boundaries. In such instances, 
Powerex argues that the seller's participation in United States 
jurisdictional markets is constrained by the total transfer capability 
(TTC) of the transmission system of the intertie (a measurement of the 
level of imports that can access a market from a particular location). 
Powerex asserts that those intertie limits represent the foreign 
seller's maximum uncommitted foreign capacity available to United 
States markets.\1184\ Thus, according to Powerex, only changes in the 
TTC of the intertie itself should be considered a change in the 
circumstances upon which the original market-based rate authorization 
was based, for purposes of Order No. 652 filings.\1185\
---------------------------------------------------------------------------

    \1183\ NOPR at P 175.
    \1184\ Powerex at 29-30.
    \1185\ Id. at 30.
---------------------------------------------------------------------------

    1042. Powerex also argues that complying with the change in status 
requirements of Order No. 652 would require foreign sellers to demand 
routine updates of potentially non-public information from their 
foreign generation-owning affiliates; it contends that Order No. 652 
imposes a continuous updating requirement any time an affiliate 
acquires additional generation assets, re-rates an existing facility, 
or enters into third-party contracts that confer some degree of 
control.\1186\ Powerex states that in certain circumstances, release of 
information could be inconsistent with the standards and policies of 
the foreign utility regulatory agency regulating the foreign generation 
owner.\1187\ Powerex argues that concerns related to these types of 
frequently non-public changes to an affiliate's generation profile are 
appropriately limited to United States assets located in United States 
markets.
---------------------------------------------------------------------------

    \1186\ Id. at 31.
    \1187\ Powerex at 31.
---------------------------------------------------------------------------

Commission Determination
    1043. The Commission treats foreign-sited generation facilities 
interconnected to an affiliated transmission system that, in turn, is 
directly interconnected to the United States transmission grid in the 
same way that it treats the first-tier generation facilities of non-
foreign sellers. For the purpose of determining total uncommitted 
capacity, the affiliates' capacity is combined.
    1044. In response to Powerex, we agree that if the Commission's 
grant of market-based rate authority was based on the seller's, 
including its affiliate's, uncommitted capacity exceeding the 
transmission limits of the intertie(s) directly interconnecting the 
seller to the United States grid, only changes in the TTC of the 
intertie would be considered a change in status subject to a reporting 
requirement.
    1045. Further, if a foreign utility believes that release of 
specific information is inconsistent with the policies of a foreign 
utility regulatory agency, the foreign utility should specifically 
inform the Commission of this, and the Commission will take the matter 
under advisement when considering whether to grant a request for 
special treatment.
4. Third-Party Providers of Ancillary Services
Commission Proposal
    1046. In Order No. 888, the Commission required transmission 
providers to offer certain ancillary services at cost-based rates as 
part of their open access commitment but also contemplated that third 
parties (parties other than the transmission provider in a particular 
transaction) could provide certain ancillary services.\1188\ The 
Commission also left open the door for ancillary services to be 
provided on other than a cost-of-service basis. In Order No. 888, the 
Commission stated that it would entertain requests for market-based 
pricing related to ancillary services on a case-by-case basis if 
supported by analyses that demonstrate that the seller lacks market 
power in these discrete services.\1189\
---------------------------------------------------------------------------

    \1188\ See Order No. 888, FERC Stats. & Regs. ] 31,036 at 
31,720-21.
    \1189\ Id.; Order No. 888-A, FERC Stats. & Regs. ] 31,048 at 
30,237-38.
---------------------------------------------------------------------------

    1047. In Ocean Vista Power Generation, L.L.C.,\1190\ the Commission 
explained that, as a general matter, a study of ancillary service 
markets should address the nature and characteristics of each ancillary 
service, as well as the nature and characteristics of generation 
capable of supplying each service, and that the study should develop 
market shares for each service. In particular, the Commission stated 
that an individual seller's market power analysis for ancillary 
services markets should: (1) Define the relevant product market for 
each ancillary service; (2) identify the relevant geographic market, 
which could include all potential sellers of the product from whom the 
buyer could obtain the service, taking into account relevant factors 
which may include the other sellers' locations, the physical capability 
of the delivery system and the cost of such delivery, and important 
technical characteristics of the sellers' facilities; (3) establish 
market shares for all suppliers of the ancillary services in the 
relevant geographic markets; and (4) examine other barriers to entry. 
The Commission also noted that it would entertain alternative 
explanations and approaches.
---------------------------------------------------------------------------

    \1190\ 82 FERC ] 61,114 at 61,406-07 (Ocean Vista).
---------------------------------------------------------------------------

    1048. The Commission adopted in Avista Corporation \1191\ a general 
policy stating that third-party ancillary service providers that could 
not perform a market power study would be allowed to sell ancillary 
services at market-based rates, but only in conjunction with a 
requirement that such third parties establish an Internet-based OASIS-
like site for providing information about and transacting ancillary 
services. The authorization in Avista extended only to the following 
four ancillary services: Regulation Service, Energy Imbalance Service, 
Spinning Reserves, and Supplemental Reserves. The Commission based its 
Avista policy on the expectation that, as entry into ancillary service 
markets occurs, prices will decrease from the level established by the 
transmission provider's cost-based rate. Under these circumstances, 
customers will pay prices for ancillary services that are no higher 
than and will very likely be lower than the transmission provider's 
cost-based rate. The Commission explained that the ancillary services 
customer is protected in part by the availability of the same ancillary 
services at cost-based rates from the transmission provider. The 
backstop of cost-based ancillary services from the transmission 
provider provides, in effect, a limit on the price at which customers 
are willing to buy ancillary services.\1192\
---------------------------------------------------------------------------

    \1191\ 87 FERC ] 61,223, order on reh'g, 89 FERC ] 61,136 (1999) 
(Avista).
    \1192\ We note that the Commission has authorized several 
utilities to use market index pricing for energy imbalance service. 
See, e.g., PacifiCorp, 95 FERC ] 61,145 (2001), order on reh'g, 95 
FERC ] 61,467 (2001). In such a case, customers are protected by the 
transmission provider's obligation to offer the service at rates the 
Commission determines are just and reasonable and consistent with 
our Avista policy.
---------------------------------------------------------------------------

    1049. To further monitor market entry, the Commission required 
third-party suppliers to file with the Commission one year after their 
Internet-based site was operational (and at least every three years 
thereafter) a report detailing their activities in the ancillary 
services market.\1193\
---------------------------------------------------------------------------

    \1193\ The Commission subsequently established an EQR 
requirement for all market-based rate sellers.
---------------------------------------------------------------------------

    1050. The Commission stated that it would apply this policy only to 
sellers that are authorized to sell power and energy at market-based 
rates. In addition, the Commission stated that it

[[Page 40030]]

would not apply this approach to sales of ancillary services by a 
third-party supplier in the following situations: (1) Sales to an RTO 
or an ISO, i.e., where that entity has no ability to self-supply 
ancillary services but instead depends on third parties; \1194\ (2) to 
address affiliate abuse concerns, sales to a traditional, franchised 
public utility affiliated with the third-party supplier, or sales where 
the underlying transmission service is on the system of the public 
utility affiliated with the third-party supplier; and (3) sales to a 
public utility that is purchasing ancillary services to satisfy its own 
open access transmission tariff requirements to offer ancillary 
services to its own customers.\1195\
---------------------------------------------------------------------------

    \1194\ With the formation of RTOs and ISOs, several RTOs/ISOs 
performed market analyses to demonstrate whether various ancillary 
services are competitive. The result has been as follows: California 
Independent System Operator: Regulation, Spinning Reserve, and Non-
Spinning Reserve. ISO New England: Regulation and Frequency 
(Automatic Generation Control), Operating Reserve--Ten-Minute 
Spinning, Operating Reserve--Ten-Minute Non-Spinning, and Operating 
Reserve--Thirty Minute. New York Independent System Operator: 
Regulation and Frequency Response Service, Operating Reserve Service 
(including Spinning Reserve, 10-Minute Non-Synchronized Reserves and 
30-Minute Reserves). PJM Independent System Operator: Regulation and 
Frequency Response, Energy Imbalance, Operating Reserve--Spinning, 
and Operating Reserve--Supplemental. Thus, in markets where the 
demonstration has been made, sellers are afforded the opportunity to 
sell at market-based rates subject to any other conditions in those 
markets.
    \1195\ Avista, 87 FERC at 61,883, n.12.
---------------------------------------------------------------------------

    1051. In the NOPR, the Commission proposed to retain the Avista 
policy but sought comment on whether to modify or revise that current 
approach and, if so, how. The Commission also sought comment on whether 
its current conditions, such as the requirement to establish an 
Internet-based site, continue to be necessary.
a. Internet Postings and Reporting Requirements
Comments
    1052. A number of commenters support modifications to the 
Commission's current approach to third-party sales of ancillary 
services on the basis that they believe the current policy has not 
succeeded in engendering robust markets for ancillary services. Avista, 
Puget, Cogentrix and Powerex state that the existing Internet posting 
and reporting policy is unnecessary.\1196\ Avista and Puget note that 
the current EQR requirement, which did not exist when the Commission 
first adopted the Internet posting requirement, provides sufficient 
information for the Commission to monitor ancillary services markets 
for market power. They argue that abandoning the Internet posting and 
reporting conditions would contribute to the development of more robust 
reserves markets. Similarly, Cogentrix and Powerex maintain that those 
requirements are burdensome and hard to implement, especially for 
independent sellers that are not transmission owners and do not have 
the responsibility to maintain an OASIS. Instead of safeguarding 
against possible abuses of market power, these commenters state that 
the posting and reporting requirements have probably hindered the 
development of robust markets for ancillary services.
---------------------------------------------------------------------------

    \1196\ Avista at 7-8; Puget at 1, 4-8; Cogentrix at 8-10; 
Powerex at 35-38; Morgan Stanley at 11-12.
---------------------------------------------------------------------------

    1053. Puget states that virtually all ancillary services outside of 
RTO/ISO markets are provided at cost-based rates by the host 
transmission provider. Puget states that it conducted a review of the 
reports filed in dockets in which the Commission has granted market-
based rate authority to sell ancillary services under the Avista 
provisions, which revealed that only a handful of ancillary services 
sales have been made. Based on the small number of market-based 
ancillary services sales that Puget found in its review of existing 
dockets, it concludes that companies have determined that the potential 
commercial gains from entering this market do not justify the cost and 
risks associated with the special posting and reporting requirements.
    1054. Avista and Powerex state that, to the extent that the 
Commission is concerned about market power, purchasers of ancillary 
services are protected from the exercise of market power because they 
may purchase these services from the transmission provider at cost 
pursuant to the OATT. Powerex maintains that the Commission can monitor 
these transactions via the EQRs and can encourage purchasers to file 
complaints under FPA section 206 should they believe a seller has 
exercised market power when making such sales.
    1055. In contrast, APPA/TAPS urge the Commission not to relax 
standards for market-based pricing of ancillary services. They support 
continuation of the Commission's current approach for pricing ancillary 
services, including the requirement for a cost-based backstop for 
ancillary services provided by a transmission provider. They argue that 
ancillary services markets remain very much dependent upon control area 
operation and are closely connected to the operations of the 
transmission system. APPA/TAPS state that locational reserves 
requirements limit the geographic scope of potential ancillary service 
suppliers, and that capacity on automatic generation control cannot 
easily sell regulation service in its home market today and switch to 
sales in an adjoining market tomorrow. Further, they state that 
customers cannot shop for such services. According to APPA/TAPS, 
limitations of transmission and technology counsel against adopting 
short-cuts for assessing the appropriateness of market-based pricing of 
ancillary services.\1197\
---------------------------------------------------------------------------

    \1197\ APPA/TAPS at 91.
---------------------------------------------------------------------------

    1056. Morgan Stanley supports efforts to establish market-based 
ancillary service markets both inside and outside of ISOs and RTOs. 
Morgan Stanley recommends that the Commission investigate what is 
necessary to establish local ancillary services markets on a nationwide 
basis. Morgan Stanley supports eliminating barriers to entry in the 
ancillary services market and states that to further this goal, the 
Commission should allow market participants to negotiate over-the-
counter (OTC) ancillary services contracts outside of established ISOs 
and RTOs. Morgan Stanley mentions that this option should be open to 
all sellers with market-based rates and that the posting requirement 
should remain mandatory for mitigated entities.
Commission Determination
    1057. We will modify our current approach for third-party sellers 
of ancillary services at market-based rates as announced in Avista. We 
appreciate the concerns raised by a number of commenters that the 
posting and reporting requirements imposed in Avista may be hindering 
the development of ancillary services markets particularly by third-
party providers. As noted above, some commenters have indicated that 
the costs and responsibilities associated with establishing and 
maintaining an internet-based site may outweigh the benefits that 
third-party sellers could derive from the sale of the additional 
products. We conclude that our EQR filing requirement provides an 
adequate means to monitor ancillary services sales by third parties 
such that the posting and reporting requirements established in Avista 
are no longer necessary. Through their EQR filings, third-party 
providers of ancillary services provide information regarding their 
ancillary services transactions for the quarter, including the 
ancillary service provided, the price, and the purchaser. As a result, 
we will no longer require third-party providers of

[[Page 40031]]

ancillary services to establish and maintain an internet-based OASIS-
like site for providing information about their ancillary services 
transactions.
    1058. In addition, we will no longer require third-party suppliers 
to file with the Commission one year after their internet-based site is 
operational (and at least every three years thereafter) a report 
detailing their activities in the ancillary services market. We note 
that the Commission retains the ability to require such a report by a 
third-party supplier of ancillary services at any time.
    1059. All sellers that seek authority to sell ancillary services at 
market-based rates pursuant to Avista \1198\ must make a filing with 
the Commission to request that authority and must include language in 
their market-based rate tariffs identifying the ancillary services that 
they offer.\1199\
---------------------------------------------------------------------------

    \1198\ As noted above, the Avista policy applies to the 
following four ancillary services: Regulation Service, Energy 
Imbalance Service, Spinning Reserves, and Supplemental Reserves.
    \1199\ Sellers that have been granted authority to provide 
third-party ancillary services need not reapply because their 
authority continues.
---------------------------------------------------------------------------

    1060. Moreover, we will retain our current policy of not allowing 
sales of ancillary services by a third-party supplier in the following 
situations: (1) Sales to an RTO or an ISO, i.e., where that entity has 
no ability to self-supply ancillary services but instead depends on 
third parties; (2) sales to a traditional, franchised public utility 
affiliated with the third-party supplier, or sales where the underlying 
transmission service is on the system of the public utility affiliated 
with the third-party supplier; and (3) sales to a public utility that 
is purchasing ancillary services to satisfy its own open access 
transmission tariff requirements to offer ancillary services to its own 
customers.\1200\ These standard applicable tariff provisions appear in 
Appendix C to this Final Rule. As we stated in Avista, we are open to 
considering requests for market-based rate authorization to make such 
sales on a case-by-case basis.
---------------------------------------------------------------------------

    \1200\ Avista, 87 FERC at 61,883, n. 12.
---------------------------------------------------------------------------

    1061. At this time, the Commission will not adopt Morgan Stanley's 
recommendation to investigate what is necessary to establish local 
ancillary services markets on a nationwide basis. We believe that the 
elimination of certain reporting requirements for third party providers 
of ancillary services adopted herein will adequately balance the need 
to encourage the development of ancillary services markets and the 
Commission's responsibility to provide oversight and protection from 
market power. We find Morgan Stanley's suggestion that the Commission 
allow market participants to negotiate OTC ancillary services contracts 
outside of established RTO/ISO markets unsupported and lacking in 
detail.\1201\
---------------------------------------------------------------------------

    \1201\ Morgan Stanley's comments provide an insufficient basis 
for us to determine whether such OTC ancillary services contracts 
would be jurisdictional. The Commission has previously stated that 
it is not concerned with management transactions (such as swaps, 
options, and futures contracts) designed to assist buyers and 
sellers of electricity in hedging against adverse price changes 
which are settled in cash and where parties do not take actual 
delivery of the electricity. Morgan Stanley Capital Group, Inc., 69 
FERC ] 61,175 (1994).
---------------------------------------------------------------------------

b. Pricing for Ancillary Services in RTOs/ISOs
Comments
    1062. As noted above, the Commission stated in Order No. 888 that 
it would entertain requests for market-based pricing related to 
ancillary services on a case-by-case basis if supported by analyses 
which demonstrate that the seller lacks market power in these discrete 
services.\1202\ To date, the Commission has permitted market-based rate 
pricing for certain ancillary services in a number of RTOs and 
ISOs.\1203\ Although Ameren supports retaining the Commission's current 
approach, Ameren urges the Commission to address what it describes as a 
critical market design flaw regarding pricing for ancillary services in 
RTO/ISO markets with Day 2 energy markets but no market for ancillary 
services, such as the Midwest ISO. Ameren explains that providing 
regulation service and spinning reserves in the Midwest ISO market at 
traditional cost-based rates is uneconomic at present because owners of 
ancillary services capacity generally find it more profitable to sell 
energy from the capacity at market-based rates rather than to offer the 
capacity as reserves at cost-based rates. Ameren recommends that the 
Commission ensure that its approach to sales of ancillary services 
provides flexibility by allowing sellers for cost-based rates for 
regulation service and spinning reserves in the Midwest ISO footprint 
to propose a component for recovery of lost opportunity costs where 
such costs are shown to be legitimate and verifiable. Ameren submits 
that the Commission has recognized the need for opportunity cost 
recovery in other circumstances, and should consider an opportunity 
cost component in the future.\1204\
---------------------------------------------------------------------------

    \1202\ Order No. 888, FERC Stats. & Regs. ] 31,036 at 31,656-57; 
Order No. 888-A, FERC Stats. & Regs. ] 31,048 at 30,230.
    \1203\ AES Redondo Beach, L.L.C., et al., 85 FERC ] 61,123 
(1998), order on reh'g, 87 FERC ] 61,208 (1999), order on reh'g and 
clarification, 90 FERC ] 61,036 (2000); New England Power Pool, 85 
FERC ] 61,379 (1998), reh'g denied, 95 FERC ] 61,074 (2001); Central 
Hudson Gas & Electric Corporation, et al., 86 FERC ] 61,062, order 
on reh'g, 88 FERC ] 61,138 (1999).
    \1204\ Ameren at 24-25, citing San Diego Gas & Elec. Co., 95 
FERC ] 61,115 at 61,363-64 & n.47 (2001).
---------------------------------------------------------------------------

    1063. CAISO states that it agrees with the Commission's decision to 
distinguish sales within an RTO or ISO from those not within an RTO or 
ISO.\1205\ It agrees that the Commission can rely on the market 
monitoring unit of the RTO or ISO to assess competitiveness in the RTO 
or ISO's ancillary service markets.\1206\
---------------------------------------------------------------------------

    \1205\ CAISO at 16-18.
    \1206\ CAISO recommends that the Final Rule emphasize the 
importance of appropriate RTO or ISO market power mitigation tariff 
provisions for sales involving ancillary services.
---------------------------------------------------------------------------

    1064. However, CAISO also notes that the size of the ancillary 
service market is subject to change based on system conditions and the 
need to meet applicable reliability criteria. It says that at times the 
CAISO may be able to procure ancillary services on a system-wide basis, 
whereas at other times factors such as the proportionate mix of hydro 
and thermal resources, transmission path operating transfer capability 
limits or deratings, forecasted path flows, anticipated load and 
weather conditions, and generator outages may require the CAISO to 
procure ancillary services on a zonal or even more location-specific 
basis. CAISO also states that because not every facility has the 
capability to provide every ancillary service, the market power 
analysis for the energy market does not automatically ensure that 
market power cannot be exercised with respect to sales of ancillary 
services. Accordingly, CAISO states that there may be the need for more 
targeted market power mitigation procedures specifically applicable to 
sales of ancillary services.
    1065. NYISO supports the Commission's proposed approach to the 
extent it is predicated on all eligible sellers being able to benefit 
from the Commission's authorization of the NYISO to purchase ancillary 
services for loads at market-based rates.\1207\ It states that all 
eligible sellers should receive the market-clearing prices for 
ancillary services that are supplied on a market basis and that the 
final regulations should not impose burdensome and duplicative market 
data requirements on a potential seller of ancillary services, either 
directly or through data demands to an ISO if the ISO has already 
received

[[Page 40032]]

Commission authorization for market-based ancillary services.
---------------------------------------------------------------------------

    \1207\ NYISO at 10.
---------------------------------------------------------------------------

    1066. APPA/TAPS urge caution for market-based pricing of ancillary 
services in RTO/ISO areas. Even if the Commission finds that conditions 
exist to permit market-based pricing of some ancillary services in some 
RTO/ISO-administered markets, APPA/TAPS state that such pricing would 
not be appropriate where vertically integrated utilities are also 
control area operators, such as in Midwest ISO and SPP, because the 
locational, control-area dependent nature of ancillary services 
increases the risk that control area operators will have market 
power.\1208\
---------------------------------------------------------------------------

    \1208\ APPA/TAPS at 92.
---------------------------------------------------------------------------

    1067. Powerex recognizes that in some control areas, there are 
locational reserve requirements that can be met by a limited number of 
resources and therefore limit the geographic scope of potential 
suppliers.\1209\ Powerex believes, however, that this situation can be 
mitigated on a case-specific basis, and therefore that it should not be 
the basis for generally rejecting the benefits of competitive supply of 
ancillary services. Powerex believes that it is the combination of the 
Commission's existing regulatory framework and administrative barriers 
raised by transmission providers that has effectively stifled the 
incentives for third-party suppliers to participate in ancillary 
services markets.\1210\ In support, Powerex states that experience with 
the California organized markets demonstrates that a third-party 
provider can sell operating reserves and regulation service services to 
an adjoining market and that these services can be provided from 
resources located two markets and more than a thousand transmission 
miles away.
---------------------------------------------------------------------------

    \1209\ See, e.g., APPA/TAPS at 90-92.
    \1210\ Powerex reply comments at 1-3.
---------------------------------------------------------------------------

Commission Determination
    1068. We will continue our current approach regarding market-based 
pricing for certain ancillary services in RTOs and ISOs. Where an RTO 
or ISO performs a market analysis demonstrating a lack of market power 
for certain ancillary services, the Commission has approved the sale of 
those ancillary services at market-based rates. As reflected in the 
NOPR, the Commission has approved the sale of certain ancillary 
services at market-based rates in CAISO, ISO New England, NYISO, and 
PJM. Moreover, the Commission considers on a case-by-case basis market 
power mitigation measures for sales involving ancillary services in 
these markets.
    1069. Ameren's request that the Commission address what Ameren 
considers to be a critical market design flaw regarding pricing for 
ancillary services in the Midwest ISO is beyond the scope of this 
rulemaking proceeding. Ameren's concerns are more appropriately 
addressed upon an appropriate record in the context of proceedings 
involving the Midwest ISO market.
    1070. With regard to APPA/TAPS' concern that market-based pricing 
of ancillary services would not be appropriate where vertically 
integrated utilities are also balancing authority area operators, such 
as in Midwest ISO and SPP, we note that the Commission carefully 
analyzes ancillary service markets in ISOs and RTOs before authorizing 
market-based rate pricing, ensuring that protections, such as market 
monitors, are established to reduce the risk that market power can be 
exercised. APPA/TAPS has had the opportunity to intervene and 
participate in such proceedings, including in proceedings involving 
Midwest ISO and SPP.
    1071. The Commission also imposes mitigation where necessary. For 
example, the Commission in its PJM West/South Regulation Zone order 
permitted sellers that lack market power in PJM to submit market-based 
rate bids in the market for regulation service, while mitigating bids 
submitted by American Electric Power Company and Virginia Electric and 
Power Company, because PJM has not sufficiently demonstrated that they 
lack the potential to exercise market power in this market.\1211\
---------------------------------------------------------------------------

    \1211\ PJM Interconnection, L.L.C., 111 FERC ] 61,134 (2005) 
(PJM West/South Regulation Zone). Similarly, the Commission in New 
York Independent System Operator, Inc., 91 FERC ] 61,218 at 61,798-
802(2000), suspended market-based pricing in the non-spinning 
reserve market for a temporary period. The Commission imposed 
bidding restrictions on 10 minute non-spinning operating reserves 
suppliers and a mandatory bid requirement which required that all 
available capacity held by eastern suppliers of 10 minute non-
spinning reserves, and that is not subject to a bona fide outage or 
conflicting contractual obligation, be bid into the market. The 
Commission indicated that the mandatory bid requirement was 
necessary to protect against the physical withholding of capacity 
for the 10 minute non-spinning reserve market.
---------------------------------------------------------------------------

5. Reactive Power and Real Power Losses
Commission Proposal
    1072. In the NOPR, the Commission did not provide a proposal with 
regard to the treatment of reactive power and real power losses. 
However, several commenters submitted comments about these services.
a. Reactive Power
Comments
    1073. Cogentrix asks the Commission to reconsider the existing 
requirements for the sale of reactive power by independent generators. 
It notes that currently generators can sell reactive power only upon 
the submission to the Commission of separate cost filings. Cogentrix 
submits that the requirement of cost justification of reactive power 
rates should be eliminated. Cogentrix states that this requirement is 
unnecessary because generators with market-based rate authority are 
found to lack market power and are subject to the EQR and change in 
status reporting requirements, which ensure that they continue to lack 
market power and, therefore, that they cannot dictate the pricing of 
reactive power services. Cogentrix submits that because reactive power 
is a service that purchasers require generators to provide, it should 
be left to the parties to negotiate the proper rate under the 
interconnection agreement or the power purchase agreement, without 
requiring the generator to submit additional cost filings.\1212\
---------------------------------------------------------------------------

    \1212\ Cogentrix at 10.
---------------------------------------------------------------------------

Commission Determination
    1074. We reject Cogentrix's proposal that the Commission reconsider 
in this proceeding existing requirements for the sale of reactive power 
by independent generators and eliminate the requirement that generators 
submit separate cost filings supporting reactive power sales. 
Consistent with our precedent,\1213\ we will continue to analyze 
reactive power sales on a case-by-case basis.
---------------------------------------------------------------------------

    \1213\ See, e.g., Calpine Oneta Power, L.P, 119 FERC ] 61,177 
(2007), and cases cited therein.
---------------------------------------------------------------------------

b. Real Power Losses
Comments
    1075. Powerex requests that the Commission explicitly permit 
sellers to offer third-party loss compensation services \1214\ on non-
affiliated transmission systems under their general market-based rate 
authority.\1215\ Powerex states that it believes that third parties 
currently are making real power losses sales pursuant to their market-

[[Page 40033]]

based rate authority.\1216\ Powerex believes that the provision of real 
power losses is no different than the provision of other energy. It 
notes that in some control areas, the provision of such services comes 
with other attendant duties such as acting as the scheduling party for 
the losses.
---------------------------------------------------------------------------

    \1214\ Although Powerex does not directly define loss 
compensation energy, we interpret it to be equivalent to real power 
losses associated with all transmission service. The Commission's 
pro forma OATT in Order No. 890, sections 15.7 and 28.5, refer to 
real power losses. For purposes of this Final Rule, we will refer to 
loss compensation service or energy as real power losses.
    \1215\ Powerex initial comments at 38-40.
    \1216\ Powerex cites to a filing in which Ameren stated its 
understanding that it ``may sell the energy that will be used by 
customers that choose to self-supply energy to meet their 
transmission losses to such customers under its general market-based 
power sales authority. [Ameren] will merely be selling the power the 
customer will use to meet its losses and obligations and, from 
[Ameren's] standpoint, this will be no different than any other 
power sale. Such sales are also consistent with the Commission's 
decision to treat the provision of losses as a service that can be 
provided by multiple entities, rather than one that the transmission 
provider is uniquely situated to provide.'' Powerex at 39, citing 
Letter Transmitting Compliance Filing, Ameren Energy Marketing Co., 
Docket No. ER01-1945, at n.3 (July 27, 2001).
---------------------------------------------------------------------------

Commission Determination
    1076. We agree with Powerex that the provision of real power losses 
is no different than the provision of other energy. We clarify that we 
permit sellers to offer third-party real power losses on non-affiliated 
transmission systems under their market-based rate authority.

V. Section-by-Section Analysis of Regulations

1. Section 35.27 Authority of State Commissions

    1077. In the NOPR, we explained that the first two paragraphs of 
this section were added by Order No. 888, while Order No. 652 later 
added subsection (c) to implement the change in status reporting 
requirement. The Commission proposed to move or delete subsections (a) 
and (c), leaving only (b), which clarifies that nothing in this part 
should be construed as preempting or affecting the authority of State 
commissions. The NOPR did not propose to revise the language of 
subsection (b) in any way, and proposed only to amend the heading from 
``Power Sales at Market-Based Rates'' to ``Authority of State 
Commissions.'' NASUCA filed comments in support of ``assuring that 
there will be no preemption of State prerogatives under the proposed 
new regulations * * *.'' \1217\
---------------------------------------------------------------------------

    \1217\ NASUCA at 3-4.
---------------------------------------------------------------------------

    1078. We reiterate that the Commission is not proposing to add or 
revise this provision at this time. It remains unchanged from when the 
Commission adopted it in Order No. 888. The fact that it is renumbered 
in this proceeding will not have any impact, positive or negative, on 
the prerogatives of State commissions.

2. Section 35.36 Generally

    1079. This section defines certain terms specific to Subpart H and 
explains the applicability of Subpart H. Some of these terms were put 
in place when the Commission codified certain market behavior rules in 
Order No. 674.\1218\
---------------------------------------------------------------------------

    \1218\ Conditions for Public Utility Market-Based Rate 
Authorization Holders, Order No. 674, FERC Stats. & Regs. ] 31,208, 
114 FERC ] 61,163 (2006).
---------------------------------------------------------------------------

    1080. The NOPR proposed to define ``Seller'' in paragraph (a)(1) as 
a public utility with authority to, or seeking authority to, engage in 
sales for resale of electric energy at market-based rates in order to 
make clear that Subpart H deals exclusively with market-based rate 
power sales. NASUCA comments that the explanation for the definition of 
``Seller'' does not mention any language in FPA section 205 regarding 
``market-based rates,'' and further, that there is no reference to 
market-based rates in that section of the Act. Thus, NASUCA contends 
that ``the reference in the definition of ``seller'' to ``market-based 
rates under section 205 of the Federal Power Act'' is a non sequitur, 
lacks support in the statutory language, and should be deleted.'' 
\1219\
---------------------------------------------------------------------------

    \1219\ NASUCA at 32.
---------------------------------------------------------------------------

    1081. We do not agree that the limiting language should be deleted. 
We believe that it is essential that the regulations in subpart H apply 
only to the specific sales that we are regulating herein (i.e., market-
based rates for wholesale sales of electric energy, capacity and 
ancillary services by public utilities) and not to any sales made at 
cost-based rates or under any other authority; the definition should 
make this scope clear. To the extent that NASUCA is challenging the 
Commission's ability to authorize market-based rates at all, the 
Commission addresses NASUCA's arguments in that regard in the legal 
authority section of this Final Rule.
    1082. In the NOPR, the Commission proposed definitions for Category 
1 Sellers and Category 2 Sellers to assist in understanding the 
parameters of the updated market power analysis filing requirement. The 
definition of Category 1 Sellers is being clarified, consistent with 
the discussion above in Implementation Process.
    1083. Paragraph (a)(4) defines inputs to electric power production 
in order to simplify Sec.  35.37(e) regarding other barriers to entry. 
The Final Rule revises the definition consistent with the discussion in 
the vertical market power section.
    1084. Paragraph (a)(5) indicates that where the term franchised 
public utility is used, it is meant to include only those public 
utilities with a franchised service obligation under State law. The 
Commission modifies the definition as proposed in the NOPR so that the 
term ``franchised public utility'' does not include only utilities with 
captive customers. Instead, throughout the final regulations, 
references to franchised public utilities with captive customers are 
explicitly identified, where applicable.
    1085. New paragraph (a)(6) provides a definition of captive 
customers, the genesis of which is discussed above in the Affiliate 
Abuse section.
    1086. Paragraph (a)(7) (which was proposed as Sec.  35.36(a)(6) in 
the NOPR) provides a definition for market-regulated affiliated 
entities.
    1087. New paragraph (a)(8) provides a definition of market 
information.
    1088. Paragraph (b) is a basic description of the applicability of 
Subpart H.

3. Section 35.37 Market Power Analysis Required

    1089. This section describes the market power analysis the 
Commission employs, as discussed in the preamble, and when sellers must 
file one. It is intended to identify the key aspects of the analysis.
    1090. The Final Rule adds paragraph (a)(2), which codifies the 
requirement mentioned in the NOPR for each seller to include an 
appendix identifying specified assets with each market power analysis 
filed. The paragraph also directs readers to Appendix B for a sample 
asset appendix.
    1091. New language in paragaphs (c)(2) and (c)(3) clarifies that 
both sellers and intervenors may file alternative evidence to support 
or rebut the indicative screens, and addresses the use of the Delivered 
Price Test and its role in the analysis of market power, respectively. 
Further, at paragraph (c)(4), the regulations codify the requirement 
that each seller use a standard format for the indicative screens, the 
use of which was proposed in the NOPR.
    1092. Paragraph (d) specifies the requirement that a seller with 
transmission facilities must have on file an Open Access Transmission 
Tariff. The Final Rule adds a description of how this requirement 
applies to sellers affiliated with foreign utilities.
    1093. Paragraph (e) describes the information that must be provided 
to demonstrate a lack of vertical market power. The text is revised in 
several respects reflecting the discussion in the section of the Final 
Rule on vertical market power.

[[Page 40034]]

    1094. The Final Rule adds a new paragraph (f) to address concerns 
that CEII claims in market-based rate filings have been overbroad. The 
subsection provides a process for intervenors to gain access to data 
for which the filer has claimed privileged treatment under 18 CFR 
388.112.

4. Section 35.38 Mitigation

    1095. The regulatory text proposed in the NOPR did not propose 
specific changes to the current approach to mitigation, and intended to 
capture the Commission's existing requirements. The Final Rule does not 
depart from this approach, and adopts the same regulatory text 
regarding mitigation as proposed in the NOPR, with the addition of a 
clarification that mitigation will apply only to the market or markets 
in which a seller is found, or presumed, to have market power.

5. Section 35.39 Affiliate Restrictions

    1096. This section governs affiliate transactions and affiliate 
relationships and establishes certain conditions that a seller must 
satisfy as a condition of its market-based rate authority. New 
paragraph (a) explains that, as a condition of obtaining and retaining 
market-based rate authority, the provisions set forth in the entire 
section, including the restriction on affiliate sales of electric 
energy and the affiliate restrictions, must be satisfied on an ongoing 
basis. Paragraph (b) expressly prohibits sales between a franchised 
public utility with captive customers and any of its market-regulated 
power sales affiliates without first receiving authorization for the 
transaction under section 205 of the FPA. This paragraph requires that, 
where the Commission grants a seller authority to engage in affiliate 
sales under its MBR tariff, any and all such authorizations must be 
listed in the seller's tariff. The language varies from that proposed 
in the NOPR to reflect changes to the definition of ``franchised public 
utility.''
    1097. Paragraphs (c)-(f) contain provisions governing the 
relationship between a franchised public utility with captive customers 
and its market-regulated power sales affiliates (formerly, code of 
conduct). The provisions of these paragraphs apply to all franchised 
public utilities with captive customers. These paragraphs include 
provisions governing the separation of employees, the sharing of market 
information, sales of non-power goods or services, and power brokering. 
The language varies from that proposed in the NOPR to reflect changes 
to the definition of ``franchised public utility'' and a number of 
other changes discussed in greater detail in the affiliate abuse 
section of this Final Rule.
    1098. As discussed above in Affiliate Abuse, the Commission is 
adding several provisions concerning separation of functions and 
information sharing to more closely model the Commission's standards of 
conduct, as appropriate. In addition, the final regulations include a 
new paragraph (g) with a general prohibition on using anyone as a 
conduit to circumvent any of the affiliate restrictions, and a new 
paragraph (h) explaining that, if necessary, affiliate restrictions 
involving two or more franchised public utilities, one or more of whom 
has captive customers and one or more of whom does not, will be imposed 
on a case-by-case basis.

6. Section 35.40 Ancillary Services

    1099. This provision restricts sales of ancillary services to those 
specific geographic markets for which the Commission has authorized 
market-based rate sales of such services. In the Final Rule, we delete 
proposed paragraph (b), which reflected the Internet posting and 
reporting requirements found in Avista Corporation,\1220\ and which we 
find are no longer necessary, as discussed above in the section on 
Ancillary Services. We also delete proposed subsection (c), which 
described limitations on sales of ancillary services by third-party 
providers; we believe that the standard applicable tariff provision, 
which will be available on the Commission's Web site as it may be 
revised from time to time, will adequately apprise sellers of the 
current policy concerning third-party providers.
---------------------------------------------------------------------------

    \1220\ Avista Corporation, 87 FERC ] 61,223, order on reh'g, 89 
FERC ] 61,136 (1999).
---------------------------------------------------------------------------

7. Section 35.41 Market Behavior Rules

    1100. In Order No. 674, the Commission rescinded two of its market 
behavior rules and codified the remainder in Sec.  35.37 of new Subpart 
H. The NOPR proposed to move these market behavior rules, unchanged, 
from Sec.  35.37 to Sec.  35.41. NASUCA submitted a number of 
substantive comments on these provisions. Because we did not propose 
any revisions to these rules, and we are not revising them 
substantively in this Final Rule, NASUCA's comments are beyond the 
scope of this proceeding. We are, however, taking this opportunity to 
make several minor corrections and stylistic edits to the market 
behavior rules.

8. Section 35.42 Change in Status Reporting Requirement

    1101. This section incorporates the provision previously found at 
paragraph 35.27(c), which was codified by Order No. 652. The final 
regulatory text clarifies distinctions between generation facilities 
and transmission facilities, and incorporates minor revisions as 
discussed above in the section on Changes in Status.
    1102. The Final Rule adds paragraph (c), which codifies the 
requirement that each seller include an appendix identifying specified 
assets with each pertinent change in status notification filed. The 
paragraph also directs readers to Appendix B for a sample asset 
appendix.

9. Miscellaneous

    1103. The final regulations add the phrase ``unless otherwise 
permitted by Commission rule or order'' in several places throughout 
the regulations to make clear that these general provisions are not 
meant to override approvals granted in particular circumstances in 
other orders or rules.
    1104. In this Final Rule, the Commission has deleted proposed Sec.  
35.42, MBR Tariff, which required sellers to have on file the MBR 
tariff of general applicability. That requirement has been modified, as 
explained above in the section on the MBR tariff; accordingly the 
regulation will not be adopted.

VI. Information Collection Statement

    1105. The Office of Management and Budget (OMB) regulations require 
approval of certain information collection and data retention 
requirements imposed by agency rules.\1221\ Upon approval of a 
collection of information and data retention, OMB will assign an OMB 
control number and an expiration date. Respondents subject to the 
filing requirements of this rule will not be penalized for failing to 
respond to these collections of information unless the collections of 
information display a valid OMB control number. As discussed herein, 
the Commission is amending its regulations to codify its requirements 
for obtaining and retaining market-based rate authorization, 
implementing a market-based rate tariff, and incorporating the change 
in status reporting requirement for sellers seeking market-based rate 
authority.
---------------------------------------------------------------------------

    \1221\ 5 CFR 1320.11.
---------------------------------------------------------------------------

Initial Market Power Analysis

    1106. The Commission has previously required utilities seeking 
market-based

[[Page 40035]]

rate authority to file a market power analysis with the Commission; the 
Commission now codifies that requirement in the Commission's 
regulations. This Final Rule reflects the Commission's existing 
practice developed over the years through individual cases and will not 
impose any additional burden, with the following exception.
    1107. Section 35.27(a) of the Commission's regulations \1222\ 
currently provides that any public utility seeking market-based rate 
authority shall not be required to submit a generation market power 
analysis with respect to sales from capacity for which construction 
commenced on or after July 9, 1996. Under current procedures, if all 
the generation owned or controlled by an applicant for market-based 
rate authority and its affiliates in the relevant balancing authority 
area is post-July 9, 1996 generation, such seller is not required to 
submit a generation market power analysis. In this Final Rule, the 
Commission eliminates the express exemption provided in Sec.  35.27(a). 
This change means that all new sellers seeking market-based rate 
authority on or after the effective date of the Final Rule issued in 
this proceeding, whether or not all of their and their affiliates' 
generation was built or acquired after July 9, 1996, must provide a 
market power analysis of their generation to support their application 
for market-based rate authority.
---------------------------------------------------------------------------

    \1222\ 18 CFR 35.27(a).
---------------------------------------------------------------------------

    1108. Because the Commission allows a seller to make simplifying 
assumptions, where appropriate, and therefore to submit a streamlined 
analysis, the Commission believes that any burden of document 
preparation occasioned by the elimination of Sec.  35.27(a) should be 
minimal. To the extent that there are greater costs for some sellers, 
the benefit of ensuring that markets do not become less competitive 
over time outweighs any additional costs.

Updated Market Power Analyses

    1109. To retain market-based rate authority, the Commission 
currently requires that sellers file an updated market power analysis 
every three years. In this Final Rule, the Commission codifies the 
requirement that certain sellers with market-based rate authority file 
an updated analysis with the Commission to retain that authority. 
However, Category 1 sellers will be relieved of their existing 
obligation to file regularly scheduled updated market power analyses, 
as explained in the Implementation Process section of this Final Rule. 
Instead, sellers that believe they fall into Category 1 will be 
required to submit a filing with the Commission at the time that 
updated market power analyses for the seller's relevant market would 
otherwise be due (based on the regional schedule for updated market 
power analyses adopted in this Final Rule) explaining why the seller 
meets the Category 1 criteria, including a list of all generation 
assets (including nameplate or seasonal capacity amounts) owned or 
controlled by the seller and its affiliates grouped by balancing 
authority area. Once the Commission agrees that a seller meets the 
Category 1 criteria, that seller will not have to file regularly 
scheduled updated market power analyses. Category 2 sellers will retain 
their existing obligation to file a regularly scheduled updated market 
power analysis. Thus, Category 2 sellers will not face a greater burden 
to provide the Commission with the information required for an updated 
market power analysis.
    1110. In addition, the elimination of Sec.  35.27(a) also means 
that existing Category 2 sellers filing updated market power analyses 
on or after the effective date of the Final Rule issued in this 
proceeding, whether or not all of their and their affiliates' 
generation was built or acquired after July 9, 1996, must provide a 
market power analysis of their generation to support their continued 
market-based rate authority.
    1111. Mirant argues that, with the elimination of the Sec.  
35.27(a) exemption, its cost of compliance will increase because it 
will have to prepare four updated market power analyses, each costing 
$20,000 to prepare and file, for companies that would have qualified 
for the Sec.  35.27(a) exemption. Mirant states that only one of its 
subsidiaries would qualify as a Category 1 seller and Mirant still 
would have to make four updated market power analysis filings. On the 
other hand, other commenters state that the benefits of eliminating the 
Sec.  35.27(a) exemption outweigh any added burdens.
    1112. Because the Commission allows a seller to make simplifying 
assumptions and rely on previously filed analyses by other market 
participants, where appropriate, and therefore to submit a streamlined 
analysis, the Commission believes that any burden of document 
preparation occasioned by the elimination of Sec.  35.27(a) should be 
minimal. To the extent that there are greater costs for some sellers, 
the benefit of ensuring that markets do not become less competitive 
over time outweighs any additional costs.

Regional Review and Schedule

    1113. In the NOPR, the Commission proposed to require each seller 
to file an updated market power analysis for its relevant geographic 
market(s) on a schedule that will allow examination of the individual 
seller at the same time the Commission examines other sellers in these 
relevant markets and contiguous markets within a region from which 
power could be imported. The regional reviews would rotate by 
geographic region.
    1114. Some commenters expressed concern that regional review would 
increase the burden associated with filing updated market power 
analyses. Reliant, for example, states that companies which engage in 
business in multiple regions of the United States would have to file 
several times over the three year schedule instead of once as is 
required currently.\1223\ Other commenters support the regional review 
proposal. For example, NRECA maintains that the proposed regional 
approach will not impose an undue compliance burden on sellers. It 
notes that the regional review approach will ensure greater consistency 
in the data used to evaluate Category 2 sellers, citing the 
Commission's statement in the NOPR that the Commission ``will have 
before it a complete picture of the uncommitted capacity and 
simultaneous import capability into the relevant geographic markets 
under review.'' \1224\ NRECA states that any increase in the burden on 
sellers hardly outweighs these substantial benefits. NRECA submits that 
the Commission has proposed a reasonable procedure to better ensure 
that market-based rate authority is granted only in appropriate 
circumstances. When compared with the burden, cost and time required by 
a cost-of-service rate regime, NRECA asserts that the burden of 
complying with the regional review approach will be minimal. APPA/TAPS 
describe the regional review proposed in the NOPR as a sensible 
proposal to conduct updated market power analyses on a rotating, 
regional basis to improve the quality and quantity of the data relied 
upon for market-based rate determinations and to provide the Commission 
with a more comprehensive picture of competitive conditions in regional 
markets. They assert that the Commission should not

[[Page 40036]]

sacrifice improvements to its market-based rate program to the 
interests of a few companies and that any increased financial cost to 
companies associated with regional reviews is outweighed by the 
companies' profits from market-based rate sales.
---------------------------------------------------------------------------

    \1223\ Similarly, Allegheny, Mirant, FP&L, EEI, FirstEnergy, 
MidAmerican, TXU, Morgan Stanley, Financial Companies, and EPSA 
argue that large corporate families could find themselves in a 
perpetual triennial review that would place a substantial regulatory 
burden and expense on them.
    \1224\ NRECA reply comments at 28, citing NOPR at P 154.
---------------------------------------------------------------------------

    1115. We believe that the Commission's proposal properly and fairly 
balances the need to effectively, comprehensively, and accurately 
assess market power in wholesale markets with the desire to minimize 
any administrative burden associated with the filing and review of 
updated market power analyses. While we recognize that some sellers may 
file updates more frequently than currently, we have carefully balanced 
the interests of all involved, and we believe that regional reviews of 
updated market analyses will result in more accurate and complete data. 
This in turn will enhance the Commission's ability to continue to 
ensure that sellers either lack market power or have adequately 
mitigated such market power.
    1116. Further, in light of commenters' concern with the regional 
review schedule, the Commission has modified the schedule as proposed 
in the NOPR. The NOPR proposed that regional reviews would rotate by 
geographic region with three regions reviewed per year. Some commenters 
expressed concerned that, because they operate in multiple regions, 
they would be required to file updated market power analyses every year 
rather than every three years. To address this concern, we are reducing 
the number of filings that sellers with generation in multiple regions 
will have to make by consolidating the regions and reducing the total 
number from nine to six. With fewer and larger regions, sellers will 
likely occupy fewer regions, necessitating fewer filings.

Market-Based Rate Tariff

    1117. The NOPR proposed a tariff of general applicability (MBR 
tariff), which would provide greater consistency and reduce confusion 
regarding tariffs. The Commission recognized that the requirement to 
file the specified MBR tariff might cause a minimal burden of document 
preparation and organization for existing market-based rate sellers, 
but stated that long-term benefits would be realized for market 
participants as well as the Commission.
    1118. In this Final Rule, we do not adopt the NOPR proposal to 
require all sellers to adopt a tariff of general applicability. 
Instead, we adopt a set of standard tariff provisions that we will 
require each seller to include in its market-based rate tariff. While 
we will require all market-based rate sellers to make compliance 
filings to modify their existing tariffs to reflect these standard 
provisions, these compliance filings are to be made by each seller the 
next time the seller proposes a tariff change, makes a change in status 
filing, or submits an updated market power analysis in accordance with 
the schedule in Appendix D, whichever occurs first.
    1119. In the NOPR, the Commission also proposed that all market-
based rate sellers file one market-based rate tariff per corporate 
family. Many commenters expressed concern with this proposal. In light 
of these concerns, we are not requiring sellers to file one market-
based rate tariff per corporate family. Instead, we will allow sellers 
to elect whether to transact under a single market-based rate tariff 
for an entire corporate family or under separate tariffs.

General

    1120. The Commission's regulations in 18 CFR Part 35 specify those 
reporting requirements that must be followed in conjunction with the 
filing of rate schedules under the FPA. The information provided to the 
Commission under 18 CFR Part 35 is identified for information 
collection and records retention purposes as FERC-516. Data collection 
FERC-516 applies to all reporting requirements covered in 18 CFR Part 
35 including: electric rate schedule filings, market power analyses, 
tariff submissions, market-based rate analyses, and reporting 
requirements for changes in status for public utilities with market-
based rate authority.
    1121. The Commission is submitting these reporting and records 
retention requirements to OMB for its review and approval under section 
3507(d) of the Paperwork Reduction Act.\1225\ The Commission solicited 
comments on the Commission's need for this information, whether the 
information will have practical utility, the accuracy of provided 
burden estimates, ways to enhance the quality, utility, and clarity of 
the information to be collected, and any suggested methods for 
minimizing the respondent's burden, including the use of automated 
information techniques. The Commission did not receive comments 
specifically addressing the burden estimates in the NOPR. With the 
exceptions of estimates regarding sellers' market-based rate tariffs, 
the number of market-based rate sellers, and the burden estimates for 
Category 1 sellers, we will use the same estimates here as in the 
NOPR.\1226\
---------------------------------------------------------------------------

    \1225\ 44 U.S.C. 3507(d).
    \1226\ We note that the number of market-based rate sellers has 
increased since issuance of the NOPR in May 2006.
---------------------------------------------------------------------------

    1122. The number of respondents expected to file to revise market-
based rate tariffs has increased from the estimate set forth in the 
NOPR, given our decision not to require one MBR tariff per corporate 
family. We expect some sellers will opt to submit a single corporate 
tariff, but we will estimate the total number to be filed to be 
approximately 1230, rather than 650 as reported in the NOPR. We will 
conform the number of responses to reflect this new estimate as well. 
However, we note that this number may be significantly less if sellers 
choose the option to file one market-based rate tariff per corporate 
family. Additionally, the Commission proposed in the NOPR that sellers 
file their MBR tariffs as directed in the rulemaking proceeding 
requiring the submission of electronic tariffs. However, in this Final 
Rule, we are requiring that sellers file their modified tariffs the 
next time sellers propose a tariff change, make a change in status 
filing, or submit an updated market power analysis. We have adjusted 
the number of responses to reflect this requirement.
    Burden Estimate: The Public Reporting and records retention burden 
for all four reporting requirements and the records retention 
requirement is as follows.\1227\
---------------------------------------------------------------------------

    \1227\ These burden estimates apply only to this Final Rule and 
do not reflect upon all of FERC-516.

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

[[Page 40037]]

    Title: Electric Rate Schedule Filings (FERC-516).
    Action: Revised Collection.
    OMB Control No: 1902-0096.

----------------------------------------------------------------------------------------------------------------
                                                     Number of       Number of       Hours per     Total annual
                 Data collection                    respondents      responses       response          hours
----------------------------------------------------------------------------------------------------------------
Initial Market Power Analysis...................             120             120             130          15,600
Market-Based Rate Tariff........................            1230      \1228\ 410               6           2,460
Category 1 Qualification Filings \1229\.........             630      \1230\ 210        \1231\15           3,150
Updated Analyses................................             600      \1233\ 200             250          50,000
                                                 ---------------------------------------------------------------
Category 2 \1232\ Totals........................  ..............  ..............  ..............          71,210
----------------------------------------------------------------------------------------------------------------

    Total Annual Hours for Collection: (Reporting + record retention 
(if appropriate) = 71,210 hours.
---------------------------------------------------------------------------

    \1228\ We expect responses to be staggered over the course of 
three years. Accordingly, the number of respondents (1230) has been 
divided by 3.
    \1229\ Category 1 sellers are power marketers and power 
producers that own or control 500 MW or less of generating capacity 
in aggregate and that are not affiliated with a public utility with 
a franchised service territory. In addition, Category 1 sellers must 
not own, operate or control transmission facilities, and must 
present no other vertical market power issues. There are 
approximately 630 Category 1 sellers.
    \1230\ To determine the number of responses, the number of 
respondents (630) has been divided by 3 because the Category 1 
filings will be submitted to the Commission on a staggered basis 
over the course of a three-year period. After the first three years, 
the number of responses will be zero.
    \1231\ This estimate reflects the limited scope of the filing 
required by Category 1 sellers, i.e., a filing explaining why the 
seller meets the Category 1 criteria and including a list of all 
generation assets owned or controlled by the seller and its 
affiliates grouped by balancing authority area.
    \1232\ Category 2 sellers are any sellers not in Category 1.
    \1233\ To determine the number of responses, the number of 
respondents (600) has been divided by 3 because the responses will 
be submitted to the Commission on a staggered basis over the course 
of a three year period.
---------------------------------------------------------------------------

    Information Collection Costs: The total annual cost for Initial 
Market Power Analyses is estimated to be $2,340,000. Total annual cost 
for market-based rate tariffs is projected to be $369,000 for the first 
year. Total annual cost for Category 1 Qualification Filings is 
projected to be $472,500.\1234\ Total annual cost for Updated Market 
Power Analyses Category 2 is projected to be $7,500,000. The hourly 
rate of $150 includes attorney fees, engineering consultation fees and 
administrative support. There are 2080 total work hours in a year. 
There are no filing fees associated with applications for market-based 
rate authority.
---------------------------------------------------------------------------

    \1234\ We note that Category 1 sellers will only be required to 
file on a single occasion Category 1 qualification filings whereas 
Category 2 sellers will file updated market power analyses every 
three years.
---------------------------------------------------------------------------

    Respondents (Market Power Analysis; MBR Tariff; Triennial Review): 
Businesses or other for profit.

Frequency of Responses

    Market Power Analyses: Occasionally; consistent with current 
practice, a market power analysis must be filed for each utility 
seeking market-based rate authority.
    Market-Based Rate Tariffs: Once, consistent with the requirement 
that all sellers file modifications to their existing tariffs in 
accordance with the provisions in Appendix C.
    Updated Market Power Analyses: Updated market power analysis filed 
every three years for Category 2 sellers seeking to retain market-based 
rate authority.

Necessity of the Information

    Market Power Analyses: Consistent with current practice, the market 
power analysis helps inform the Commission as to whether an entity 
seeking market-based rate authority lacks market power, and whether 
sales by that entity will be just and reasonable.
    Market-Based Rate Tariff: Market-based rate tariffs with standard 
provisions will improve the efficiency of the Commission in its 
analysis and determination of market-based rate authority. These will 
reduce document preparation time overall and provide utilities with the 
clearly defined expectations of the Commission.
    Updated Market Power Analyses: The updated market power analyses 
allow the Commission to monitor market-based rate authority to detect 
changes in market power or potential abuses of market power. The 
updated market power analysis permits the Commission to determine that 
continued market-based rate authority will still yield rates that are 
just and reasonable.
    Internal review: The Commission has conducted an internal review of 
the public reporting burden associated with the collection of 
information and assured itself, by means of internal review, that there 
is specific, objective support for this information burden estimate. 
Moreover, the Commission has reviewed the collections of information 
and has determined that these collections of information are necessary 
and conform to the Commission's plans, as described in this order, for 
the collection, efficient management, and use of the required 
information.\1235\
---------------------------------------------------------------------------

    \1235\ See 44 U.S.C. 3506(c).
---------------------------------------------------------------------------

    1123. Interested persons may obtain information on the reporting 
requirements by contacting: 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 or the Office of Information 
and Regulatory Affairs, Office of Management and Budget, Washington, DC 
20503 [Attention: Desk Officer for the Federal Energy Regulatory 
Commission].

VII. Environmental Analysis

    1124. 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.\1236\ The 
Commission concludes that neither an Environmental Assessment nor an 
Environmental Impact Statement is required for this Final Rule under 
Sec.  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 electric rate filings.\1237\
---------------------------------------------------------------------------

    \1236\ Order No. 486, Regulations Implementing the National 
Environmental Policy Act, 52 FR 47897 (Dec. 17, 1987), FERC Stats. & 
Regs. Preambles 1986-1990 ] 30,783 (1987).
    \1237\ 18 CFR 380.4(a)(15).
---------------------------------------------------------------------------

VIII. Regulatory Flexibility Act

    1125. The Regulatory Flexibility Act of 1980 (RFA) \1238\ generally 
requires a description and analysis of rules that will have significant 
economic impact on a substantial number of small entities.\1239\ The 
Final Rule will be

[[Page 40038]]

applicable to all public utilities seeking and currently possessing 
market-based rate authority. The Commission finds that the regulations 
adopted here should not have a significant impact on small businesses.
---------------------------------------------------------------------------

    \1238\ 5 U.S.C. 601-12.
    \1239\ The RFA definition of ``small entity'' refers to the 
definition provided in the Small Business Act, which defines a 
``small business concern'' as a business that is independently owned 
and operated and that is not dominant in its field of operation. 15 
U.S.C. 632. The Small Business Size Standards component of the North 
American Industry Classification System defines a small electric 
utility as one that, including its affiliates, is primarily engaged 
in the generation, transmission, and/or distribution of electric 
energy for sale and whose total electric output for the preceding 
fiscal year did not exceed 4 million MWh. 13 CFR 121.201 (section 
22, Utilities, North American Industry Classification System, 
NAICS).
---------------------------------------------------------------------------

    1126. The submission of a market power analysis is currently 
required of all entities seeking authority to sell at market-based 
rates, and the Final Rule does not expand which entities will be 
required to file these analyses. The Final Rule does not create a new 
reporting requirement. It does, however, expand the scope of the 
analysis that must be submitted for those entities that previously were 
exempted from preparing a generation market power analysis by virtue of 
18 CFR 35.27(a). The Commission is concerned that the continued use of 
the Sec.  35.27(a) exemption, in time, would encompass all market 
participants as all pre-July 9, 1996 generation is retired. 
Nevertheless, because the Commission allows a seller to make 
simplifying assumptions, where appropriate, and therefore to submit a 
streamlined analysis, the Commission believes that any additional 
burden imposed by the elimination of the Sec.  35.27(a) exemption will 
be minimal.
    1127. Standard tariff provisions will decrease document preparation 
by clearly defining the information sought by the Commission.
    1128. For certain sellers, the triennial review submissions that 
provide updated market power analyses are required for the retention of 
market-based rate authority. Category 2 utilities shall continue to 
submit this analysis, which poses no greater burden than that already 
in place. However, the regulations will result in fewer filings with 
the Commission after the next three years than currently required for 
qualified smaller (Category 1) utilities' retention of market-based 
rate authority. Thus, the Final Rule will be less burdensome 
economically and reduce the frequency of document preparation for 
market-based rate authority retention for qualified smaller utilities. 
The Commission concludes that this Final Rule will not have a 
significant economic impact on a substantial number of small entities.

IX. Document Availability

    1129. 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 FERC's Home Page (http://www.ferc.gov) and in FERC'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.
    1130. From FERC's Home Page on the Internet, this information is 
available on 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 the docket 
number excluding the last three digits of this document in the docket 
number field.
    1131. User assistance is available for eLibrary and the 
Commission's Web site during normal business hours from FERC Online 
Support at (202) 502-6652 (toll-free at 1-866-208-3676) or e-mail at 
ferconlinesupport@ferc.gov, or the Public Reference Room at (202) 502-

8371 Press 0, TTY (202) 502-8659. E-mail the Public Reference Room at 
public.referenceroom@ferc.gov.


X. Effective Date and Congressional Notification

    1132. These regulations are effective September 18, 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 in 18 CFR Part 35

    Electric power rates, Electric utilities, Reporting and 
recordkeeping requirements.

    By the Commission. Commissioner Moeller dissenting in part with 
a separate statement in Attachment A.
Kimberly D. Bose,
Secretary.

0
In consideration of the foregoing, the Commission amends part 35, 
Chapter I, Title 18, Code of Federal Regulations, as follows:
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. 7101-7352.


0
2. Sec.  35.27 is revised to read as follows:


Sec.  35.27  Authority of State commissions.

    Nothing in this part--
    (a) Shall be construed as preempting or affecting any jurisdiction 
a State commission or other State authority may have under applicable 
State and Federal law, or
    (b) Limits the authority of a State commission in accordance with 
State and Federal law to establish
    (1) Competitive procedures for the acquisition of electric energy, 
including demand-side management, purchased at wholesale, or
    (2) Non-discriminatory fees for the distribution of such electric 
energy to retail consumers for purposes established in accordance with 
State law.

0
3. Subpart H is revised to read as follows:
Subpart H--Wholesale Sales of Electric Energy, Capacity and Ancillary 
Services at Market-Based Rates
Sec.
35.36 Generally.
35.37 Market power analysis required.
35.38 Mitigation.
35.39 Affiliate restrictions.
35.40 Ancillary services.
35.41 Market behavior rules.
35.42 Change in status reporting requirement.
Appendix A to Subpart H Standard Screen Format
Appendix B to Subpart H Corporate Entities and Assets

Subpart H--Wholesale Sales of Electric Energy, Capacity and 
Ancillary Services at Market-Based Rates


Sec.  35.36  Generally.

    (a) For purposes of this subpart:
    (1) Seller means any person that has authorization to or seeks 
authorization to engage in sales for resale of electric energy, 
capacity or ancillary services at market-based rates under section 205 
of the Federal Power Act.
    (2) Category 1 Sellers means wholesale power marketers and 
wholesale power producers that own or control 500 MW or less of 
generation in aggregate per region; that do not own, operate or control 
transmission facilities other than limited equipment necessary to 
connect individual generating facilities to the transmission grid (or 
have been granted waiver of the requirements of Order No. 888, FERC 
Stats. & Regs. ] 31,036); that are not affiliated with anyone that 
owns, operates or controls transmission facilities in the same region 
as the seller's generation assets; that are not affiliated with a 
franchised public utility in the same region as the seller's generation 
assets; and that do not raise other vertical market power issues.

[[Page 40039]]

    (3) Category 2 Sellers means any Sellers not in Category 1.
    (4) Inputs to electric power production means intrastate natural 
gas transportation, intrastate natural gas storage or distribution 
facilities; sites for generation capacity development; sources of coal 
supplies and equipment for the transportation of coal supplies such as 
barges and rail cars.
    (5) Franchised public utility means a public utility with a 
franchised service obligation under State law.
    (6) Captive customers means any wholesale or retail electric energy 
customers served under cost-based regulation.
    (7) Market-regulated power sales affiliate means any power seller 
affiliate other than a franchised public utility, including a power 
marketer, exempt wholesale generator, qualifying facility or other 
power seller affiliate, whose power sales are regulated in whole or in 
part on a market-rate basis.
    (8) Market information means non-public information related to the 
electric energy and power business including, but not limited to, 
information regarding sales, cost of production, generator outages, 
generator heat rates, unconsummated transactions, or historical 
generator volumes. Market information includes information from either 
affiliates or non-affiliates.
    (b) The provisions of this subpart apply to all Sellers authorized, 
or seeking authorization, to make sales for resale of electric energy, 
capacity or ancillary services at market-based rates unless otherwise 
ordered by the Commission.


Sec.  35.37  Market power analysis required.

    (a) (1) In addition to other requirements in subparts A and B, a 
Seller must submit a market power analysis in the following 
circumstances: when seeking market-based rate authority; for Category 2 
Sellers, every three years, according to the schedule contained in 
Order No. 697, FERC Stats. & Regs. ] 31,252; or any other time the 
Commission directs a Seller to submit one. Failure to timely file an 
updated market power analysis will constitute a violation of Seller's 
market-based rate tariff.
    (2) When submitting a market power analysis, whether as part of an 
initial application or an update, a Seller must include an appendix of 
assets in the form provided in Appendix B of this subpart.
    (b) A market power analysis must address whether a Seller has 
horizontal and vertical market power.
    (c) (1) There will be a rebuttable presumption that a Seller lacks 
horizontal market power if it passes two indicative market power 
screens: a pivotal supplier analysis based on the annual peak demand of 
the relevant market, and a market share analysis applied on a seasonal 
basis. There will be a rebuttable presumption that a Seller possesses 
horizontal market power if it fails either screen.
    (2) Sellers and intervenors may also file alternative evidence to 
support or rebut the results of the indicative screens. Sellers may 
file such evidence at the time they file their indicative screens. 
Intervenors may file such evidence in response to a Seller's 
submissions.
    (3) If a Seller does not pass one or both screens, the Seller may 
rebut a presumption of horizontal market power by submitting a 
Delivered Price Test analysis. A Seller that does not rebut a 
presumption of horizontal market power or that concedes market power, 
is subject to mitigation, as described in Sec.  35.38.
    (4) When submitting a horizontal market power analysis, a Seller 
must use the form provided in Appendix A of this subpart and include 
all supporting materials referenced in the form.
    (d) To demonstrate a lack of vertical market power, a Seller that 
owns, operates or controls transmission facilities, or whose affiliates 
own, operate or control transmission facilities, must have on file with 
the Commission an Open Access Transmission Tariff, as described in 
Sec.  35.28; provided, however, that a Seller whose foreign 
affiliate(s) own, operate or control transmission facilities outside of 
the United States that can be used by competitors of the Seller to 
reach United States markets must demonstrate that such affiliate either 
has adopted and is implementing an Open Access Transmission Tariff as 
described in Sec.  35.28, or otherwise offers comparable, non-
discriminatory access to such transmission facilities.
    (e) To demonstrate a lack of vertical market power in wholesale 
energy markets through the affiliation, ownership or control of inputs 
to electric power production, such as the transportation or 
distribution of the inputs to electric power production, a Seller must 
provide the following information:
    (1) A description of its ownership or control of, or affiliation 
with an entity that owns or controls, intrastate natural gas 
transportation, intrastate natural gas storage or distribution 
facilities;
    (2) Sites for generation capacity development; and
    (3) Sources of coal supplies and the transportation of coal 
supplies such as barges and rail cars.
    (4) A Seller must ensure that this information is included in the 
record of each new application for market-based rates and each updated 
market power analysis. In addition, a Seller is required to make an 
affirmative statement that it has not erected barriers to entry into 
the relevant market and will not erect barriers to entry into the 
relevant market.
    (f) If the seller seeks to protect any portion of the application, 
or any attachment thereto, from public disclosure pursuant to Sec.  
388.112 of this chapter, the seller must include with its request for 
privileged treatment a proposed protective order under which the 
parties to the proceeding will be able to review any of the data, 
information, analysis or other documentation relied upon by the seller 
for which privileged treatment is sought. A seller must grant access to 
privileged data to any party that signs a protective order within 5 
days from the date that the party executes the protective order.


Sec.  35.38  Mitigation.

    (a) A Seller that has been found to have market power in generation 
or that is presumed to have horizontal market power by virtue of 
failing or foregoing the horizontal market power screens, as described 
in Sec.  35.37(c), may adopt the default mitigation detailed in 
paragraph (b) of this section or may propose mitigation tailored to its 
own particular circumstances to eliminate its ability to exercise 
market power. Mitigation will apply only to the market(s) in which the 
Seller is found, or presumed, to have market power.
    (b) Default mitigation consists of three distinct products:
    (1) Sales of power of one week or less priced at the Seller's 
incremental cost plus a 10 percent adder;
    (2) Sales of power of more than one week but less than one year 
priced at no higher than a cost-based ceiling reflecting the costs of 
the unit(s) expected to provide the service; and
    (3) New contracts filed for review under section 205 of the Federal 
Power Act for sales of power for one year or more priced at a rate not 
to exceed embedded cost of service.


Sec.  35.39  Affiliate restrictions.

    (a) General affiliate provisions. As a condition of obtaining and 
retaining market-based rate authority, the conditions provided in this 
section, including the restriction on affiliate sales of electric 
energy and all other

[[Page 40040]]

affiliate provisions, must be satisfied on an ongoing basis, unless 
otherwise authorized by Commission rule or order. Failure to satisfy 
these conditions will constitute a violation of the Seller's market-
based rate tariff.
    (b) Restriction on affiliate sales of electric energy. As a 
condition of obtaining and retaining market-based rate authority, no 
wholesale sale of electric energy may be made between a franchised 
public utility with captive customers and a market-regulated power 
sales affiliate without first receiving Commission authorization for 
the transaction under section 205 of the Federal Power Act. All 
authorizations to engage in affiliate wholesale sales of electric 
energy must be listed in a Seller's market-based rate tariff.
    (c) Separation of functions. (1) For the purpose of this paragraph, 
entities acting on behalf of and for the benefit of a franchised public 
utility with captive customers (such as entities controlling or 
marketing power from the electrical generation assets of the franchised 
public utility) are considered part of the franchised public utility. 
Entities acting on behalf of and for the benefit of the market-
regulated power sales affiliates of a franchised public utility with 
captive customers are considered part of the market-regulated power 
sales affiliates.
    (2) (i) To the maximum extent practical, the employees of a market-
regulated power sales affiliate must operate separately from the 
employees of any affiliated franchised public utility with captive 
customers.
    (ii) Franchised public utilities with captive customers are 
permitted to share support employees, and field and maintenance 
employees with their market-regulated power sales affiliates. 
Franchised public utilities with captive customers are also permitted 
to share senior officers and boards of directors with their market-
regulated power sales affiliates; provided, however, that the shared 
officers and boards of directors must not participate in directing, 
organizing or executing generation or market functions.
    (iii) Notwithstanding any other restrictions in this section, in 
emergency circumstances affecting system reliability, a market-
regulated power sales affiliate and a franchised public utility with 
captive customers may take steps necessary to keep the bulk power 
system in operation. A franchised public utility with captive customers 
or the market-regulated power sales affiliate must report to the 
Commission and disclose to the public on its Web site, each emergency 
that resulted in any deviation from the restrictions of section 35.39, 
within 24 hours of such deviation.
    (d) Information sharing. (1) Unless simultaneously disclosed to the 
public, market information may not be shared between a franchised 
public utility with captive customers and a market-regulated power 
sales affiliate if the sharing could be used to the detriment of 
captive customers.
    (2) Permissibly shared support employees, field and maintenance 
employees and senior officers and board of directors under Sec. Sec.  
35.39(c)(2)(ii) may have access to information covered by the 
prohibition of Sec.  35.39(d)(1), subject to the no-conduit provision 
in Sec.  35.39(g).
    (e) Non-power goods or services. (1) Unless otherwise permitted by 
Commission rule or order, sales of any non-power goods or services by a 
franchised public utility with captive customers, to a market-regulated 
power sales affiliate must be at the higher of cost or market price.
    (2) Unless otherwise permitted by Commission rule or order, sales 
of any non-power goods or services by a market-regulated power sales 
affiliate to an affiliated franchised public utility with captive 
customers may not be at a price above market.
    (f) Brokering of power. (1) Unless otherwise permitted by 
Commission rule or order, to the extent a market-regulated power sales 
affiliate seeks to broker power for an affiliated franchised public 
utility with captive customers:
    (i) The market-regulated power sales affiliate must offer the 
franchised public utility's power first;
    (ii) The arrangement between the market-regulated power sales 
affiliate and the franchised public utility must be non-exclusive; and
    (iii) The market-regulated power sales affiliate may not accept any 
fees in conjunction with any brokering services it performs for an 
affiliated franchised public utility.
    (2) Unless otherwise permitted by Commission rule or order, to the 
extent a franchised public utility with captive customers seeks to 
broker power for a market-regulated power sales affiliate:
    (i) The franchised public utility must charge the higher of its 
costs for the service or the market price for such services;
    (ii) The franchised public utility must market its own power first, 
and simultaneously make public (on the Internet) any market information 
shared with its affiliate during the brokering; and
    (iii) The franchised public utility must post on the Internet the 
actual brokering charges imposed.
    (g) No conduit provision. A franchised public utility with captive 
customers and a market-regulated power sales affiliate are prohibited 
from using anyone, including asset managers, as a conduit to circumvent 
the affiliate restrictions in Sec. Sec.  35.39(a) through (g).
    (h) Franchised utilities without captive customers. If necessary, 
any affiliate restrictions regarding separation of functions, power 
sales or non-power goods and services transactions, or brokering 
involving two or more franchised public utilities, one or more of whom 
has captive customers and one or more of whom does not have captive 
customers, will be imposed on a case-by-case basis.


Sec.  35.40  Ancillary services.

    A Seller may make sales of ancillary services at market-based rates 
only if it has been authorized by the Commission and only in specific 
geographic markets as the Commission has authorized.


Sec.  35.41  Market behavior rules.

    (a) Unit operation. Where a Seller participates in a Commission-
approved organized market, Seller must operate and schedule generating 
facilities, undertake maintenance, declare outages, and commit or 
otherwise bid supply in a manner that complies with the Commission-
approved rules and regulations of the applicable market. A Seller is 
not required to bid or supply electric energy or other electricity 
products unless such requirement is a part of a separate Commission-
approved tariff or is a requirement applicable to Seller through 
Seller's participation in a Commission-approved organized market.
    (b) Communications. A Seller must provide accurate and factual 
information and not submit false or misleading information, or omit 
material information, in any communication with the Commission, 
Commission-approved market monitors, Commission-approved regional 
transmission organizations, Commission-approved independent system 
operators, or jurisdictional transmission providers, unless Seller 
exercises due diligence to prevent such occurrences.
    (c) Price reporting. To the extent a Seller engages in reporting of 
transactions to publishers of electric or natural gas price indices, 
Seller must provide accurate and factual information, and not knowingly 
submit false or misleading information or omit material information to 
any such publisher, by reporting its transactions in a manner 
consistent with the procedures set forth in the Policy

[[Page 40041]]

Statement issued by the Commission in Docket No. PL03-3-000 and any 
clarifications thereto. Unless Seller has previously provided the 
Commission with a notification of its price reporting status, Seller 
must notify the Commission within 15 days of the effective date of this 
regulation or within 15 days of the date it begins making wholesale 
sales, whichever is earlier, whether it engages in such reporting of 
its transactions. Seller must update the notification within 15 days of 
any subsequent change in its transaction reporting status. In addition, 
Seller must adhere to such other standards and requirements for price 
reporting as the Commission may order.
    (d) Records retention. A Seller must retain, for a period of five 
years, all data and information upon which it billed the prices it 
charged for the electric energy or electric energy products it sold 
pursuant to Seller's market-based rate tariff, and the prices it 
reported for use in price indices.


Sec.  35.42  Change in status reporting requirement.

    (a) As a condition of obtaining and retaining market-based rate 
authority, a Seller must timely report to the Commission any change in 
status that would reflect a departure from the characteristics the 
Commission relied upon in granting market-based rate authority. A 
change in status includes, but is not limited to, the following:
    (1) Ownership or control of generation capacity that results in net 
increases of 100 MW or more, or of inputs to electric power production, 
or ownership, operation or control of transmission facilities, or
    (2) Affiliation with any entity not disclosed in the application 
for market-based rate authority that owns or controls generation 
facilities or inputs to electric power production, affiliation with any 
entity not disclosed in the application for market-based rate authority 
that owns, operates or controls transmission facilities, or affiliation 
with any entity that has a franchised service area.
    (b) Any change in status subject to paragraph (a) of this section 
must be filed no later than 30 days after the change in status occurs. 
Power sales contracts with future delivery are reportable 30 days after 
the physical delivery has begun. Failure to timely file a change in 
status report constitutes a tariff violation.
    (c) When submitting a change in status notification regarding a 
change that impacts the pertinent assets held by a Seller or its 
affiliates with market-based rate authorization, a Seller must include 
an appendix of assets in the form provided in Appendix B of this 
subpart.

[[Page 40042]]

Appendix A to Subpart H

                         Standard Screen Format
             [Data provided for Illustrative Purposes only]
------------------------------------------------------------------------
        Row               Generation             MW         Reference
------------------------------------------------------------------------
                    Part I--Pivotal Supplier Analysis
------------------------------------------------------------------------
                     Seller and Affiliate
                            Capacity

A.................  Installed Capacity....       19,500  Workpaper.
B.................  Long-Term Firm                  500  Workpaper.
                     Purchases.
C.................  Long-Term Firm Sales..       -1,000  Workpaper.
D.................  Imported Power........            0  Workpaper.

                    Non-Affiliate Capacity

E.................  Installed Capacity....        8,000  Workpaper.
F.................  Long-Term Firm                  500  Workpaper.
                     Purchases.
G.................  Long-Term Firm Sales..       -2,500  Workpaper.
H.................  Imported Power........        3,500  Workpaper.
I.................  Balancing Authority          -2,160  Workpaper.
                     Area Reserve
                     Requirement.
J.................  Amount of Line I             -2,160  Workpaper.
                     Attributable to
                     Seller, if any.
K.................  Total Uncommitted             9,840
                     Supply (SUM
                     A,B,C,D,E,F,G,I).

                             Load

L.................  Balancing Authority          18,000  Workpaper.
                     Area Annual Peak Load.
M.................  Average Daily Peak          -16,500  Workpaper.
                     Native Load in Peak
                     Month.
N.................  Amount of Line M            -16,500  Workpaper.
                     Attributable to
                     Seller, if any.
O.................  Wholesale Load (SUM           1,500
                     L,M).
P.................  Net Uncommitted Supply        8,340
                     (K-O).
Q.................  Seller's Uncommitted            340
                     Capacity (SUM
                     A,B,C,D,J,N).
------------------------------------------------------------------------
Result of Pivotal Supplier Screen (PPASSif
 Line Q < Line P) (Fail if Line Q > Line
 P).
------------------------------------------------------------------------



         Row                                 Q1  (MW)     Q2  (MW)     Q3  (MW)     Q4  (MW)       Reference
----------------------------------------------------------------------------------------------------------------
                                         Part II--Market Share Analysis
----------------------------------------------------------------------------------------------------------------
                      Seller and
                       Affiliate Capacity

A...................  Installed Capacity.       19,500       19,500       19,500       19,500  Workpaper.
B...................  Long-Term Firm               500          500          500          500  Workpaper.
                       Purchases.
C...................  Long-Term Firm            -1,000       -1,000       -1,000       -1,000  Workpaper.
                       Sales.
D...................  Seasonal Average          -4,000       -3,000         -800       -3,500  Workpaper.
                       Planned Outages.
E...................  Imported Power.....            0            0            0            0  Workpaper.

                      Capacity Deductions

F...................  Average Peak Native      -11,500      -10,000      -12,500      -11,500  Workpaper.
                       Load in the Season.
G...................  Amount of Line F         -11,500      -10,000      -12,500      -11,500  Workpaper.
                       Attributable to
                       Seller, if any.
H...................  Amount of Line F               0            0            0            0  Workpaper.
                       Attributable to
                       Others, if any.
I...................  Balancing Authority       -1,500       -1,320       -1,560       -1,500  Workpaper.
                       Area Reserve
                       Requirement.
J...................  Amount of Line I          -1,500       -1,320       -1,560       -1,500  Workpaper.
                       Attributable to
                       Seller, if any.
K...................  Amount of Line I               0            0            0            0  Workpaper.
                       Attributable to
                       Others, if any.

                      Non-Affiliate
                       Capacity

L...................  Installed Capacity.        8,000        8,000        8,000        8,000  Workpaper.
M...................  Long-Term Firm               500          500          500          500  Workpaper.
                       Purchases.
N...................  Long-Term Firm            -2,500       -2,500       -2,500       -2,500  Workpaper.
                       Sales.
O...................  Local Seasonal              -800         -200         -300         -400  Workpaper.
                       Average Planned
                       Outages.
P...................  Uncommitted                5,000        4,500        3,500        4,000  Workpaper.
                       Capacity Imports.

                      Supply Calculation

Q...................  Total Competing           10,200       10,300        9,200        9,600
                       Supply (SUM
                       L,M,N,O,P,H,K).
R...................  Seller's                   2,000        4,680        4,140        2,500
                       Uncommitted
                       Capacity (SUM
                       A,B,C,D,E,G,J).
S...................  Total Seasonal            12,200       14,980       13,340       12,100
                       Uncommitted
                       Capacity (SUM Q,R).
T...................  Seller's Market           16.39%       31.24%       31.03%       20.66%
                       Share (R/S).
                      Results (Pass if <           PASS         FAIL         FAIL         FAIL
                       20%) (Fail if >=
                       20%).
----------------------------------------------------------------------------------------------------------------

?>
[[Page 40043]]

Appendix B to Subpart H

    This is an example of the required appendix listing the filing 
entity and all its energy affiliates and their associated assets 
which should be submitted with all market-based rate filings.

                                                                        Market-Based Rate Authority and Generation Assets
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                                                                       Location
                                Docket No. where                                                                         ------------------------------------                   Nameplate and/or
 Filing entity and its  energy    MBR authority    Generation name      Owned by        Controlled by     Date  control                        Geographic      In-service date       seasonal
          affiliates               was granted                                                             transferred        Balancing        region (per                           rating
                                                                                                                           authority area      Appendix D)
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
ABC Corp......................  ER05-23X-000....  ABC falls plant   ABC Corp........  ABC Corp........  NA*.............  ABC balancing     Central.........  8/12/1981.......  153.5 MW
                                                   1.                                                             authority area.                                       (seasonal).
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
xyz Inc.......................  ER94-79XX-000...  NA..............  NA..............  NA..............  NA..............  NA..............  NA..............  NA..............  NA.
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
RST LLC.......................  ER01-2XX5-000...  Green CoGen.....  WWW Corp........  RST LLC.........  5/23/2005.......  New York ISO....  Northeast.......  12/20/2003......  2000 MW
                                                                                                                                                                                 (nameplate).
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Sample Co.....................  ER03-XX45-000...  Sample Co. 3....  Sample Co.......  YYY Corp........  2/1/1982........  Sample Co.        Southwest.......  5/13/1973.......  10 MW
                                                                                                                           balancing                                             (seasonal).
                                                                                                                           authority.
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
*If an entity has no assets or the field is not applicable please indicate so by inputting (NA).


                           Electric Transmission Assets and/or Natural Gas Intrastate Pipelines and/or Gas Storage Facilities
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                                                   Location
                                                                                                      ----------------------------------
Filing entity and its  energy   Asset name and       Owned by        Controlled by     Date  control                       Geographic          Size
          affiliates                  use                                               transferred       Balancing       region (per
                                                                                                        authority area    Appendix D)
--------------------------------------------------------------------------------------------------------------------------------------------------------
ABC Corp.....................  CBA Line, used    ABC Corp........  ABC Corp........  NA*.............  New York ISO...  Northeast......  approximately
                                to interconnect                                                                                           five-mile, 500
                                Green Cogen to                                                                                            kV line.
                                New York ISO
                                transmission
                                system.
--------------------------------------------------------------------------------------------------------------------------------------------------------
Etc. LP......................  Nowhere           Etc. LP.........  Etc. LP.........  NA..............  ABC balancing    Central........  approximately
                                Pipeline, used                                                          authority area.                   14 miles of
                                to connect                                                                                                natural gas
                                Storage LLC's--                                                                                           pipeline and
                                Longway                                                                                                   related
                                Pipeline to ABC                                                                                           equipment with
                                falls plant                                                                                               50 MMcf/d
                                1.                                                                                               capacity.
--------------------------------------------------------------------------------------------------------------------------------------------------------
*If the field is not applicable please indicate so by inputting (NA).


    Note: The following appendices will not be published in the Code 
of Federal Regulations.

Appendix C to the Final Rule

Required Provisions of the Market-Based Rate Tariff

Compliance With Commission Regulations

    Seller shall comply with the provisions of 18 CFR Part 35, 
Subpart H, as applicable, and with any conditions the Commission 
imposes in its orders concerning seller's market-based rate 
authority, including orders in which the Commission authorizes 
seller to engage in affiliate sales under this tariff or otherwise 
restricts or limits the seller's market-based rate authority. 
Failure to comply with the applicable provisions of 18 CFR Part 35, 
Subpart H, and with any orders of the Commission concerning seller's 
market-based rate authority, will constitute a violation of this 
tariff.

Limitations and Exemptions Regarding Market-Based Rate Authority

    [Seller should list all limitations (including markets where 
seller does not have market-based rate authority) on its market-
based rate authority and any exemptions from or waivers granted of 
Commission regulations and include relevant cites to Commission 
orders].

Include All of the Following Provisions That Are Applicable

Mitigated Sales

    Sales of energy and capacity are permissible under this tariff 
in all balancing authority areas where the Seller has been granted 
market-based rate authority. Sales of energy and capacity under this 
tariff are also permissible at the metered boundary between the 
Seller's mitigated balancing authority area and a balancing 
authority area where the Seller has been granted market-based rate 
authority provided: (i) Legal title of the power sold transfers at 
the metered boundary of the balancing authority area; (ii) any power 
sold hereunder is not intended to serve load in the seller's 
mitigated market; and (iii) no affiliate of the mitigated seller 
will sell the same power back into the mitigated seller's mitigated 
market. Seller must retain, for a period of five years from the date 
of the sale, all data and information related to the sale that 
demonstrates compliance with items (i), (ii) and (iii) above.

Ancillary Services

RTO/ISO Specific--Include All Services the Seller Is Offering

    PJM: Seller offers regulation and frequency response service, 
energy imbalance service, and operating reserve service (which 
includes spinning, 10-minute, and 30-minute reserves) for sale into 
the market administered by PJM Interconnection, L.L.C. (``PJM'') 
and, where the PJM Open Access Transmission Tariff permits, the 
self-supply of these services to purchasers for a bilateral

[[Page 40044]]

sale that is used to satisfy the ancillary services requirements of 
the PJM Office of Interconnection.
    New York: Seller offers regulation and frequency response 
service, and operating reserve service (which include 10-minute non-
synchronous, 30-minute operating reserves, 10-minute spinning 
reserves, and 10-minute non-spinning reserves) for sale to 
purchasers in the market administered by the New York Independent 
System Operator, Inc.
    New England: Seller offers regulation and frequency response 
service (automatic generator control), operating reserve service 
(which includes 10-minute spinning reserve, 10-minute non-spinning 
reserve, and 30-minute operating reserve service) to purchasers 
within the markets administered by the ISO New England, Inc.
    California: Seller offers regulation service, spinning reserve 
service, and non-spinning reserve service to the California 
Independent System Operator Corporation (``CAISO'') and to others 
that are self-supplying ancillary services to the CAISO.

Third Party Provider

    Third-party ancillary services [include all of the following 
that the seller is offering: Regulation Service, Energy Imbalance 
Service, Spinning Reserves, and Supplemental Reserves]. Sales will 
not include the following: (1) Sales to an RTO or an ISO, i.e., 
where that entity has no ability to self-supply ancillary services 
but instead depends on third parties; (2) sales to a traditional, 
franchised public utility affiliated with the third-party supplier, 
or sales where the underlying transmission service is on the system 
of the public utility affiliated with the third-party supplier; and 
(3) sales to a public utility that is purchasing ancillary services 
to satisfy its own open access transmission tariff requirements to 
offer ancillary services to its own customers.

Appendix D to the Final Rule

Regions and Schedule for Regional Market Power Update Process

    The six regions are combinations of NERC regions; RTOs and ISOs 
and are depicted in the map that follows.
BILLING CODE 6717-01-P
[GRAPHIC] [TIFF OMITTED] TR20JY07.000

BILLING CODE 6717-01-C

[[Page 40045]]



                                      Regional Market Power Update Schedule
----------------------------------------------------------------------------------------------------------------

----------------------------------------------------------------------------------------------------------------
         Study period           Filing period (anytime                  Entities required to file
                                        between)
----------------------------------------------------------------------------------------------------------------
2006.........................  December 1-30, 2007.....  Northeast Transmission    .............................
                                                          Operators.
2006.........................  June 1-30, 2008.........  Southeast Transmission    All others in Northeast that
                                                          Operators.                did not file in December
                                                                                    including all power
                                                                                    marketers that sold in the
                                                                                    Northeast.
2006.........................  December 1-30, 2008.....  ........................  All others in Southeast that
                                                                                    did not file in June
                                                                                    including all power
                                                                                    marketers that sold in the
                                                                                    Southeast and have not
                                                                                    already been found to be
                                                                                    Category 1 sellers.
2007.........................  December 1-30, 2008.....  Central Transmission      .............................
                                                          Operators.
2007.........................  June 1-30, 2009.........  SPP Transmission          All others in Central that
                                                          Operators.                did not file in December
                                                                                    including all power
                                                                                    marketers that sold in the
                                                                                    Central and have not already
                                                                                    been found to be Category 1
                                                                                    sellers.
2007.........................  December 1-30, 2009.....  ........................  All others in SPP that did
                                                                                    not file in June including
                                                                                    all power marketers that
                                                                                    sold in SPP and have not
                                                                                    already been found to be
                                                                                    Category 1 sellers.
2008.........................  December 1-30, 2009.....  Southwest Transmission    .............................
                                                          Operators.
2008.........................  June 1-30, 2010.........  Northwest Transmission    All others in Southwest that
                                                          Operators.                did not file in December
                                                                                    including all power
                                                                                    marketers that sold in the
                                                                                    Southwest and have not
                                                                                    already been found to be
                                                                                    Category 1 sellers.
2008.........................  December 1-30, 2010.....  ........................  All others in Northwest that
                                                                                    did not file in June
                                                                                    including all power
                                                                                    marketers that sold in the
                                                                                    Northwest and have not
                                                                                    already been found to be
                                                                                    Category 1 sellers.
2009.........................  December 1-30, 2010.....  Northeast Transmission    .............................
                                                          Operators.
----------------------------------------------------------------------------------------------------------------
All Category 1 sellers should be identified by the Commission prior to the subsequent filing periods. Only
 Category 2 sellers will continue to file updated market power analyses according to the repeating schedule
 below.
----------------------------------------------------------------------------------------------------------------
2009.........................  June 1-30, 2011.........  Southeast Transmission    Others in Northeast that did
                                                          Operators.                not file in December and
                                                                                    have not been found to be
                                                                                    Category 1 sellers.
2009.........................  December 1-30, 2011.....  ........................  Others in Southeast that did
                                                                                    not file in June and have
                                                                                    not been found to be
                                                                                    Category 1 sellers.
2010.........................  December 1-30, 2011.....  Central Transmission      .............................
                                                          Operators.
2010.........................  June 1-30, 2012.........  SPP Transmission          Others in Central that did
                                                          Operators.                not file in December and
                                                                                    have not been found to be
                                                                                    Category 1 sellers.
2010.........................  December 1-30, 2012.....  ........................  Others in SPP that did not
                                                                                    file in June and have not
                                                                                    been found to be Category 1
                                                                                    sellers.
2011.........................  December 1-30, 2012.....  Southwest Transmission    .............................
                                                          Operators.
2011.........................  June 1-30, 2013.........  Northwest Transmission    Others in Southwest that did
                                                          Operators.                not file in December and
                                                                                    have not been found to be
                                                                                    Category 1 sellers.
2011.........................  December 1-30, 2013.....  ........................  Others in Northwest that did
                                                                                    not file in June and have
                                                                                    not been found to be
                                                                                    Category 1 sellers.
----------------------------------------------------------------------------------------------------------------
This review cycle will be repeated in subsequent years.

Appendix E to the Final Rule

List of Commenters and Acronyms

Allegheny Energy Supply Co. and Allegheny Power--Allegheny Energy 
Companies
Alliance for Cooperative Energy Services Power Marketing LLC--
Alliance Power Marketing
Ameren Services Co., Inc.--Ameren
AARP--AARP
American Public Power Association/Transmission Access Policy Study 
Group--APPA/TPAS
American Wind Energy Association--AWEA
Avista Corp.--Avista
Board of Water, Light and Sinking Fund Commissioners of the City of 
Dalton, Georgia--Dalton Utilities
California Electricity Oversight Board--California Board
California Independent System Operator Corp.--CAISO
California Public Utilities Commission--California Commission
Coalition of Midwest Transmission Customers, PJM Industrial Customer 
Coalition, NEPOOL Industrial Customer Coalition, Industrial Energy 
Users of Ohio, Southeast Electricity Consumers Association, 
Southwest Industrial Customer Coalition--Industrial Customers
Cogentrix Energy, Inc. and Goldman Sachs Group--Cogentrix/Goldman
Constellation Energy Group, Inc.--Constellation
Consumers Energy Co.--Consumers
Dominion Resources Services, Inc.--Dominion
Duke Energy Corp.--Duke
Duquesne Power, LLC; Duquesne Light Company; Duquesne Keystone, LLC; 
Duquesne Conemaugh, LLC; and Monmouth Energy, Inc.--Duquesne 
Companies
E.ON U.S. LLC--E.ON U.S.
Edison Electric Institute--EEI
ElectriCities of North Carolina, Inc. and Piedmont Municipal Power 
Agency--Carolina Agencies
Electricity Consumers Resource Council--ELCON
El Paso E&P Co. L.P.--El Paso E&P
Electric Power Supply Association--EPSA
Entergy Services, Inc.--Entergy
FirstEnergy Service Co.--FirstEnergy
Florida Power & Light Company and FPL Energy, LLC--FP&L
Indianapolis Power & Light Co.--Indianapolis P&L
ISO New England Inc.--ISO-NE
Joe Pace, PhD--Dr. Pace
Mark B. Lively--Mr. Lively

[[Page 40046]]

Merrill Lynch Commodities Inc., J.P. Morgan Ventures Energy Corp. 
and Bear Energy--Financial Companies
MidAmerican Energy Co. and PacifiCorp--MidAmerican
Midwest Energy, Inc.--Midwest Energy
Mirant Corp.--Mirant
Montana Consumer Counsel--Montana Counsel
Morgan Stanley Capital Group Inc.--Morgan Stanley
National Association of State Utility Consumer Advocates--NASUCA
National Rural Electric Cooperative Association--NRECA
New Jersey Board of Public Utilities--New Jersey Board
New Mexico Office of Attorney General, Colorado Office of Consumer 
Counsel, Utah Committee of Consumer Services, Public Citizen, Public 
Utility Law Project of New York, Rhode Island Office of Attorney 
General, and Rhode Island Division of Public Utilities and 
Carriers--State AGs and Advocates
New York Independent System Operator, Inc.--NYISO
New York State Public Service Commission--New York Commission
Newfoundland and Labrador Hydro--NL Hydro
Newmont Mining Corp.--Newmont
NiSource Inc.--NiSource
NRG Energy, Inc.--NRG
Oregon Public Utilities Commission--Oregon Commission
Ormet Power Marketing--Ormet
Pacific Gas & Electric Co.--PG&E
Piedmont Municipal Power Agency and ElectriCities of North 
Carolina--Carolina Agencies
Pinnacle West Companies--Pinnacle
Powerex Corp.--Powerex
PPL Companies--PPL
PPM Energy, Inc.--PPM
Progress Energy, Inc.--Progress Energy
Public Service Electric and Gas Company, PSEG Power LLC and PSEG 
Energy Resources & Trade LLC--PSEG Companies
Public Service Co. of New Mexico/Tuscon Electric Power Company--PNM/
Tuscon
Public Works Commission for the City of Fayetteville, North 
Carolina--Fayetteville
Puget Sound Energy, Inc.--Puget
Reliant Energy, Inc.--Reliant
Richard Blumenthal, Attorney General for the State of Connecticut 
and the People of the State of Illinois, by and through the Illinois 
Attorney General, Lisa Madigan--Attorneys General of Connecticut and 
Illinois
Romkaew Broehm, PhD. and Peter Fox-Penner--Drs. Broehm and Fox-
Penner
Sempra Energy--Sempra
Southern California Edison Co.--SoCal Edison
Southern Company Services, Inc.--Southern
Southwest Industrial Customer Coalition--Southwest Coalition
Suez Energy North America, Inc. and Chevron USA Inc.--Suez/Chevron
Towns of Black Creek, NC; Dallas, NC; Forest City, NC; Lucama, NC; 
Sharpsburg, NC; Stantonsburg, NC; and Waynesville, NC--NC Towns
Transmission Dependent Utility Systems--TDU Systems
TXU Portfolio Management Co. LP--TXU Wholesale
Westar Energy, Inc. and Kansas Gas and Electric Co.--Westar
Williams Power Co., Inc.--Williams
Wisconsin Electric Power Co.--Wisconsin Electric
Xcel Energy Services Inc.--Xcel

    Note: The following attachment will not appear in the Code of 
Federal Regulations

Attachment A to the Final Rule

    MOELLER, Commissioner, dissenting in part: I find persuasive the 
arguments raised by commenters \1240\ that a limited grandfathering 
provision for the ``1996 exemption'' \1241\ is warranted, to avoid 
modifying the understanding that certain generators relied upon to 
finance and construct new generation. It is my position that, with 
respect to sales from capacity for which construction commenced on 
or after July 9, 1996, but before the effective date of this Final 
Rule, any public utility that has authority to engage in market-
based rate sales should not be required to demonstrate a lack of 
market power in generation consistent with the terms of the 
exemption. That is, any public utility that qualified and received a 
1996 exemption should retain its exemption from filing a generation 
market power analysis (now termed horizontal market power analysis). 
However, any increase in such capacity after the effective date of 
this Final Rule would terminate the exemption.
---------------------------------------------------------------------------

    \1240\ Such commenters include EPSA, Mirant and Constellation.
    \1241\ 18 CFR 35.27(a) (2006), which states ``Notwithstanding 
any other requirements, any public utility seeking authorization to 
engage in sales for resale of electric energy at market-based rates 
shall not be required to demonstrate any lack of market power in 
generation with respect to sales from capacity for which 
construction has commenced on or after July 9, 1996.''
---------------------------------------------------------------------------

    As I have stated previously, I am interested in providing 
regulatory certainty, and promoting infrastructure investment and 
independent power production. A limited grandfathering of the 1996 
exemption would, on one hand, allow entities to continue to preserve 
the bargain they received when they relied on the exemption and, on 
the other hand, support the majority's reasons for revoking the 
exemption for all generators.
    Also, my understanding is that very few entities would be 
eligible for this limited grandfathering; even without the 
grandfathering, they would probably be classified as ``Category 1 
sellers.'' \1242\ Moreover, this exemption neither precludes any 
entity from presenting evidence to the Commission, nor disallows the 
Commission of its own accord, to investigate an allegation of market 
power abuse by an exempt generator. This should allay any fears that 
these smaller entities will be able to exercise generation market 
power.\1243\
---------------------------------------------------------------------------

    \1242\ ``The sellers that have taken advantage of the exemption 
will largely qualify as Category 1 sellers, and thus will be 
unaffected to the extent that they will not be required to file a 
regularly scheduled updated market power analysis.'' Final Rule at P 
321.
    \1243\ In defending our decision to create Category 1 sellers, 
the majority observes that no commenter has submitted compelling 
evidence that Category 1 sellers have unmitigated market power. 
Final Rule at P 334.
---------------------------------------------------------------------------

Philip D. Moeller

Commissioner.

 [FR Doc. E7-13675 Filed 7-19-07; 8:45 am]

BILLING CODE 6717-01-P
