

[Federal Register: July 2, 2007 (Volume 72, Number 126)]
[Proposed Rules]               
[Page 36275-36298]
From the Federal Register Online via GPO Access [wais.access.gpo.gov]
[DOCID:fr02jy07-19]                         


[[Page 36275]]

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Part V





Department of Energy





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Federal Energy Regulatory Commission



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18 CFR Part 35



Wholesale Competition in Regions With Organized Electric Markets; 
Proposed Rule


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DEPARTMENT OF ENERGY

Federal Energy Regulatory Commission

18 CFR Part 35

[Docket Nos. RM07-19-000 and AD07-7-000]

 
Wholesale Competition in Regions With Organized Electric Markets

June 22, 2007.
AGENCY: Federal Energy Regulatory Commission, DOE.

ACTION: Advance notice of proposed rulemaking.

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SUMMARY: The Federal Energy Regulatory Commission (Commission) is 
issuing an Advance Notice of Proposed Rulemaking (ANOPR) with regard to 
potential reforms to improve the operation of organized wholesale 
electric markets. The Commission invites all interested persons to 
submit comments in response to specific questions.

DATES: Comments on this ANOPR are due on August 16, 2007.

ADDRESSES: You may submit comments identified by Docket Nos. RM07-19-
000 and AD07-7-000 by one of the following methods:
     Agency Web Site: http://www.ferc.gov. Follow the 

instructions for submitting comments via the eFiling link found in the 
Comment Procedures section of the ANOPR.
     Mail: Commenters unable to file comments electronically 
must mail or hand deliver an original and 14 copies of their comments 
to the Federal Energy Regulatory Commission, Secretary of the 
Commission, 888 First Street, NE., Washington, DC 20426. Please refer 
to the Comment Procedures section of the ANOPR for additional 
information on how to file paper comments.

FOR FURTHER INF0RMATION CONTACT:
David Kathan (Technical Information), Office of Energy Markets and 
Reliability, Federal Energy Regulatory Commission, 888 First Street, 
NE., Washington, DC 20426, David.Kathan@ferc.gov, (202) 502-6404.
Elizabeth Rylander (Legal Information), Office of the General Counsel, 
Federal Energy Regulatory Commission, 888 First Street, NE., 
Washington, DC 20426, Elizabeth.Rylander@ferc.gov, (202) 502-8466.

SUPPLEMENTARY INFORMATION:


                                                              Paragraph
                                                               numbers

I. Introduction............................................            1
II. Background.............................................            4
    A. Brief History.......................................           14
    B. Competition Issues and Commission Actions...........           25
    C. Issues Addressed in the ANOPR.......................           30
III. Demand Response and Pricing During Power Shortages in            34
 Organized Markets.........................................
    A. Importance of Demand Response to Competition in RTO/           36
     ISO Areas.............................................
    B. Prior Commission Actions To Address Demand Response.           41
    C. Remaining Problems with Demand Response in Organized           47
     Markets...............................................
    D. Proposed Commission Actions To Improve Demand                  57
     Response and Market Pricing During a Power Shortage...
IV. Long-Term Power Contracting in Organized Markets.......           83
    A. Importance of Long-Term Power Contracts and Factors            84
     Affecting Contracting Decisions by Buyers and Sellers.
    B. Commission Actions To Support Long-Term Power                  88
     Contracts.............................................
    C. Proposed Commission Actions To Facilitate Long-Term            92
     Power Contracting.....................................
V. Market Monitoring Policies..............................           95
    A. History of Market Monitoring........................           98
    B. Independence and Function...........................          108
    C. Information Sharing.................................          122
    D. Pro Forma Tariff Section............................          131
    E. Conclusion..........................................          132
VI. Responsiveness of RTOS and ISOS........................          133
    A. The Challenge of Improving RTO and ISO                        134
     Responsiveness to Stakeholders........................
    B. Prior Commission Actions Regarding RTO and ISO                140
     Responsiveness........................................
    C. Proposed Commission Action To Improve RTO and ISO             146
     Responsiveness........................................
VII. Additional Questions..................................          164
VIII. Comment Procedures...................................          166
IX. Document Availability..................................          170


I. Introduction

    1. The Federal Energy Regulatory Commission (Commission) is 
considering potential reforms to improve the operation of organized 
wholesale electric markets.\1\ In response to issues raised by various 
market participants and industry observers about improvements to 
enhance wholesale electric markets, the Commission held two 
conferences, on February 27, 2007 and May 8, 2007, to learn more about 
these issues. The first dealt with all wholesale power markets while 
the second focused on organized RTO/ISO markets. Based on the comments 
received at these two conferences, the Commission identified four 
specific and narrow issues, as described below, that are not already 
being fully addressed by the Commission in other proceedings and that 
may be appropriate to address in a generic proceeding.
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    \1\ Organized market regions are areas of the country in which a 
regional transmission organization (RTO) or independent system 
operator (ISO) operates day-ahead and/or real-time energy markets.
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    2. These issues are: (1) The role of demand response in organized 
markets, including greater reliance on market prices to elicit demand 
reductions during power shortages; (2) increasing opportunities for 
long-term power contracting; (3) strengthening market monitoring; and 
(4) the responsiveness of RTOs and ISOs to customers and other 
stakeholders. This Advance Notice of Proposed Rulemaking (ANOPR) 
identifies specific concerns in these four areas and presents the 
Commission's preliminary views on proposed reforms.\2\ The Commission 
seeks

[[Page 36277]]

comments on the proposed reforms. After receiving and considering these 
comments, the Commission will determine whether to issue a Notice of 
Proposed Rulemaking (NOPR) and the scope of the proposed rule, if a 
NOPR is warranted.
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    \2\ Throughout this document, the term ``propose'' is used as a 
short form of stating that it is the Commission's preliminary view 
that the proposal that follows may be a reasonable way to achieve a 
regulatory objective, and that the Commission requests comments on 
the proposal and on alternative recommendations for achieving the 
objective.
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    3. Finally, the actions proposed here are intended to complement 
other Commission actions, discussed further below, intended to improve 
the operation of wholesale competition in regions with and without RTOs 
and ISOs and their organized markets. There are opportunities to 
improve the operation of wholesale markets in both types of regions. 
Many of the Commission's prior actions--such as Order No. 890 \3\--
apply to both types of regions, while others by their nature apply only 
to RTO/ISO regions, such as assuring load-serving entities (LSEs) of 
long-term transmission rights in regions with locational marginal 
pricing and congestion hedges. The issues being explored in this 
proceeding are discrete and apply to regions with organized spot 
markets, market monitors, and an RTO or ISO. The actions considered 
address concerns that numerous market participants and many of our 
state colleagues have raised in this proceeding and elsewhere. The 
Commission is not seeking to fundamentally redesign organized markets 
or to appropriate jurisdiction from our state colleagues. Our goal is 
to make incremental improvements to the operation of organized markets 
without undoing or upsetting the significant efforts that have already 
been made in providing demonstrable benefits to wholesale customers. In 
particular, we acknowledge and commend the ISOs and RTOs and their 
respective transmission owners and stakeholders for their work over the 
past several years in fulfilling the Commission's policies supporting 
wholesale competition and non-discriminatory access to transmission.
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    \3\ Preventing Undue Discrimination and Preference in 
Transmission Service, Order No. 890, 72 FR 12,266 (Feb. 16, 2007), 
FERC Stats. & Regs. ] 31,241 (2007), reh'g pending (Reform of the 
Open Access Transmission Tariff (OATT) rules or OATT Reform).
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II. Background

    4. National policy for many years has been, and continues to be, to 
foster competition in wholesale power markets. As the third major 
federal law enacted in the last 30 years to embrace wholesale 
competition, the Energy Policy Act of 2005 (EPAct 2005) \4\ 
strengthened the legal framework for continuing wholesale competition 
as federal policy for this country.
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    \4\ Pub. L. No. 109-58, 119 Stat. 594 (2005).
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    5. The Commission's core responsibility is to ``guard the consumer 
from exploitation by non-competitive electric power companies.'' \5\ 
The Commission has always used two general approaches to meet this 
responsibility--regulation and competition. The first was the primary 
approach for most of the last century and remains the primary approach 
for wholesale transmission service, and the second has been the primary 
approach in recent years for wholesale generation service.
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    \5\ National Association for the Advancement of Colored People 
v. FPC, 520 F.2d 432, 438 (D.C. Cir. 1975), aff'd, 425 U.S. 662 
(1976).
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    6. The Commission has never relied exclusively on competition to 
assure just and reasonable rates and has never withdrawn from 
regulation of wholesale electric markets. Rather, the Commission has 
shifted the balance of the two approaches over time as circumstances 
changed. Advances in technology, exhaustion of economies of scale in 
most electric generation, and new federal and state laws have changed 
our views of the right mix of these two approaches. Our goal has always 
been to find the best possible mix of regulation and competition to 
protect consumers from the exercise of monopoly power.
    7. In each major energy bill over the last few decades, Congress 
has acted to open up the wholesale electric power market by 
facilitating entry of new generators to compete with traditional 
utilities. The Commission has acted quickly and strongly over the years 
to implement this national policy.
    8. Congress has not deregulated the wholesale electric power 
business, however, and the Commission has not done so by regulation. To 
the contrary, the Commission has issued many new regulations and orders 
designed to foster competition nationally and to support competitive 
markets in specific regions. Because the United States does not have a 
national electric power market, our approach to implementing 
competition has been to recognize and foster the development of 
regional markets.
    9. There are significant differences among the regional wholesale 
power markets. There are differences in industry structure, differences 
in the mix of ownership (such as investor-owned, cooperatively-owned, 
and publicly-owned utilities), differences in the mix of fuels and 
energy sources for electric generation, and differences in population 
densities and weather patterns, to name a few. Some regions pursue 
wholesale competition exclusively by relying on direct bilateral 
contracting between sellers and buyers, and others employ a mix of 
bilateral contracting with organized spot markets and other markets to 
increase opportunities for the sale or purchase of electric power. In 
regions with organized spot markets, the markets are administered by an 
RTO or ISO, which themselves have differences regarding such matters as 
market design, transmission responsibilities, and decision-making 
procedures. The Commission's approach to supporting wholesale 
competition is to recognize and respect these differences in market 
structure and other differences across the various regions.
    10. Wholesale competition can serve customers well in all regions, 
including RTO and ISO regions with organized markets and regions 
without such organizations and markets. There are strengths and 
weaknesses to the approach taken by each, and wholesale competition 
faces challenges in both areas.
    11. The best way to address these challenges may differ among the 
regions, however. For example, in all regions the cost of the fuels 
used for electric generation has increased in recent years, as it has 
throughout the world. Those regions of the United States that depend on 
natural gas for electric generation have felt this the most. 
Competitive spot markets reflect these cost changes quickly in market 
prices, while longer-term fixed price bilateral contracts or cost-of-
service regulation may reflect cost increases or decreases more 
gradually in the wholesale price. Wholesale customers in all regions 
want better long-term contracting opportunities. All regions face the 
problem that retail customers are often unaware of supply shortages and 
continue their normal consumption even on days when supplies are tight 
and wholesale prices are high. Allocating the costs of a major new 
regional transmission facility fairly is a challenge faced by every 
region.
    12. Regions with an RTO or ISO may be better able than other 
regions to address some of these issues, but they may also face more 
difficult challenges. For example, much of the recent dissatisfaction 
with organized competitive markets appears to be directly linked to 
rising natural gas prices.
    13. National policy is to promote wholesale competition in all 
regions, and customers now are calling especially for actions to 
improve the operation of wholesale competitive

[[Page 36278]]

markets in the organized market regions. Hence, the focus of this ANOPR 
is not whether wholesale competition is the correct federal policy; the 
focus is on further improving the operation of wholesale competitive 
markets in organized market regions.\6\ The Commission seeks comment on 
proposed reforms to improve the operation of wholesale markets in these 
regions.
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    \6\ There are organized markets in the following RTOs and ISOs: 
PJM Interconnection, L.L.C. (PJM), New York Independent System 
Operator, Inc. (NYISO), Midwest Independent Transmission System 
Operator, Inc. (Midwest ISO), ISO New England, Inc. (ISO-NE), 
California Independent Service Operator Corp. (CAISO), Southwest 
Power Pool, Inc. (SPP), and the Electric Reliability Council of 
Texas (ERCOT).
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A. Brief History

    14. Numerous federal and state legislative and regulatory 
activities have supported competition in the U.S. electric industry 
over the last three decades. Congress enacted the Public Utility 
Regulatory Policies Act of 1978 (PURPA) \7\ as a response to the energy 
crises of the 1970s. PURPA required electric utilities to interconnect 
with, and offer to purchase power from, qualifying cogeneration and 
small power production facilities at avoided cost rates set by state 
regulatory authorities. It gave the Commission limited authority to 
order wholesale transmission on a case-by-case basis, upon application 
by an eligible entity. A consequence of PURPA was the emergence of a 
new class of power generators that were independent of traditional 
utilities.
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    \7\ Pub. L. No. 95-617, 92 Stat. 3117 (codified in scattered 
sections of 15, 16, 26, 30, 42, and 43 U.S.C.) (1978).
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    15. Beginning in the 1980s, the Commission allowed independent 
power producers to sell electric energy at wholesale at negotiated 
rates instead of the traditional cost-based rates.\8\ Development of a 
competitive generation sector was impeded, however, because independent 
power producers were discouraged from entering the generation business 
by certain provisions of the Public Utility Holding Company Act of 1935 
(PUHCA) \9\ and because the new power suppliers could not readily gain 
access to the transmission grid to reach wholesale buyers.
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    \8\ See The Electric Energy Market Competition Task Force, 
Report to Congress on Competition in Wholesale and Retail Markets 
for Electric Energy, Docket No. AD05-17-, at 22 (April 2007).
    \9\ 15 U.S.C. 79a et seq. (2000).
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    16. Congress addressed these problems in the Energy Policy Act of 
1992 (EPAct 1992).\10\ EPAct 1992 eased PUHCA restrictions so that 
independent and affiliate generators could more easily enter the market 
to compete at wholesale and it expanded the Commission's authority to 
order a transmitting utility to provide wholesale power transmission 
service, upon application on a case-by-case basis, to anyone selling 
power at wholesale. By the mid-1990s, the Commission found that 
ordering wholesale transmission services case-by-case did not 
adequately address problems with undue discrimination in transmission 
access, which limited opportunities for wholesale power competition. In 
1996, the Commission used its authority under section 206 of the 
Federal Power Act (FPA) \11\ to issue Order No. 888, remedying undue 
discrimination in access to transmission by requiring all public 
utilities with transmission to provide transmission service under an 
OATT.\12\ The Commission recently issued Order No. 890 to remedy 
remaining opportunities for undue discrimination in the provision of 
open access transmission service.
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    \10\ Pub. L. No. 102-486, 106 Stat. 2776 (1992).
    \11\ 16 U.S.C. 824e (2000).
    \12\ Promoting Wholesale Competition Through Open Access Non-
Discriminatory Transmission Services by Public Utilities; Recovery 
of Stranded Costs by Public Utilities and Transmitting Utilities, 
Order No. 888, FERC Stats. & Regs., Regulations Preambles January 
1991-June 1996 ] 31,036 (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 relevant part, remanded in part on other grounds sub nom. 
Transmission Access Policy Study Group, et al. v. FERC, 225 F.3d 667 
(D.C. Cir. 2000), aff'd sub nom. New York v. FERC, 535 U.S. 1 
(2002).
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    17. Also during the 1990s, many states began to allow retail 
customers to choose their power supplier. Retail competition was 
expected to lower retail prices, protect customers from shouldering 
generation investment risk, and introduce innovative retail services 
including demand response services. By 2000, 24 states and the District 
of Columbia had enacted legislation or issued regulatory orders to 
restructure their electric power industries.\13\
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    \13\ U.S. Department of Energy, Energy Information 
Administration, Status of State Restructuring of the Electric Power 
Industry, at http://www.eia.doe.gov/cneaf/electricity/epar1/state.html
.

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    18. In addition to requiring open transmission access in Order No. 
888, FERC also encouraged the formation of ISOs. The Commission 
encouraged transmission-owning utilities to voluntarily transfer 
operating control of their transmission facilities to an ISO to ensure 
independent operation of the transmission grid. Several ISOs--some 
based on longstanding power pools such as PJM and ISO-NE--formed after 
that. Early experience with open transmission access led the Commission 
to issue Order No. 2000 in December 1999,\14\ which encouraged 
transmitting utilities, including those that were not public utilities, 
to join an RTO.\15\ More than half the United States' load is now 
served by RTOs or ISOs.\16\ Most RTOs and ISOs have adopted some forms 
of organized markets, which have continued to evolve with operating 
experience.\17\ RTOs and ISOs have improved transmission reliability 
and enabled greater coordination and efficiency in the dispatch of 
resources and provision of transmission service over regions served 
previously by separate entities. Further, they have supported 
competitive power markets by eliminating pancaked rates in the region, 
as well as by providing a spot market to supplement traditional means 
of selling and buying power.
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    \14\ Regional Transmission Organizations, Order No. 2000, FERC 
Stats. & Regs. ] 31,089 (1999), order on reh'g, Order No. 2000-A, 
FERC Stats. & Regs ] 31,092 (2000), aff'd sub nom. Pub. Util. Dist. 
No. 1 of Snohomish County, Washington v. FERC, 272 F.3d 607 (D.C. 
Cir. 2001).
    \15\ See Order No. 2000, FERC Stats. & Regs., Regulations 
Preambles July 1996-December 2000 ] 31,089 at 31,028.
    \16\ The Commission has approved RTOs or ISOs in several regions 
including the Northeast (PJM, NYISO, and ISO-NE), California 
(CAISO), the Midwest (Midwest ISO) and the Southwest (SPP).
    \17\ RTOs and ISOs currently operate various combinations of the 
following organized markets: energy markets (day-ahead and real-time 
balancing markets), transmission rights, installed capacity markets, 
and other ancillary services markets.
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    19. While RTOs and ISOs have produced benefits, they also have 
encountered many challenges. Security constrained least cost dispatch 
over a large region can reveal transmission constraints and higher 
locational prices in constrained areas. Previously, average prices for 
the large region masked these constraints. Higher prices in certain 
locations and the lack of investment to relieve chronic congestion are 
criticisms of RTOs and ISOs. Concerns about transmission investment are 
common to both the RTO and ISO regions and the other regions.
    20. Competitive wholesale markets for electric energy, including 
RTO and ISO spot markets, have had successes and failures. Competitive 
markets have stimulated generation investment, with much of the new 
generation supplied by merchant generating companies.\18\ According to 
data from the Energy

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Information Administration (EIA), the percentage of generating capacity 
in the United States owned by independent power producers has grown 
from less than 2 percent in 1990 to more than 35 percent by 2005.\19\ A 
result has been to shift the risk of investment from customers to 
shareholders. In addition, under wholesale competition, the efficiency 
of existing nuclear, coal, and other types of generation has improved 
significantly, lowering costs to consumers and reducing environmental 
effects, and the increased capacity factors and availability of these 
units has further lowered electric generating costs.\20\ The RTO and 
ISO-organized markets opened opportunities for renewable energy 
sources; an increasing fraction of new generation is from non-
traditional sources such as wind generators. In fact, more wind 
generation has been added in RTO and ISO regions than in other regions, 
even though there are many areas with good wind availability.\21\ RTO 
and ISO regions with organized markets report that competitive markets 
promote significant investment in new transmission, improve 
transmission reliability, and open new opportunities for demand 
response.\22\
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    \18\ See Platts Research and Consulting/RDI, Review and 
Assessment of New Competitive-Market Sources of Power Generation 
(February 5, 2003); Paul L. Joskow February 27, 2007 Comments, 
Docket No. AD07-7-000; New England Power Generators Association, 
Inc., Meeting New England's Supply Needs: Regulated vs. Unregulated 
Generation, at http://www.nepga.org/contents/factsheet9041006.pdf.

    \19\ U.S. Department of Energy, Energy Information 
Administration, Electric Power Annual 2005, Table 2.1 (November 
2006), at http://www.eia.doe.gov/cneaf/electricity/epa/epat2p1.html.

    \20\ North American Electric Reliability Corporation, Generating 
Availability Report (November 2006).
    \21\ Michael Skelly February 27, 2007 Comments, Docket No. AD07-
7-000, at 1 (submitted on behalf of Horizon Wind Energy and the 
American Wind Energy Association) (reporting that ``[w]ell-
structured regional wholesale electricity markets operated 
independently allow far greater amounts of renewable energy and 
demand response resources to be integrated into the nation's 
electric grid. In fact, approximately 73 percent of installed wind 
capacity is now located in regions with such markets, while only 44 
percent of wind energy potential is found in these areas. Large, 
regional energy markets provide for cost-effective balancing of 
generation and load with significant penetrations of variable, 
nondispatchable power sources, and they facilitate delivery of 
resources remote from load centers.'')
    \22\ See, e.g., ISO/RTO Council, The Value of Independent 
Regional Grid Operators (November 2005), http://www.caiso.com/14c6/14c6c4291aa40.pdf
.

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    21. Despite all of the successes attributable to wholesale 
competition, there have been difficulties. The most prominent is that 
spot markets in California during 2000 and 2001 experienced sustained 
high wholesale prices resulting from supply shortages, market design 
flaws, and market abuses. In other RTOs and ISOs, prices in the day-
ahead and real-time balancing markets have been volatile at times. This 
volatility can present issues for both buyers and sellers as buyers try 
to hedge the volatility and sellers try to project revenues from the 
organized markets. Even with the volatility, the RTO and ISO markets 
have provided wholesale customers and suppliers with a new and 
constantly available opportunity to buy or sell power and transparent 
price information.
    22. Much of the concern about competition in wholesale power 
markets can be traced to the effects of higher natural gas prices on 
wholesale electric power prices. As the Commission's staff reports, 
``natural gas currently functions as the most significant price-setting 
fuel in U.S. electric generation.'' \23\ Natural gas prices have 
increased significantly over the last decade. According to the Energy 
Information Administration, the average U.S. wellhead price of natural 
gas increased from $2.17 in 1996 to $6.42 in 2006 (which was down from 
$7.33 in 2005).\24\ The summer 2007 futures prices from the New York 
Mercantile Exchange (NYMEX) for natural gas at Henry Hub, Louisiana are 
up 21 percent over last summer's actual average prices traded on the 
Intercontinental Exchange (ICE).\25\ As reported by Commission staff, 
wholesale prices for electricity are expected to be higher in the 
summer of 2007 in all regions of the United States, regardless of 
regional market structure.\26\ The principal reason is higher expected 
prices for natural gas. As the United States has increased its reliance 
on natural gas for electricity generation, particularly to meet peak 
loads, the forward price of natural gas has had an increasing effect on 
the forward price of wholesale electric power, especially during 
electric peak periods. The effect of wholesale prices is felt in parts 
of the United States that have no organized markets as well as regions 
with organized markets.
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    \23\ Stephen Harvey, Office of Enforcement, Federal Energy 
Regulatory Commission, Presentation at the May 17, 2007 Commission 
Meeting: 2007 Summer Energy Market Assessment (May 17, 2007) (Summer 
Market Assessment), at http://www.ferc.gov/EventCalendar/Files/20070517112506-A-3.pdf
 [to fix].

    \24\ See Id. See also U.S. Department of Energy, Energy 
Information Administration, U.S. Natural Gas Wellhead Price, at 
http://tonto.eia.doe.gov/dnav/ng/hist/n9190us3a.htm.

    \25\ See Summer Market Assessment. These NYMEX and ICE prices 
are not estimates but prices actually produced on those two trading 
systems.
    \26\ Id.
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    23. Some perceived challenges in the organized wholesale markets 
may be closely related to difficulties in state retail choice programs. 
Retail choice programs tend to be in areas served by organized 
wholesale markets, and the distinction between wholesale and retail 
competition challenges is often blurred. It appears that some areas 
with retail choice depend on their RTO or ISO to provide or arrange for 
the provision of some functions previously carried out by vertically 
integrated utilities. This has created challenges for wholesale market 
design, particularly with regard to whether it effectively provides for 
resource adequacy. Because wholesale and retail markets are 
intertwined, any examination of retail choice typically involves a 
critique of the combination of the particular retail choice program and 
the RTO's or ISO's wholesale market design.
    24. The Commission continues to believe that wholesale competition 
benefits customers by providing more choice, spurring innovative 
services and technologies, shifting risk away from customers, improving 
efficiency, and providing incentives for cost reductions and for the 
construction of new resources. As stated above, the purpose of this 
ANOPR is to explore reasonable proposals for improving wholesale 
organized markets.

B. Competition Issues and Commission Actions

    25. In proceedings outside this ANOPR, the Commission has addressed 
or is addressing many issues related to improving wholesale electric 
power competition in all regions, both with and without organized 
markets. The Commission has taken actions to improve wholesale 
transmission and competitive wholesale power opportunities.
    26. The Commission's transmission actions have included reform of 
the OATT, development of long-term transmission rights policies, 
incentives for new transmission infrastructure, and approval of 
transmission cost allocation policies. OATT reform applies to 
transmission-owning and operating public utilities in all regions. It 
adds greater consistency and transparency to available transfer 
capability calculations, requires an open and coordinated regional 
transmission planning process, and reforms energy imbalance charges. 
Additionally, it provides for a new ``conditional firm'' point-to-point 
transmission service. Long-term transmission rights in RTOs and ISOs 
were strengthened in Order Nos. 681 and 681-A. These orders, as 
directed by EPAct 2005, provide for long-term transmission price 
certainty in the organized electricity markets, which supports long-
term power supply arrangements. In Order No. 679,\27\ the

[[Page 36280]]

Commission acted to bolster investment in the nation's transmission 
infrastructure in response to section 1241 of EPAct 2005.\28\ This rule 
allows those building transmission to apply for recovery of prudently 
incurred costs for construction work in progress, pre-operations, and 
abandoned facilities, and it provides for application for an incentive 
rate of return on equity for new transmission investment. To further 
encourage transmission investment, and provide certainty about who pays 
for new transmission, the Commission, in separate orders for each RTO 
or ISO--including two this year \29\--has approved cost allocation 
policies for new and existing transmission, thereby removing any 
barrier to new investment caused by uncertainty about transmission cost 
allocation.
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    \27\ Promoting Transmission Investment through Pricing Reform, 
Order No. 679, 71 FR 43,294 (July 31, 2006), FERC Stats. & Regs. ] 
31,222, order on reh'g, Order No. 679-A, 72 FR 1,152 (January 10, 
2007), FERC Stats. & Regs. ] 31,236 (2006), order on reh'g, 119 FERC 
] 61,062 (2007).
    \28\ Section 1241 of EPAct 2005 is to be codified at section 219 
of the FPA, 16 U.S.C. 824s.
    \29\ PJM Interconnection, L.L.C., Opinion No. 494, 119 FERC ] 
61,063 (2007), reh'g pending (approving PJM's cost allocation 
proposal for existing transmission facilities, and requiring 
revisions to its proposal for new transmission facilities); Midwest 
Independent Transmission System Operator, Inc., 118 FERC ] 61,209 
(2007), reh'g pending (conditionally approving cost allocation for 
economic upgrades). In 2006, the Commission approved the Midwest 
ISO's proposed cost allocation for reliability upgrades. Midwest 
Independent Transmission System Operator, Inc., 114 FERC ] 61,106, 
order on technical conference, 117 FERC ] 61,241 (2006), order on 
reh'g, 118 FERC ] 61,208 (2007), reh'g pending.
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    27. The Commission also has undertaken numerous actions in support 
of competitive wholesale power opportunities. For example, the 
Commission established interconnection rules for large, small and wind 
generators. In addition, the Commission has not only granted initial 
approval to the organized markets of the RTO and ISO regions but has 
continued to work with each region to improve the design of its markets 
as the region and the Commission have gained experience with the 
different regional approaches. Further, we have approved various market 
power mitigation rules and provided for market monitoring in the 
organized markets of RTOs and ISOs. Also, in response to EPAct 2005, 
the Commission prepared a report that assesses electric demand response 
resources by region.\30\ The Commission has also opened a proceeding on 
demand response in wholesale markets, and we held a technical 
conference on April 23, 2007, to examine demand resources in markets, 
grid operations and expansion, and best practices for the measurement 
and evaluation of demand response resources.\31\ These Commission 
actions, along with other prior actions of the Commission, are intended 
to work together to improve the operation of competitive wholesale 
markets across the nation, in regions with and without organized 
markets. The proposals in this ANOPR complement these actions and are 
part of our ongoing effort to maintain and encourage competitive 
wholesale electric energy markets.
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    \30\ Federal Energy Regulatory Commission, Assessment of Demand 
Response and Advanced Metering: Staff Report, Docket No. AD06-2-000 
(August 8, 2006) (FERC Staff Demand Response Assessment).
    \31\ See Supplemental Notice, Demand Response in Wholesale 
Markets, Docket No. AD07-11-000 (April 6, 2007).
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    28. With the passage of EPAct 2005, Congress granted the Commission 
additional authorities to support wholesale competition. Key provisions 
in EPAct 2005 include authority to impose civil penalties for market 
manipulation, to prevent exercise of market power through expanded 
power to review mergers and generation facility transfers, and to 
require market transparency. EPAct 2005 also included a number of 
provisions designed to strengthen the interstate power grid, both to 
assure reliability and support competitive markets, encouraging the 
Commission to increase transmission investment through incentives, 
providing for backstop federal siting of transmission facilities, 
encouraging the deployment of advanced technologies, and authorizing 
the Commission to approve and enforce mandatory reliability standards. 
The Commission has taken these and other new responsibilities seriously 
and has complied with all Congressional directives and deadlines.
    29. In addition, the Commission has recognized that there are 
issues that need to be addressed where the Commission and state 
commissions share an interest, such as demand response and competitive 
procurement. The Commission is engaged with the National Association of 
Regulatory Utility Commissioners (NARUC) in two collaborative efforts, 
the NARUC-FERC Collaborative Dialogue on Demand Response and the NARUC-
FERC Competitive Procurement Collaborative.

C. Issues Addressed in the ANOPR

    30. Competition remains national policy with respect to wholesale 
power markets. Competition continues to be sound policy in wholesale 
markets, when combined with effective regulation. The Commission has a 
duty to improve the operation of wholesale power markets to support 
competition. One way to accomplish that is by pursuing regulatory 
reform. To that end, the Commission initiated this proceeding, designed 
to identify the challenges facing competitive wholesale power markets, 
identify workable solutions to those challenges that will complement 
other Commission actions to improve the operation of competitive 
wholesale markets, and determine which solutions are within the 
Commission's authority. This proceeding also responds to concerns 
raised by market participants regarding needed improvements to the 
operation of competitive wholesale markets.
    31. In order to gather more information and allow public comment, 
the Commission held a conference on competition issues on February 27, 
2007. At this first competition conference, most speakers addressed 
issues affecting the RTO and ISO regions, including the level of 
wholesale prices, the need for long-term power contracts, the 
effectiveness of market monitoring, and the lack of adequate demand 
response. The Commission held a second competition conference on May 8, 
2007, to examine in more detail several specific concerns and 
challenges identified in the first conference. This second conference 
focused on regions with RTOs and ISOs and organized markets and dealt 
with: (1) Demand response and market prices during a power shortage; 
(2) fostering long-term power contracting; and (3) the responsiveness 
of RTOs and ISOs to customers and other stakeholders. The panel on 
demand response emphasized allowing customers to respond to high 
prices, particularly when generating capacity falls short of demand, 
providing adequate compensation for demand reductions, and allowing 
many small retail demand reductions to be aggregated for use in the 
wholesale power market. The panel on long-term power contracting 
discussed the role and availability of long-term contracts, as well as 
the importance of long-term transmission service and a robust 
transmission system. The RTO and ISO accountability panel discussed the 
need for RTOs and ISOs to be more responsive to their stakeholders; it 
considered several means of achieving this such as allowing a few 
stakeholder representatives to serve on hybrid boards of RTOs or ISOs. 
On April 5, 2007, the Commission also held a technical conference on 
market monitoring policies and heard from interested commenters on 
issues such as the development of the concept and

[[Page 36281]]

functions of market monitoring and the MMUs' role with respect to the 
Commission, ISOs and RTOs, and various stakeholders.
    32. Based on comments received at these three conferences, the 
Commission decided to consider in this ANOPR four issues in organized 
market regions that are not already being fully addressed by the 
Commission in other proceedings. These areas are: (1) The role of 
demand response in organized markets and greater use of market prices 
to elicit demand reductions during a power shortage; (2) increasing 
opportunities for long-term power contracting; (3) strengthening market 
monitoring; and (4) enhancing the responsiveness of RTOs and ISOs to 
customers and other stakeholders.
    33. At this time, the Commission is not addressing in this ANOPR 
potential reforms outside the organized market regions. As discussed in 
our first technical conference, the primary concerns of wholesale 
customers and competitors in other regions are nondiscriminatory access 
to transmission and nondiscriminatory rules for power procurement. 
These two areas, although critically important, are being addressed by 
the Commission in other proceedings. In Order No. 890, the Commission 
reformed the OATT to ensure that it continues to provide 
nondiscriminatory access to transmission service. Much work remains to 
be done, however, and the Commission is focusing on the compliance 
phase of OATT reform to ensure that it is implemented properly, 
particularly in the area of regional transmission planning and the 
calculation of available transfer capability. With regard to power 
procurement, the Commission believes that competitive procurement can 
enhance the ability of LSEs to acquire reliable wholesale power 
supplies at reasonable prices. The Commission recognizes, however, that 
wholesale power procurement raises issues that are important to both 
the Commission and state commissions. The Commission is therefore 
pursuing a cooperative dialogue with NARUC to develop guidelines for 
best practices for power procurement. Since these two main areas of 
concern are being pursued in other proceedings, the Commission will not 
address reforms outside the RTO/ISO regions in this proceeding. 
Similarly, issues related to demand response are important to both this 
Commission and state commissions. Concerns with participation of demand 
response in organized and bilateral markets were voiced in our 
technical conferences. The Commission is pursuing a collaborative 
dialogue with state commissions on best practices and coordination on 
demand response issues, and lessons learned there may be applicable to 
bilateral markets.

III. Demand Response and Pricing During Power Shortages in Organized 
Markets

    34. A well-functioning competitive wholesale electric market should 
reflect current supply and demand conditions. The Commission has 
expressed the view on numerous occasions that the wholesale electric 
power market works best when demand can respond to the wholesale 
price.\32\ The Commission's policy is to facilitate the participation 
of demand response in the organized power markets, in part because 
demand response helps to hold down wholesale power prices, increases 
awareness of energy usage, provides for more efficient operation of 
markets, mitigates market power, and enhances reliability. This policy 
reflects the Commission's view that the value of electric power to 
customers is not always the same. It changes over time and varies from 
place to place. The value can be very different for two customers at 
the same time and place, one of whom may prefer to reduce consumption 
if the price is high and another who may be willing to pay a high price 
to avoid curtailment in an emergency.
---------------------------------------------------------------------------

    \32\ New England Power Pool and ISO New England, Inc., 101 FERC 
] 61,344, at P 44-49 (2002), order on reh'g, 103 FERC ] 61,304, 
order on reh'g, 105 FERC ] 61,211 (2003); PJM Interconnection, 
L.L.C., 95 FERC ] 61,306 (2001); PJM Interconnection, L.L.C., 99 
FERC ] 61,227 (2002); Southwest Power Pool, Inc., 116 FERC ] 61,289 
(2006).
---------------------------------------------------------------------------

    35. While the Commission and the various RTOs and ISOs have done 
much to facilitate demand response in organized power markets, more can 
be done. In response to a requirement of EPAct 2005 to assess demand 
response capability nationally, the August 2006 FERC Staff Demand 
Response Assessment estimated the total installed demand response 
capability from existing programs nationally to be 37,500 megawatts 
(MW), or about five percent of current peak demand. Several reports 
indicate that the potential demand response capability available in the 
United States may be much greater than this.\33\ The Commission's 
preliminary view is that RTO and ISO wholesale market design changes or 
additions, particularly for energy and ancillary services markets, may 
be needed to help tap that potential. Our goal is for RTOs and ISOs to 
develop rules to ensure the treatment of supply and demand resources on 
a comparable basis to the extent each is technically capable of 
providing the service. Our aim is not to afford demand resources 
preferential treatment over supply resources. For example, even under 
the mechanisms contemplated by this ANOPR, demand resources must 
satisfy all requirements for service provision comparable to those 
applied to supply resources, including but not limited to procedures 
for measurement and verification of performance, as well as penalties. 
Further, our aim is not to require demand resources to participate in 
these or any other resource programs. Rather, we are merely ensuring 
that the wholesale markets are designed to accommodate demand resources 
in a manner comparable to supply resources, unless not permitted by 
state law. Therefore, the mechanisms should not intrude on state 
jurisdiction. The Commission's proposals do not require action by 
states but can benefit from such action.
---------------------------------------------------------------------------

    \33\ See, e.g., Ahmad Faruqui et al., The Brattle Group, The 
Power of Five Percent: How Dynamic Pricing Can Save $35 Billion in 
Electricity Costs (May 16, 2007), http://www.brattle.com/_documents/Publications/ArticleReport2441.pdf
.

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A. Importance of Demand Response to Competition in RTO/ISO Areas

    36. The value of demand response to properly functioning RTO and 
ISO markets has been described in detail by many experts, such as Nobel 
Prize-winning economist Vernon Smith and Lynne Kiesling, in their paper 
titled ``A Market-Based Model for ISO-Sponsored Demand Response 
Programs.'' \34\ Demand response assists competitive wholesale markets 
in at least three ways.
---------------------------------------------------------------------------

    \34\ Vernon Smith and Lynne Kiesling, Market-Based Model for 
ISO-Sponsored Demand Response Programs, (September 2005), http://www.defgllc.com/Downloads/051018_DEFG_DRwp02.pdf
 .

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

    37. First, demand response can help reduce wholesale prices and 
wholesale price volatility. The reduction is valued especially during 
peak periods, but demand response can also lower price and volatility 
during off-peak periods. Demand response can lower wholesale prices 
directly and indirectly. The direct effect occurs when a demand 
reduction is bid directly into the wholesale market: lower demand means 
a lower wholesale price. Demand response at retail, if not bid directly 
into the wholesale market by a large retail customer, affects the 
wholesale market indirectly because it reduces the need for power by 
the retail customers' LSE and in turn reduces that LSE's need to 
purchase power from the wholesale market. For example, where an LSE 
offers retail customers some form of

[[Page 36282]]

time-of-use rates, the retail customers' response to rates during a 
higher-priced period reduces the LSE's wholesale demand and helps lower 
wholesale prices. This lower wholesale price may result in lower retail 
prices.
    38. Second, demand response tends to flatten an area's load 
profile. With a flatter load profile, the distribution of generation 
types tends to shift toward lower-cost base load generation and away 
from higher-cost peaking generation, and this tends to lower the 
overall average cost to produce energy.
    39. Third, demand response can help reduce the potential for market 
manipulation by reducing generator market power. As more demand 
response is available during peak periods, power suppliers need to 
account more for the price responsiveness of load when they consider 
higher-price bids. The more demand response is able to reduce the peak 
price, the more downward pressure it places on generator bidding 
strategies by increasing the risk to a supplier that it will not be 
dispatched if it bids too high.
    40. RTOs such as PJM, NYISO, and ISO-NE have quantified the cost-
effectiveness of demand response in their wholesale markets. They 
assessed both the reduction in market prices due to demand reductions 
and the value of demand response to system reliability. These 
assessments conclude that the demand response programs they operate 
produce net benefits associated with lower wholesale prices. For 
example, ISO-NE found that the benefits of its various economic and 
emergency demand response programs in 2005 more than compensate for its 
costs, largely payments to demand response participants and its own 
extra operating costs.\35\ PJM and NYISO found similar positive results 
in evaluations of their programs.\36\
---------------------------------------------------------------------------

    \35\ ISO-NE, An Evaluation of the Performance of the Demand 
Response Programs Implemented by ISO-NE in 2005, Docket No. ER02-
2330-040 (Dec. 30, 2005).
    \36\ NYISO, NYISO 2006 Demand Response Programs, Docket No. 
ER01-3001-016 (Feb. 16, 2007); PJM, Assessment of PJM Load Response 
Programs, Docket No. ER02-1326-006 (Aug. 29, 2006).
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B. Prior Commission Actions To Address Demand Response

    41. The Commission has issued numerous orders over the last several 
years on various aspects of electric demand response in organized 
markets. A goal of most of these orders was to remove unnecessary 
obstacles to demand response participating in the wholesale power 
markets of RTOs and ISOs.\37\
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    \37\ See, e.g., New York Independent System Operator, Inc., 92 
FERC ] 61,073, order on clarification, 92 FERC ] 61,181 (2000), 
order on reh'g, 97 FERC ] 61,154 (2001); New England Power Pool and 
ISO New England, Inc., 100 FERC ] 61,287, order on reh'g, 101 FERC ] 
61,344 (2002), order on reh'g, 103 FERC ] 61,304, order on reh'g, 
105 FERC ] 61,211 (2003); PJM Interconnection, L.L.C., 95 FERC ] 
61,306 (2001); PJM Interconnection, L.L.C., 99 FERC ] 61,139 (2002); 
PJM Interconnection, L.L.C., 99 FERC ] 61,227 (2002).
---------------------------------------------------------------------------

    42. These orders approved various types of demand response 
programs, including programs to allow demand response to be used as a 
capacity resource and as a resource during system emergencies,\38\ 
programs to allow wholesale buyers and qualifying large retail buyers 
to bid a demand reduction directly into the day-ahead and real-time 
energy markets and certain ancillary service markets, particularly as a 
provider of operating reserves, as well as programs to accept bids from 
aggregators of retail customers (ARCs).\39\ The Commission also has 
approved special demand response applications such as use of demand 
response for synchronized reserves and regulation service.\40\ The 
theme underlying the Commission's approval of these programs has been 
to allow demand resources to participate in these markets on a basis 
that is comparable to other resources.
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    \38\ See, e.g., PJM Interconnection, L.L.C., 117 FERC ] 61,331 
(2006); Devon Power L.L.C., 115 FERC ] 61,340 (2006). These orders 
allow demand resources to provide capacity resources.
    \39\ We will use the phrase ``aggregation of retail customers'' 
to refer to RTOs and ISOs accepting bids from parties that aggregate 
demand response bids (which are mostly from retail loads), or ARCs. 
See, e.g., New York Independent System Operator, Inc., 95 FERC ] 
61,223 (2001); New England Power Pool and ISO New England, Inc., 100 
FERC ] 61,287, order on reh'g, 101 FERC ] 61,344 (2002), order on 
reh'g, 103 FERC ] 61,304, order on reh'g, 105 FERC ] 61,211 (2003); 
PJM Interconnection, L.L.C., 99 FERC ] 61,227 (2002).
    \40\ See, e.g., PJM Interconnection, L.L.C., 114 FERC ] 61,201 
(2006).
---------------------------------------------------------------------------

    43. An important type of demand response program is one that allows 
demand response bids in the day-ahead and real-time energy markets by a 
group of retail customers. There is usually a minimum size bid allowed 
in an RTO or ISO market for any participating retail customer. The 
Commission has approved programs that allow smaller retail customers to 
combine their individual demand reductions into a larger block for 
bidding into the organized markets, if permitted by state law, without 
having to go through their LSE.\41\ A third party ARC, often called a 
curtailment service provider, typically provides this aggregation 
service. The aggregate demand reduction may be bid directly into the 
energy and ancillary services markets.
---------------------------------------------------------------------------

    \41\ See, e.g., New York Independent System Operator, Inc., 95 
FERC ] 61,223 (2001); New England Power Pool and ISO New England, 
Inc., 100 FERC ] 61,287, order on reh'g, 101 FERC ] 61,344 (2002), 
order on reh'g, 103 FERC ] 61,304, order on reh'g, 105 FERC ] 61,211 
(2003); PJM Interconnection, L.L.C., 99 FERC ] 61,227 (2002).
---------------------------------------------------------------------------

    44. In addition, the Commission has explicitly addressed demand 
response in its recent final rules on OATT Reform (Order No. 890) and 
reliability standards (Order No. 693).\42\ Order No. 890 requires any 
public utility with an OATT to allow qualified demand resources to 
participate in its regional transmission planning process on a 
comparable basis and to allow qualified demand response to provide 
certain ancillary services. Specifically, we agreed with a request by 
Alcoa that load resources (i.e., demand response) should be permitted 
to self-supply and sell ancillary services to third parties.\43\ In 
doing so, we also made clear that a Transmission Provider may use non-
generation resources in meeting its OATT obligation to provide 
ancillary services, so long as those resources are capable of providing 
the service.\44\ Order No. 890 did not require Transmission Providers 
to purchase ancillary services from non-generation resources or 
generation resources. Our proposal here would require RTO/ISO ancillary 
service markets to allow bidding by non-generation resources if they 
are capable of providing such services. Order No. 693 requires the 
Electricity Reliability Organization to revise its reliability 
standards so that all technically feasible resource options, including 
demand response and generating resources, may be employed in the 
management of grid operations and emergencies.\45\
---------------------------------------------------------------------------

    \42\ See Mandatory Reliability Standards for the Bulk Power 
System, Order No. 693, 72 FR 16,416 (April 4, 2007), FERC Stats. & 
Regs. ] 31,242 (2007).
    \43\ Order No. 890 at P 887-88.
    \44\ E.g., Order 890, OATT Schedule 5 (Operating Reserve--
Spinning Reserve Service).
    \45\ Order No. 693 directed the Electricity Reliability 
Organization to develop new versions of its BAL-002, BAL-005, and 
EOP-002 reliability standards to allow demand side resources to 
provide contingency reserves. Order No. 693 at ] 330-35, 404-06, 
573.
---------------------------------------------------------------------------

    45. The Commission has also encouraged demand response outside of 
its orders. The Commission has conducted several technical conferences 
on demand response over the last several years, most recently on April 
23, 2007.\46\ The NARUC-FERC

[[Page 36283]]

Collaborative Dialogue on Demand Response began in November 2006 to 
explore state/federal coordination of efforts to promote and integrate 
demand response into retail and wholesale markets and planning. Also, 
as mentioned, in August 2006 the Commission published the staff report 
on demand response and advanced metering as directed by EPAct 2005 
section 1252(e)(3).\47\
---------------------------------------------------------------------------

    \46\ For example, the Commission conducted a technical 
conference on January 25, 2006 to support the FERC Staff Demand 
Response Assessment in Docket No. AD06-2-000. The April 23, 2007 
conference was convened in Docket No. AD07-11-000.
    \47\ See FERC Staff Demand Response Assessment.
---------------------------------------------------------------------------

    46. In this ANOPR, the Commission's focus is on exploring market 
rules that allow both wholesale and qualifying retail customers to bid 
demand response into the day-ahead, real-time energy, and ancillary 
services markets.

C. Remaining Problems With Demand Response in Organized Markets

    47. While progress has been made to increase demand-responsiveness 
and price-responsiveness in organized markets, more needs to be done.
    48. An effective way for demand to respond to price is at the 
retail level, through some form of time-based retail rates (time-based 
retail rates include rates that vary by hour, such as real-time 
pricing, or by blocks of time, such as time-of-use rates or critical 
peak pricing). Demand response is more effective when retail rates are 
tied to current wholesale market-clearing prices. Effective demand 
response can be achieved by linking the wholesale and retail markets. 
While the Commission can remove some obstacles to demand participation 
in organized markets, more effective demand response also requires the 
action of state commissions.
    49. As discussed in the FERC Staff Demand Response Assessment, some 
forms of demand response are well-suited to provide the ancillary 
services of spinning reserves, supplemental reserves, energy imbalance, 
and regulation and frequency response.\48\ Because demand is always 
connected and demand reduction, in principle, can always be available, 
some forms of demand resources may be able to provide a rapid, near 
real-time response.\49\ Nevertheless, except for a few markets, demand 
response is not able to participate in these ancillary services 
markets. ISO-NE, NYISO, and CAISO allow demand resources to provide 
supplemental (non-spinning) reserves. As of mid-2007, only PJM allows 
demand resources to provide synchronized reserves (PJM's term for 
spinning reserves) and regulation service (although no resource has yet 
qualified to provide this service in PJM).
---------------------------------------------------------------------------

    \48\ For an explanation of each of these ancillary services, see 
the pro forma OATT, Schedules 3 through 6, contained in Order No. 
890.
    \49\ For example, electric-arc steel furnaces have the 
capability to adjust their consumption rapidly, and air conditioner 
cycling programs can respond within several minutes of execution.
---------------------------------------------------------------------------

    50. Several factors may account for the lack of participation of 
demand resources in some ancillary services markets. System operators 
responsible for maintaining reliable operation have little or no 
experience with the responsiveness of demand resources and may lack 
confidence in them. To qualify to provide ancillary services, a 
resource must satisfy certain requirements such as having a minimum 
size \50\ and real-time telemetry. These requirements can limit which 
customers may participate and may also obligate customers to invest in 
real-time metering and monitoring equipment at their sites.
---------------------------------------------------------------------------

    \50\ ISO-NE places a minimum size of 5 MW for participation. See 
ISO-NE, ISO New England Manual for Market Rule 1 Accounting (May 31, 
2007), at section 12.3.5.3, http://www.iso-ne.com/rules_proceds/isone_mnls/m_28_market_rule_1_accounting_
(revision--27)--05--

31--07.doc.
---------------------------------------------------------------------------

    51. In addition, market rules for bidding and participating in 
ancillary services markets were developed with generation in mind and 
may not make sense for demand response resources. Distinguishing among 
rules that must apply to all resources to maintain reliability and 
those that can be amended to accommodate inflexible or special case 
resources is an important market design issue. For example, many demand 
resources can respond quickly and at a low cost if called on for a 
short duration, which may make them well suited for providing operating 
reserves. A large industrial customer, such as a steel mill, provides 
an operating reserve when it reduces its load quickly within seconds or 
minutes, in response to direction from a system operator. However, if 
market rules require that bids be made into a joint energy-plus-
reserves market, those offering operating reserves must also be 
available to provide energy or other ancillary services. The result is 
that the operating reserve provider that risks being called on 
frequently or for a prolonged period in the energy market may simply 
decide not to participate in the energy market, and consequently not 
provide demand reduction as operating reserves. Because energy use is 
necessary to a customer's business, frequent or lengthy unplanned 
interruptions could disrupt that business. As a result, market rules 
that do not allow a demand response provider to limit the frequency and 
duration of interruption creates a disincentive for a demand resource 
to bid into the operating reserves market.\51\
---------------------------------------------------------------------------

    \51\ See FERC Staff Demand Response Assessment at 123.
---------------------------------------------------------------------------

    52. Demand response providers need market rules that allow bids to 
be flexible and that reflect bidders' willingness to offer various 
levels of service depending on the market prices. In fact, the design 
of today's organized markets does allow some flexible and some price-
sensitive bidding into day-ahead and real-time energy markets. 
Nevertheless, the Commission is concerned that some market features may 
inhibit LSEs and other demand response providers from bidding load 
reductions into energy markets. For example, in most organized markets, 
if an LSE's actual purchase from the real-time market differs from the 
purchase it scheduled in the day-ahead market, it may be assessed an 
uplift charge (separate from any imbalance charge) \52\ While it is 
important to have mechanisms in place that encourage LSEs to accurately 
forecast and schedule their loads in the day-ahead market, these types 
of charges may unnecessarily discourage an LSE from urging retail 
customers to conserve energy during a system emergency.
---------------------------------------------------------------------------

    \52\ During reserve shortages on August 1 in the Midwest ISO 
region, LSEs contributed close to 3,000 MW of demand reductions but 
were assessed revenue sufficiency guarantee charges--charges that 
ensure that any generator scheduled or dispatched by the Midwest ISO 
after the close of the day-ahead energy market will receive no less 
than its offer prices for start-up, no-load and incremental energy. 
Wisconsin Public Service Commission Chairperson Daniel Ebert 
reported on these charges at the April 23, 2007 technical conference 
on demand response. See Technical Conference on Demand Response in 
Wholesale Markets on April 23, 2007, Tr. 83-84 (Daniel Ebert, 
Wisconsin Public Service Commission) (Docket No. AD07-11-000).
---------------------------------------------------------------------------

    53. Organized energy market rules may restrict the type of bid that 
a LSE or ARC may submit. In some cases, this may be intended to treat a 
demand response bid the same as a generation bid, but, in other cases 
there may be a restriction on a demand response bid that does not apply 
to a generation bid. Bidding features available to generation, such as 
a guaranteed minimum price and a minimum duration of service, are often 
not available to demand reductions. Some generators need such features 
if, for example, they are not able to start and stop frequently or if 
cycling output up and down produces excessive stress on their 
equipment. Providers of demand reductions may have their own 
limitations on cycling but not be allowed to express these in their 
bids. For example, if a factory reduces consumption in response to a 
dispatch signal, it may be required to stop production for an entire 
work shift

[[Page 36284]]

or until equipment can be restarted. Frequent directions to reduce load 
for short durations could be disruptive to production. Allowing demand 
response providers to make bids with provisions for minimum duration 
and price limits would make participation by such customers in the 
energy market more attractive.
    54. As mentioned above, the Commission has approved some demand 
response programs that allow retail customers, if it is consistent with 
state law, to bid their combined demand reductions through an ARC into 
wholesale day-ahead and real-time markets. PJM, ISO-NE and NYISO have 
allowed such ARCs to become market participants, and these RTOs accept 
bids from ARCs.\53\ If these load reduction bids are accepted, the RTO 
or ISO directs the customers to reduce their consumption as bid and the 
customers are paid the market-clearing price. The aggregation of retail 
customers programs in PJM and ISO-NE allow program participants to 
reduce their demand before the real-time market runs without being 
subject to uplift charges for unscheduled changes from the day-ahead 
schedule.
---------------------------------------------------------------------------

    \53\ These aggregation of retail customers programs go by 
various names. PJM operates the Economic Load Response Program that 
allows direct bidding in day-ahead and real-time markets. NYISO 
operates the Day-Ahead Demand Response Program. ISO-NE operates the 
Day-Ahead Load Response Program and the Real-Time Price Response 
Program.
---------------------------------------------------------------------------

    55. Another factor that may limit participation by LSEs and retail 
customers in demand response programs is the use of bid caps and price 
caps in the market design. Bid caps and price caps in RTO and ISO 
markets are designed to limit the opportunity to exercise market power 
in these markets, but they also may prevent the markets from expressing 
prices that are legitimately high due to a shortage. These caps may not 
permit buyers in RTO and ISO wholesale energy markets to see prices 
high enough to signal that there is a power shortage and reliability is 
at risk. Moreover, when power is in short supply and price is high, 
retail prices remain fixed, and retail customers do not adjust their 
demand to react to wholesale price signals because these price signals 
are not seen. Consequently, both generation and demand response can be 
in short supply at once, and the market-clearing price may not reflect 
the actual cost of providing more power or the value to customers of 
not being interrupted. Further, as discussed in the long-term 
contracting section below, capping the exposure of LSEs to higher 
prices may reduce their incentive to explore various hedging 
activities, such as participating in interruptible demand response 
programs, entering into long-term contracts or similar power supply 
procurement options, and building new generating units.
    56. Certain demand response programs may themselves act to dampen 
prices during a power shortage. Emergency demand response programs are 
those intended to ensure reliability, which are called on by RTOs and 
ISOs only during a system emergency. They may be paid a fixed price 
such as $500 per MWh when called on. Typically, these emergency 
resources are not paid the market-clearing price. As a result, the 
market-clearing price may decrease because demand is reduced when an 
emergency demand response resource is used, even though it is the 
highest-valued resource used at the time. The reduced price signals 
that buyers should consume more and suppliers produce less, which is 
contrary to the signal that should be sent in an emergency. Only NYISO 
has integrated its emergency demand response programs into the market-
clearing process,\54\ and Midwest ISO is discussing a similar 
integration based on its 2006 experience.
---------------------------------------------------------------------------

    \54\ The Commission approved this change in 2003. New York 
Independent System Operator, Inc., 102 FERC ] 61,313 (2003).
---------------------------------------------------------------------------

D. Proposed Commission Actions To Improve Demand Response and Market 
Pricing During a Power Shortage

    57. The Commission's preliminary view is that the following 
proposals, if adopted, would address market rules to ensure that demand 
response can participate directly and would be treated on a comparable 
basis to supply resources in the organized electric energy and 
ancillary services markets. This would benefit customers by allowing 
market prices to reflect the need for demand response (or more 
generation) during a power shortage. The Commission seeks comment on 
these proposals. In addition, the Commission does not intend the 
following proposals to be the only mechanisms open to consideration for 
ensuring that demand resources be treated comparably to supply 
resources. Commenters may propose other mechanisms for the organized 
markets to adopt that would ensure that demand resources and supply 
resources are treated on a comparable basis in the energy and ancillary 
services markets.
    58. The Commission is considering four proposals to modify the 
design of wholesale RTO and ISO markets to ensure that demand resources 
may participate directly in the energy and ancillary services markets 
on a comparable basis to supply resources. As a complement to these 
potential reforms, the Commission is also considering revisions to 
existing mitigation rules to enable the wholesale market prices to help 
balance supply and demand when power supplies are tight so as to better 
ensure power system reliability.
    59. First, the Commission is considering a proposal to obligate 
each RTO or ISO to purchase demand resources in its markets for certain 
ancillary services, similar to any other resources, if the resources 
meet the necessary technical requirements and the resources submit a 
bid under the generally-applicable bidding rules at or below the 
market-clearing price, unless the seller is not permitted to do so by 
state retail laws or regulations. The Commission proposes modifications 
to RTO and ISO tariffs that would apply this requirement for energy 
imbalance, spinning reserves, and supplemental reserves, as defined in 
the pro forma OATT, or their functional equivalents in an RTO or ISO 
tariff.\55\ To be eligible to supply these ancillary services, demand 
resources must be capable of reducing demand within seconds or minutes. 
Demand resources must meet the RTO's or ISO's reasonable size, 
telemetry, metering, and bidding requirements. For example, the 
Commission approved a one-megawatt minimum bid by demand resources to 
provide certain operating reserves in PJM. The RTO or ISO may propose 
reasonable standards for metering and telemetry needed by system 
operators to call on these reserves and measure their compliance. 
Bidding rules for demand resources should not differ from the rules for 
generation resources unless the reason for the difference is adequately 
explained and justified. An RTO or ISO may propose other requirements 
for demand resources to provide these ancillary services that are 
necessary for reliability and effectiveness.
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    \55\ Order No. 890 also allows qualified demand resources to 
provide the other ancillary services of reactive supply and voltage 
control, regulation and frequency response and generator imbalance.
---------------------------------------------------------------------------

    60. The Commission also proposes to modify RTO and ISO tariffs to 
provide that demand resources must be allowed to provide spinning and 
supplemental reserves without also being required to sell into the 
energy market. This change to market rules is intended to address the 
disincentive for demand response to be an operating reserve. Without 
this modification, customers may hesitate to offer demand reductions as 
operating

[[Page 36285]]

reserves due to concerns about disruptions to their businesses. The 
Commission has approved market rules adopted by the California ISO and 
PJM that reduce this disincentive.\56\
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    \56\ See, e.g., PJM Interconnection, L.L.C., 114 FERC ] 61,201 
(2006) (approving the use of demand resources as operating reserves 
in PJM). PJM allows demand resources to submit separate bids in its 
various energy and operating reserve markets.
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    61. The Commission requests comment on the feasibility and 
effectiveness of the proposal to require RTOs and ISOs to allow demand 
resources to provide these ancillary services. It also requests comment 
on whether to allow each RTO and ISO to propose its own minimum 
requirements (for example, as to minimum size bids, measurement and 
telemetry) or to specify appropriate minimum requirements in a 
Commission rule. In particular, the Commission requests comment on what 
size a minimum bid should be. Any proposal must comply with the ERO 
mandatory reliability standards.\57\
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    \57\ In particular, any proposal must comply with BAL-002 
(Disturbance Control Performance) and EOP-002 (Capacity and Energy 
Emergencies).
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    62. Second, the Commission is considering a proposal to modify RTO 
and ISO tariffs to eliminate, during a system emergency, a charge to a 
buyer in the energy market for taking less electric energy in the real-
time market than purchased in the day-ahead market. This proposal is 
intended to eliminate a disincentive for demand response in the real-
time market. We refer to the charge that we propose to eliminate during 
an emergency as a ``deviation charge,'' which covers certain uplift 
costs, as explained below.
    63. Before setting out the specific proposal to eliminate this 
deviation charge, it is necessary to summarize first how the day-ahead 
and real-time markets relate. A buyer that makes a purchase in the day-
ahead market has a commitment to pay for the amount of energy it 
purchases at the day-ahead market price. If that buyer consumes more 
energy in real-time than it bought the day before, it pays the day-
ahead market price for the amount purchased in the day-ahead market and 
in addition pays the real-time market price for the extra energy 
consumed. The real-time price may be higher or lower than the day-ahead 
price. If the buyer takes less energy in the real-time market than it 
purchased in the day-ahead market, in effect it sells the reduction 
back to the market at the real-time market price. The buyer profits if 
it sells the energy reduction back when the real-time price is higher 
than the day-ahead price, and suffers a loss when the real-time price 
is lower.\58\ Nothing in the proposal here would change this effect. If 
many buyers were to systematically purchase more energy in the day-
ahead market than they expect to take in real time, the reduced real-
time demand is likely to result in a lower real-time price. The 
potential loss to the buyers should effectively discourage purchasing 
more energy than needed in the day-ahead market.
---------------------------------------------------------------------------

    \58\ This true-up process substitutes for an energy imbalance 
charge in most RTO and ISO spot markets.
---------------------------------------------------------------------------

    64. Aside from the buyer's market profit or loss, some RTOs and 
ISOs assess buyers a charge when real-time consumption deviates from 
day-ahead purchases. This charge recovers at least some types of 
``uplift'' costs, which are the portion of the generators' costs (such 
as start-up costs) that exceed their energy market revenues. These 
uplift costs may include the cost of the extra operating reserves 
needed when the total real-time demand of all buyers exceeds the total 
scheduled day-ahead demand. The extra reserves are not needed, however, 
when real-time demand is less than the day-ahead demand. Nevertheless, 
the deviation charge may apply to any deviation from the day-ahead 
schedule.\59\
---------------------------------------------------------------------------

    \59\ Although covering operating reserve costs, the deviation 
charge may also cover other costs not affected by the direction of 
the deviation.
---------------------------------------------------------------------------

    65. Notwithstanding that these charges are typically meant to serve 
as an incentive for accurate scheduling, they tend to discourage demand 
response. When supplies are tight and the real-time price is high, a 
buyer that reduced load but nevertheless has to pay a deviation charge 
may be penalized for taking the appropriate action. This unintended 
disincentive may lead a buyer to maintain a high load or discourage an 
LSE from calling on the demand response capabilities of its retail 
customers. This negative incentive is especially troublesome during a 
system emergency when load reduction is needed most.
    66. The Commission requests comment on a proposal to require RTOs 
and ISOs to eliminate this deviation charge for a load reduction during 
a system emergency. The Commission has already approved a PJM proposal 
to apply no deviation charge for a load reduction from day-ahead to 
real-time during a system emergency.\60\
---------------------------------------------------------------------------

    \60\ During an emergency situation a deviation is only assessed 
if ``that deviation increases [the load's] spot market purchases * * 
*'' PJM, Manual 28: Operating Agreement Accounting, at 65 (March 7, 
2007), http://www.pjm.com/contributions/pjm-manuals/pdf/m28.pdf.

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

    67. The Commission also requests comment on whether an RTO or ISO 
should assess a deviation charge for a day-ahead to real-time load 
reduction when there is no system emergency. Eliminating the charge 
would encourage demand response, but might have unintended 
consequences. The Commission understands that these deviation charges 
cover real costs. Would eliminating the deviation charge for taking 
less energy in real-time result in an unfair reallocation of these 
costs to others? Would the incentive described above--for a buyer to 
avoid purchasing more than it needs in the day-ahead market--adequately 
discourage poor scheduling practices, or is it important to retain the 
deviation charge for this reason? Would eliminating the deviation 
charge for a real-time load reduction introduce any new opportunity for 
gaming behavior?
    68. As background for the third proposal, demand resources 
currently participate in every organized real-time market, with the 
exception of SPP, which is considering such a proposal. Demand 
resources also currently participate in the organized day-ahead markets 
of NYISO, ISO-NE, and PJM, while CAISO and the Midwest ISO are 
considering such a proposal. In addition to participation by individual 
customers, ARCs aggregate demand reductions by retail customers and bid 
these aggregated reductions into the energy markets. The FERC Staff 
Demand Response Assessment and comments during our technical 
conferences indicate that more needs to be done to facilitate direct 
participation in the energy markets by ARCs who bid into the wholesale 
markets aggregated demand reductions on behalf of retail customers and 
other customers. The potential contribution from ARCs has increased 
with technological developments that make demand response more 
automated.
    69. The Commission is considering a proposal to require RTOs and 
ISOs to amend their market rules as necessary to permit an ARC to bid a 
demand reduction on behalf of retail customers directly into the RTO's 
or ISO's organized markets. This proposal is intended to remove a 
barrier to demand response in some RTO and ISO energy markets \61\ by 
allowing an ARC to act as an intermediary for many small retail loads 
that cannot individually participate in the organized market

[[Page 36286]]

because they lack standing as an LSE or because they individually 
cannot meet a requirement that a demand response bid be of minimum 
size.
---------------------------------------------------------------------------

    \61\ Aggregation of retail customers is used now in the energy 
markets of PJM, ISO-NE, and NYISO and in PJM's Synchronized Reserve 
and Regulation Service market in PJM. PJM's aggregation of retail 
customers is integrated into its market rules for PJM's Interchange 
Energy Market. Aggregation of retail customers in ISO-NE and NYISO 
are separate programs that are not yet part of the market rules.
---------------------------------------------------------------------------

    70. Under this proposal, the market rules may not exclude a demand 
response bid from a third-party ARC that is not a LSE unless state 
retail electric laws or regulations do not permit this. This proposal 
would apply to each of the RTO's or ISO's organized markets into which 
an LSE may submit a demand response bid. The market rules for ARCs may 
not differ from the rules for LSEs, except as needed to comply with 
state retail service laws and regulation, unless the RTO or ISO 
satisfactorily explains the reason for any such difference in its 
compliance filing. RTOs and ISOs may, however, set rules for ARC 
participation that are the same as or equivalent to its rules for LSEs. 
Such rules may address such subjects as bidding requirements; technical 
requirements for communicating demand response bids and measuring 
demand response performance; a minimum organized market price above 
which the ARC may offer to reduce load and below which it may not; a 
minimum or maximum number of contiguous hours for which the load 
reduction must be committed; and how to account for start-up costs 
associated with reducing load, creditworthiness, and settlement 
procedures.
    71. Under this proposal, the Commission also would direct the RTOs 
and ISOs to coordinate to identify common issues, best practices 
solutions, and market rules that are consistent between regions, 
particularly in the areas of market procedures, bidding protocols, 
communication protocols, and measurement and verification. The 
Commission would direct the RTOs and ISOs to report, within 90 days of 
the effective date of any Final Rule in this proceeding, on how they 
intend to explore best practices, common issues, and market rules for 
the direct participation of demand resources in their markets.\62\ 
Although we would direct RTOs and ISOs to consider best practices, the 
Commission does not intend that every region would have to adopt the 
same practices, rules, or procedures.
---------------------------------------------------------------------------

    \62\ The Commission would also encourage the RTOs and ISOs to 
work within the ISO/RTO Council to consider best practices that may 
be applicable to the members' regions. The Commission also 
encourages continued participation in the North American Energy 
Standards Board's (NAESB) measurement and verification initiative.
---------------------------------------------------------------------------

    72. The Commission requests comments on the proposal to require 
RTOs and ISOs to amend their market rules to permit demand response of 
aggregated retail customers. Are there other requirements the 
Commission should consider to improve the efficiency of aggregation of 
retail customers? The Commission also requests comments on the 
conditions under which a RTO or ISO aggregation of retail customers 
program would no longer be needed.
    73. The Commission also requests comment on whether aggregation of 
retail customers allows inappropriate compensation when a retail 
customer is paid for wholesale demand reduction and also saves in its 
retail bill from the same demand reduction. The Edison Electric 
Institute (EEI) has argued that the payments to customers represent 
subsidies that are not justified or a form of double payment.\63\ For 
example, because a customer's bill decreases for every megawatt-hour 
(MWh) not consumed, if that customer is also paid an amount by the RTO 
or ISO for the same MWh not consumed, EEI and others allege that the 
customer has been compensated twice. They contend that use of time-
based rates is the correct way to achieve price-responsive demand and 
that any additional payment to retail customers by RTOs and ISOs is 
inappropriate and should be considered a temporary measure at best. 
Others disagree with this criticism, arguing that the price reduction 
does not fully reflect the social benefits produced by the demand 
reduction.\64\ Further, critics of aggregation of retail customers 
programs charge that the incentives for aggregation of retail customers 
programs in energy markets are inconsistent across RTOs and ISOs and 
the programs are susceptible to gaming behavior.\65\
---------------------------------------------------------------------------

    \63\ See Technical Conference on Demand Response and Advanced 
Metering on January 25, 2006, Tr. 26 (Richard Tempchin, EEI) (Docket 
No. AD06-2-000), http://elibrary.ferc.gov:0/idmws/file_list.asp?document_id=4378387
.

    \64\ R.N. Boisvert and B.F. Neenan, Neenan Associates, Social 
Welfare Implications of Demand Response Programs in Competitive 
Electricity Markets (August 2003), http://eetd.lbl.gov/ea/EMP/reports/LBNL-52530.pdf
.

    \65\ The potential for gaming occurs if an aggregator submits a 
demand reduction bid on behalf of customers that will have reduced 
consumption anyway for another reason such as maintenance, vacation, 
or holiday. The Commission approved NYISO's bid floor of $75/MWh in 
its Day Ahead Demand Response Program to eliminate or reduce the 
incentive for this behavior. New York Independent System Operator, 
Inc., 109 FERC ] 61,101 (2004).
---------------------------------------------------------------------------

    74. The Commission requests comments on how to appropriately 
compensate a customer for demand response. We seek comment on whether 
there is any inappropriate double compensation. We also solicit 
comments on whether providing an additional payment is appropriate to 
compensate for the value of the demand response. For example, PJM pays 
the market-clearing price less the generation and transmission 
component of each retail customer's retail rate (this price reduction 
is sometimes called the generation offset).\66\ Would a PJM-type 
generation offset reduce the amount of the alleged double compensation? 
\67\ Would a generation offset encourage demand response more so during 
a period of high price, when it is needed most?
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    \66\ For example, if the market-clearing price is $100 per MWh 
and the generation component of a customer's retail rate is $75 per 
MWh, the payment for the load curtailment would be $25 per MWh 
($100-$75). In PJM's Economic Load Response Program, this netting is 
applied when the market-clearing price is below $75/MWh. See section 
3.3A.4(d) of the PJM Operating Agreement.
    \67\ PJM Interconnection, L.L.C., 99 FERC ] 61,227 (2002).
---------------------------------------------------------------------------

    75. Fourth, the Commission is considering whether to modify RTO and 
ISO market power mitigation rules and other market rules when demand is 
nearing the amount of available supply. When supplies are short 
relative to demand and reliability is threatened, market rules that 
limit the market price may have the unintended effect of making demand 
response less attractive to its providers. The Commission seeks comment 
on four potential ways to modify mitigation rules to allow the market 
price to better reflect the value of lost load in an emergency 
situation.
    76. One way to address this issue to require that RTOs and ISOs 
increase the energy bid caps and price caps above the current levels 
only during an emergency. When the market price is constrained, it is 
not possible to distinguish customers who place a high value on 
uninterrupted electric service from other customers who would reduce 
demand rather than pay a price that reflects that high value. An 
emergency situation typically occurs when a system faces a shortage of 
operating reserves--a reliability standard violation. Demand for energy 
in the real-time market then competes with the need for spare 
generation for operating reserves to maintain grid reliability. To 
maintain operating reserves, electric energy service must be reduced 
immediately, either by prorating the load reduction across all 
customers or by using the market price to allocate the limited energy 
available to those who value it most. In defined periods of tight 
supply, PJM's market rules remove sellers' bid caps, but keep the 
market-wide $1,000 per MWh offer cap. If the market-wide cap was also 
raised, the

[[Page 36287]]

real-time market could clear at a price above the current cap, 
customers could decide whether to purchase energy at this higher price, 
and those who place a higher value on energy could continue to buy it 
while those who do not value it as highly could reduce their demand. 
All bid caps could be raised to a high level, for example, when ten-
minute operating reserves are about to drop below required levels. 
Raising caps in an emergency would allow each customer to decide the 
value of its own lost load. To use this method, an RTO and ISO would 
have to establish market rules to specify the emergency conditions for 
raising the caps and the higher bid levels allowed. RTO and ISO markets 
would have to establish procedures for vigorous oversight and 
monitoring for the exercise of market power during a system shortage.
    77. The Commission requests comment on this proposal to raise 
energy bid caps and market-wide caps in an emergency, and on what 
operating conditions should constitute an emergency shortage.
    78. A second way to allow the market price to reduce demand during 
an emergency is to raise bid caps above the current level only for 
demand bids \68\--the offers by buyers to purchase a certain amount of 
energy at a given price--in the day-ahead and real-time markets, while 
keeping generation bid caps in place. That is, a buyer would be allowed 
to inform the RTO or ISO about how much energy it would purchase at 
various prices above the current bid caps. Under this proposal, such 
high demand bids would not only be allowed but also would be allowed to 
set the market price if they clear the market.\69\ The high market 
price under this approach would create an incentive for all buyers to 
lower their demands during an emergency. To the extent the buyers are 
not also sellers, this approach raises fewer concerns about market 
power than the first approach, which raises bid caps for all market 
participants. The Commission requests comment on whether this method 
would be more effective, less subject to the exercise of market power, 
or otherwise easier to implement than raising all bid and price caps.
---------------------------------------------------------------------------

    \68\ A demand bid is different from a demand reduction bid. The 
first is an offer by a potential purchaser to buy a certain amount 
of energy at a given market price, and the second is an offer by a 
purchaser to reduce his normal purchase by a given amount in return 
for compensation.
    \69\ For example, a demand bid of $1,500 could set the market 
price under the following conditions. If there is not enough 
generation capacity to meet all demand after the RTO or ISO reserves 
enough generating capacity to meet ancillary service requirements 
and if there is just enough generating capacity to meet the 
combination of: (1) All ancillary service requirements, (2) all 
price-insensitive demand (i.e., buyers who are willing to purchase 
energy at any price), and (3) all demand with price bids above 
$1,500 per MWh, the market would clear at a price of $1,500 per MWh. 
In this case, a demand bid of $1,500/MWh would set the market price. 
Buyers bidding less than this price for all or part of their total 
demand are in effect choosing not to purchase energy for $1,500 per 
MWh, and thus would have to reduce their demand accordingly. All 
other buyers would receive their requested energy.
---------------------------------------------------------------------------

    79. A third way to allow the market price to reduce demand during 
an emergency is to require a demand curve for operating reserves in 
each RTO or ISO market. Under this approach, when available generating 
capacity falls short of combined energy demand and operating reserve 
requirements, the market price for energy and operating reserves would 
increase to specified levels (typically above the market-wide seller 
offer cap) and the price level would increase with the severity of the 
shortage. This approach would ensure that market prices reflect tight 
conditions on the grid without altering any of the market power 
mitigation restrictions on either supply or demand bids. The market 
rules in NYISO and ISO-NE include a demand curve for operating reserves 
that sets the real-time market price when operating reserves are low. 
These rules are intended to help assure reliability by reducing demand 
significantly during a shortage. The Commission could require each RTO 
and ISO to establish market rules that set real-time market prices at 
specific pre-determined values during an emergency when operating 
reserves are low. The Commission requests comment on whether it should 
require all ISOs and RTOs to adopt such a demand curve, how to set its 
parameters, and how to apply these rules to any local shortages with 
high locational prices that do not have a significant effect throughout 
the entire RTO or ISO region. In particular, how should an emergency be 
defined now that mandatory reliability rules are in effect?
    80. A fourth way to allow the market price to reduce demand during 
an emergency is to set the market-clearing price at the payment made to 
participants in an emergency demand response program, described above. 
For example, if payments to participants in emergency demand response 
programs are set at $500 per MWh, the market-clearing price when these 
resources are called would be set at $500 per MWh. This approach would 
avoid the problem caused by the drop in market price that results from 
calling on an emergency demand response provider, which sends the wrong 
price signal to both suppliers and consumers. To implement this 
approach, the Commission would propose to amend RTO and ISO market 
rules to allow the payment to emergency demand response providers to 
set the market-clearing price for all supply and demand resources 
dispatched. RTOs and ISOs would have to amend their market rules on 
unit commitment and settlement to adjust wholesale energy prices 
outside the normal clearing process. RTOs and ISOs may also have to 
review and adjust the emergency conditions under which these emergency 
demand response resources would be called.
    81. The Commission requests comment on these four ways to allow the 
market price to reduce demand during an emergency. Should any be used 
and, if so, which way or combination of ways would be most beneficial? 
For any of these ways to allow the market price to elicit demand 
reduction during an emergency, the Commission requests comments on 
whether it should require a specific method, or, given the differences 
in market design among the RTOs and ISOs, adopt the general requirement 
and direct each RTO and ISO to develop its own compliance mechanism.
    82. Finally, as discussed above, some RTOs and ISOs have quantified 
the cost-effectiveness of demand response in their wholesale power 
markets. The Commission requests comments on whether it should require 
all RTOs and ISOs to do this for their markets that have demand 
response.

IV. Long-Term Power Contracting in Organized Markets

    83. Competitive wholesale markets need a strong infrastructure--
both adequate electricity supply and a robust interstate transmission 
grid. Long-term contracts are an important tool to achieve and maintain 
a strong power infrastructure, particularly for new entrants into the 
generation sector and especially for many renewable energy developers. 
Long-term contracts are important to effective competition both in 
regions with organized wholesale markets and in regions without 
organized markets. Competitive solicitation is a sound vehicle to 
support long-term contracts in regions with and without organized 
markets. Order No. 890 and long-term firm transmission rights support 
long-term transmission service contracts in both kinds of regions. In 
this proceeding, the Commission proposes additional steps to facilitate 
opportunities for long-term power contracting in organized markets. 
Although long-term contracts are important in all regions, the

[[Page 36288]]

Commission has a special responsibility in organized markets to ensure 
that our market rules support long-term contracting. The Commission 
seeks comment on whether there are additional steps that can be taken 
to support increased long-term contracting. The Commission discusses 
below the advantages of long-term power contracting in organized market 
regions and various factors that affect the degree to which such 
contracts are executed. The Commission then considers potential steps 
that could facilitate greater long-term power contracting in organized 
market regions, such as encouraging or requiring development of 
standardized long-term products and providing greater market 
transparency by posting on the internet information about recent long-
term power contracts and offers for future long-term sales and 
purchases. Given the importance of long-term contracts to development 
of the strong infrastructure necessary to support competitive markets, 
the Commission also recognizes the need to provide contract certainty. 
The Commission believes it can discharge its legal duties under the FPA 
while providing contract certainty.

A. Importance of Long-Term Power Contracts and Factors Affecting 
Contracting Decisions by Buyers and Sellers

    84. The Commission believes that the organized market regions 
facilitate long-term contracting in several ways, such as eliminating 
pancaked rates for long distance power sales, eliminating internal loop 
flow problems that might otherwise lead to unplanned curtailment of 
long distance transmission service, and ensuring reliable transmission 
operation over a large area that encompasses many potential sellers and 
buyers of long-term power. These and other features of RTO and ISO 
transmission services expand the geographic scope of markets available 
to sellers and buyers of long-term power. Our goal here is to further 
improve opportunities for long-term contracting in RTO and ISO regions.
    85. It is important that wholesale sellers and buyers have adequate 
opportunities to sell and buy electric power through long-term power 
contracts to allow them to manage their exposure to uncertain future 
spot market prices. Sellers and buyers should also have the opportunity 
to sell and buy electric power in the spot market. The Commission 
believes that it is important for buyers and sellers in organized 
markets to be able to choose a portfolio of short-term, intermediate-
term, and long-term power supplies. Having portfolio choice allows 
market participants to manage the risk that comes from uncertainty. 
Forward power contracting by buyers combined with purchases from a spot 
market with demand response can be an efficient and low-cost way of 
meeting customer needs because both buyers and sellers can hedge risk 
as well as adapt to actual real-time supply and demand conditions. 
Competitive forward power contracting allows many sellers to compete to 
provide electric service, and greater reliance on long-term power 
contracting could decrease the incentive for sellers to exercise market 
power in the spot market if there is reduced opportunity to profit from 
such action.
    86. At the Commission's technical conference on May 8, 2007, 
speakers on the long-term power contracting panel agreed that long-term 
power contracts are important to a well functioning electric 
market.\70\ Customers argued that long-term contracts are essential to 
providing price stability and supporting the adequacy of supply over 
the long run.\71\ Sellers argued that long-term contracts are important 
and often essential to financing new generation sources.
---------------------------------------------------------------------------

    \70\ Transcript of Conference at 111, Conference on Competition 
in Wholesale Power Markets, Docket No. AD07-7-000 (May 8, 2007).
    \71\ Id. at 107.
---------------------------------------------------------------------------

    87. Customers and sellers differed sharply, however, on the nature 
and extent of any impediments to long-term contracts. Customers argued 
that suppliers are reluctant to sell power under long-term contracts at 
a price attractive to those customers.\72\ They argued that the 
presence of liquid spot markets gives suppliers an incentive to sell 
most of their output on a daily or hourly basis, not through long-term 
contracts. By contrast, suppliers and their representatives said they 
are willing to sign long-term power contracts but asserted that buyers 
simply do not want to pay the long-term cost of power. In particular, 
they alleged that customers do not want to pay enough to finance new 
generation and any needed transmission investment. With respect to 
existing assets, suppliers argued that customers often want a price 
pegged to a particular fuel (e.g., coal or nuclear), even if that price 
does not reflect the long-term market value of electric power.
---------------------------------------------------------------------------

    \72\ See, e.g., Post-Technical Conference Comments of the 
American Public Power Association, Docket No. AD07-7-000 (Mar. 13, 
2007); Supplemental Comments of the Electricity Consumers Resource 
Council, Docket No. AD07-7-000 (Mar. 12, 2007).
---------------------------------------------------------------------------

B. Commission Actions To Support Long-Term Power Contracts

    88. The Commission fully supports reliance on long-term contracts 
to provide price stability, hedge risk, and support financing for new 
investments. In this regard, the Commission has taken a number of steps 
to facilitate long-term contracting. The Commission adopted a final 
rule on long-term transmission rights for organized market regions in 
Order No. 681.\73\ The assurance of long-term transmission availability 
at a predictable cost is an important component of a buyer's decision 
to sign a long-term power contract with a distant supplier.
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    \73\ Long-Term Firm Transmission Rights in Organized Electricity 
Markets, Order No. 681, 71 FR 43,564 (August 1, 2006), FERC Stats. & 
Regs. ] 31,226, order on reh'g, Order No. 681-A, 117 FERC ] 61,201 
(2006).
---------------------------------------------------------------------------

    89. Also, the Commission adopted transmission planning reforms in 
Order No. 890. These reforms provide an open and transparent process 
for wholesale entities and transmission providers to plan for the long-
term needs of their customers, including making transmission 
investments that can support long-term contracts for generation.
    90. The Commission has also sought to lower barriers to entry for 
new generation that can support long-term contracts. In a series of 
orders (Order Nos. 2003, 2006, and 661),\74\ the Commission adopted 
interconnection rules for large, small, and wind generators that 
provide a known and stable process for requesting interconnection, 
receiving timely responses from transmission service providers, and 
determining who pays for various costs associated with the 
interconnection process and facilities. The Commission also reformed 
capacity

[[Page 36289]]

markets in several regions to shift reliance from short-term purchases 
to forward markets held sufficiently in advance of delivery (e.g., 
three years) to be more consistent with the time necessary to construct 
new generation.\75\
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    \74\ Standardization of Generator Interconnection Agreements and 
Procedures, Order No. 2003, FERC Stats. & Regs., Regulations 
Preambles 2001-2005 ] 31,146 (2003), order on reh'g, Order No. 2003-
A, FERC Stats. & Regs., Regulations Preambles 2001-2005 ] 31,160, 
order on reh'g, Order No. 2003-B, FERC Stats. & Regs., Regulations 
Preambles 2001-2005 ] 31,171 (2004), order on reh'g, Order No. 2003-
C, FERC Stats. & Regs., Regulations Preambles 2001-2005 ] 31,190 
(2005), aff'd sub nom. Nat'l Ass'n of Regulatory Util. Comm'rs v. 
FERC, 475 F.3d 1277 (D.C. Cir. 2007); Standardization of Small 
Generator Interconnection Agreements and Procedures, Order No. 2006, 
FERC Stats. & Regs., Regulations Preambles 2001-2005 ] 31,180, order 
on reh'g, Order No. 2006-A, FERC Stats. & Regs., Regulations 
Preambles 2001-2005 ] 31,196 (2005), order granting clarification, 
Order No. 2006-B, FERC Stats. & Regs. ] 31,221 (2006), appeal 
pending sub nom. Consolidated Edison Co. of New York, Inc., et al. 
v. FERC (U.S.C.A., D.C. Circuit, Docket Nos. 06-1018, et al.); 
Interconnection for Wind Energy, Order No. 661, FERC Stats. & Regs., 
Regulations Preambles 2001-2005 ] 31,186, order on reh'g, Order No. 
661-A, FERC Stats. & Regs., Regulations Preambles 2001-2005 ] 31,198 
(2005).
    \75\ See Devon Power L.L.C., 115 FERC ] 61,340, order on reh'g, 
117 FERC ] 61,133 (2006); PJM Interconnection, L.L.C., 117 FERC ] 
61,331 (2006).
---------------------------------------------------------------------------

    91. Through this ANOPR the Commission intends to consider whether 
there are other concrete steps that can be taken to facilitate long-
term contracting.

C. Proposed Commission Actions To Facilitate Long-Term Power 
Contracting

    92. The Commission seeks comments on any concrete steps it can take 
to facilitate voluntary long-term power contracting in organized market 
regions. In seeking comment on this issue, however, the Commission is 
mindful of the limits of its jurisdiction. The Commission cannot compel 
buyers and sellers to enter into long-term contracts, and the 
purchasing practices of LSEs are often dictated by state policies, not 
those of this Commission.
    93. Based on the comments received in the technical conferences and 
other actions being considered in various markets, the Commission seeks 
comment on whether it should:
     Provide greater market transparency by requiring RTOs and 
ISOs to post information that could facilitate long-term contracts, 
such as by aggregating and posting information on long-term contract 
prices and quantities on a periodic basis. Would this information prove 
helpful to buyers and sellers? If so, how could the information be 
reported in a way that protects the confidentiality of individual 
contracts? Would other information be helpful to long-term contracting, 
such as the posting of estimates of transmission constraints and 
congestion costs on a long-term basis?
     Require or encourage efforts to develop new standardized 
forward products. Would standardized products better facilitate long-
term contracting? If so, what role should the Commission play? Should 
it encourage RTOs or ISOs to play an active role in this area or would 
that place them in a position of undertaking commercial functions? Is 
this a role better played by NAESB or other industry groups?
     Take other steps such as having a dedicated portion of the 
ISO or RTO Web site for market participants to post offers to buy or 
sell power long-term? Would this prove helpful or is it a service that 
is better provided by the market?
    94. Further, the Commission requests comments on whether we should 
consider any modification of the data requirements of the Electric 
Quarterly Report (EQR)--for example, to report the start date, term, 
and end date of long term power contracts--to provide information that 
would make transparent the average prices of long term power contracts 
of various terms and vintages.

V. Market Monitoring Policies

    95. Market monitors have played an integral role in the organized 
electric markets since the latter's inception, providing valuable 
reporting and analysis services not only to the Commission, but also to 
the RTOs and ISOs, to market participants, and to state commissions. In 
light of their importance, the Commission has required that all RTOs 
and ISOs incorporate a market monitoring function.\76\
---------------------------------------------------------------------------

    \76\ Order No. 2000, FERC Stats. and Regs., Regulations 
Preambles July 1996-December 2000 ] 31,089 at ] 31,016 (regarding 
RTOs).
---------------------------------------------------------------------------

    96. Market monitoring units (MMUs) take different forms and perform 
differing functions, depending on the individual tariffs of their 
respective RTO or ISO. The span of years over which market monitors 
have been in existence has given the Commission and others in the 
industry a track record upon which to evaluate the appropriate roles 
MMUs should play and the protections that might be adopted to assist 
them in performing those roles. Based both on our own experience with 
MMUs and on concerns raised by many interested entities, the Commission 
decided to initiate a comprehensive review of its market monitoring 
policies. To that end, the Commission held a technical conference on 
April 5, 2007, and received comments from 29 entities and individuals.
    97. The Commission has considered those comments and drawn on our 
own extensive interaction with market monitors in formulating a 
proposed set of market monitoring policies. In this ANOPR, the 
Commission solicits comments and suggestions from the industry 
regarding these proposals.

A. History of Market Monitoring

1. Order No. 2000
    98. The Commission undertook its first generic consideration of 
market monitoring in Order No. 2000, which was issued in 1999 to 
encourage the formation of RTOs. In that Order, the Commission required 
an RTO to include market monitoring as one of its minimum functions, 
and to submit a market monitoring plan as part of its RTO proposal. The 
Order did not, however, impose a specific MMU structure on the 
RTOs.\77\
---------------------------------------------------------------------------

    \77\ Prior to this first generic consideration of MMUs, the 
Commission addressed market monitoring in connection with individual 
RTO/ISO proposals. See Pacific Gas and Electric Co., 77 FERC ] 
61,265 (1996), order on reh'g, 81 FERC ] 61,122 (1997), order on 
clarification, 83 FERC ] 61,033 (1998) (requiring the ISO to file a 
detailed monitoring plan and listing minimum elements for such a 
plan); Pennsylvania-New Jersey-Maryland Interconnection, 81 FERC ] 
61,257 (1997) (PJM Formation Order) (requiring PJM to develop a 
market monitoring program to evaluate market power and design 
flaws).
---------------------------------------------------------------------------

    99. The Commission noted in Order No. 2000 that while MMUs were not 
intended to supplant Commission authority, they should be designed in 
such a way as to provide the Commission with an additional means of 
detecting market power abuses, market design flaws and opportunities 
for improvements in market efficiency.\78\ The Commission ordered RTOs 
to incorporate in their market monitoring plans certain standards to be 
met by the MMUs, which include ensuring objective information about the 
markets that the RTO operates or administers, proposing appropriate 
action regarding opportunities for efficiency improvement, identifying 
market design flaws or market power abuses, and evaluating whether 
market participants comply with market rules.\79\ The Commission 
observed that the information to be gleaned from market monitoring 
would be beneficial not only to the Commission, but also to state 
commissions and market participants.\80\
---------------------------------------------------------------------------

    \78\ Order No. 2000, FERC Stats. & Regs., Regulations Preambles 
July 1996-December 2000 ] 31,089 at ] 31,156.
    \79\ Id.
    \80\ Id.
---------------------------------------------------------------------------

2. Market Behavior Rules Order
    100. The Commission next addressed the role of market monitors in 
its 2003 Order Amending Market-Based Rate Tariffs and 
Authorizations,\81\ issued in connection with the promulgation of 
Market Behavior Rules applicable to entities possessing market-based 
rate authority. In that order, the Commission clarified the duties of 
MMUs in connection with enforcement matters, directing that MMUs refer 
compliance issues to the Commission and limiting direct enforcement 
action by the MMUs to objectively identifiable and

[[Page 36290]]

sanctioned behavior expressly set forth in the RTO/ISO tariffs.\82\
---------------------------------------------------------------------------

    \81\ Investigation of Terms and Conditions of Public Utility 
Market-Based Rate Authorizations, 105 FERC ] 61,218 (2003) (Market 
Behavior Rules), order on reh'g, 107 FERC ] 61,175 (2004) (Market 
Behavior Rules Rehearing Order).
    \82\ Market Behavior Rules, 105 FERC ] 61,218 at P 182, 184.
---------------------------------------------------------------------------

    101. In its subsequent Order on Rehearing, the Commission clarified 
that MMU personnel were not a substitute for Commission enforcement 
staff.\83\ Rather, the Commission held that MMUs were to provide 
information to the Commission and its staff, so that the Commission 
could take appropriate action under the FPA. The Commission also 
announced the intention to make a thorough evaluation of the 
appropriate role of MMUs, which would lead to the issuance of a policy 
statement on the subject.\84\
---------------------------------------------------------------------------

    \83\ Market Behavior Rules Rehearing Order, 107 FERC ] 61,175 at 
P 165.
    \84\ Id. P 168.
---------------------------------------------------------------------------

3. Policy Statement
    102. The Commission issued the Policy Statement on Market 
Monitoring Units in May of 2005.\85\ In this Policy Statement, the 
Commission identified four tasks which MMUs perform,\86\ and for which 
they needed access to data and other resources.\87\ Those duties were 
listed as follows:
---------------------------------------------------------------------------

    \85\ Market Monitoring Units in Regional Transmission 
Organizations and Independent System Operators, 111 FERC ] 61,267 
(2005) (Policy Statement).
    \86\ Id. P 2.
    \87\ Id. P 3.
---------------------------------------------------------------------------

    a. To identify ineffective market rules and tariff provisions and 
recommend proposed rule and tariff changes to the ISO or RTO that 
promote wholesale competition and efficient market behavior.
    b. To review and report on the performance of wholesale markets in 
achieving customer benefits.
    c. To provide support to the ISO or RTO in the administration of 
Commission-approved tariff provisions related to markets administered 
by the ISO or RTO (e.g., day-ahead and real-time markets).
    d. To identify instances in which a market participant's behavior 
may require investigation and evaluation to determine whether a tariff 
violation has occurred, or which may be a potential Market Behavior 
Rule violation, and immediately notify appropriate Commission staff for 
possible investigation.
    103. In an Appendix to the Policy Statement, the Commission set 
forth detailed Protocols for the MMUs to follow in referring potential 
tariff or Market Behavior Rule violations to the Commission.\88\ This 
Policy Statement, together with the Protocols it incorporates, 
represents the last generic pronouncement by the Commission on the 
duties of MMUs.
---------------------------------------------------------------------------

    \88\ Id. at Appendix A. The Market Behavior Rules extant at the 
time of the Policy Statement have since been in part rescinded, with 
the remainder codified. See Conditions for Public Utility Market-
Based Rate Authorization Holders, Order No. 674, FERC Stats. & Regs. 
] 31,208 (2006). Rescinded Market Behavior Rule 2 has been replaced 
by the Commission's Anti-Manipulation Rules. See Prohibition of 
Energy Market Manipulation, Order No. 670, FERC Stats. & Regs. ] 
31,202 (Market Manipulation Order), order on reh'g, 114 FERC ] 
61,300 (2006).
---------------------------------------------------------------------------

    104. In 2006, PJM Interconnection, L.L.C. (PJM) filed proposed 
revisions to the MMU sections of its tariff, with the general aim of 
conforming its tariff to the provisions of the Policy Statement. 
Several parties filed comments, declaring a need to safeguard and 
advance the independence, clarity of function, and transparency of the 
MMU. The commenters argued that PJM's tariff should contain a clear 
statement of the MMU's independence, and should set forth all the rules 
relevant to the responsibilities and functions of the MMU. In the Order 
on Rehearing and Compliance Filing, the Commission noted that these 
concerns were of a generic nature and not necessarily limited to 
PJM.\89\ The Commission decided to initiate a generic review of our MMU 
policies and announced that it would hold a technical conference to 
explore the issues raised by the commenters.\90\
---------------------------------------------------------------------------

    \89\ PJM Interconnection, L.L.C., 117 FERC ] 61,263, at P 19 
(2006) (PJM Tariff Rehearing Order).
    \90\ Id. P 20.
---------------------------------------------------------------------------

4. Technical Conference
    105. The Commission held the technical conference on market 
monitoring policies on April 5, 2007. At the conference, the 
Commissioners heard from interested commenters on the following general 
subjects: the development of the concept and functions of market 
monitoring, the MMUs' role with respect to the Commission, the MMUs' 
role with respect to ISOs and RTOs, and the MMUs' role with respect to 
the various stakeholders such as states, generators, transmission 
providers, and customers.\91\
---------------------------------------------------------------------------

    \91\ Review of Market Monitoring Policies, Second Notice of 
Technical Conference, Docket No. AD07-8-000 (2007).
---------------------------------------------------------------------------

    106. Two principal issues received the bulk of attention from the 
commenters at the technical conference. Those were: (i) The need for, 
and suggested methods of achieving, independence on the part of MMUs so 
they can perform their assigned functions; and (ii) the content and 
proper recipients of the market data and analysis developed by the 
MMUs. Every commenter touched upon these issues in one fashion or 
another.
    107. The Commission is mindful of the fact that both independence 
and information sharing raise complex concerns, which require a careful 
weighing of the needs of various interests and constituencies. 
Nonetheless, the Commission is in general agreement with the importance 
both of safeguarding MMU independence and ensuring useful and 
transparent market analysis by the MMUs. Indeed, since the very 
beginnings of market monitoring, the Commission has emphasized the 
importance of independence and objectivity on the part of market 
monitors,\92\ and has required that MMUs analyze and report on any 
inefficiencies and structural flaws they detect in the market.\93\ In 
our own independent review of our market monitoring policies, the 
Commission has identified concerns which also fall within both these 
areas. Therefore, in this ANOPR, the Commission structures the 
proposals for modifying and standardizing the market monitoring 
function within these two general categories.
---------------------------------------------------------------------------

    \92\ PJM Formation Order, 81 FERC at 62,282; Order No. 2000, 
FERC Stats. & Regs., Regulations Preambles July 1996-December 2000 ] 
31,089 at 31,061.
    \93\ PJM Formation Order, 81 FERC at 62,282; Order No. 2000, 
FERC Stats. & Regs., Regulations Preambles July 1996-December 2000 ] 
31,089 at 31,156.
---------------------------------------------------------------------------

B. Independence and Function

    108. The functions MMUs are expected to perform, as well as the 
independence needed to carry out those functions, have always been 
critical concerns in discussions of market monitoring. There were some 
differences of opinion expressed at the technical conference regarding 
the appropriate functions MMUs should perform, but virtually every 
commenter agreed with the need for independence. The commenters, 
however, offered many varying proposals as to how to achieve that goal, 
as well as how to provide for MMU accountability. The Commission 
believes that there are several means by which to balance independence 
and accountability on the part of MMUs, and therefore proposes a 
balanced and flexible approach to the problem which includes oversight 
protection, tariff safeguards and tools, and the elimination of 
conflicts of interest. The Commission also proposes certain changes in 
the functions MMUs are expected to perform, which we believe will 
strengthen both their independence and accountability. We

[[Page 36291]]

solicit comments regarding our proposed changes, as well as comments as 
to whether the MMUs' existing functions need to be clarified and 
whether MMUs should perform any additional functions.
1. Structure and Tools
    109. The Commission has never required that MMUs conform to any 
standardized organizational structure. As a result, RTOs and ISOs have 
developed varying structural relationships between themselves and their 
MMUs. PJM, for instance, has an internal market monitor; MISO has an 
external market monitor, and the other RTOs and ISOs have hybrid 
structures. Some commenters at the technical conference favored an 
internal market monitor, one whose personnel are employees of the RTO 
or ISO. These commenters contended that such employees are closer to 
the actual operations of the RTO or ISO and as a result have better 
access to information. Other commenters favored an external market 
monitor, an independent contractor who is hired by the RTO or ISO. 
These commenters contended that such an entity inherently has more 
independence from the RTO or ISO than do employees of the organization. 
However, most commenters were of the opinion that the particular 
structural relationship between the MMU and the RTO or ISO was of 
secondary importance, provided that the RTO/ISO tariff contained 
provisions ensuring independence on the part of the MMU.
    110. From our own experience, the Commission has observed no 
appreciable difference among the performance of the market monitors 
that can be attributed to whether they are external or internal to 
their RTO or ISO. The Commission therefore declines to impose a ``one 
size fits all'' approach toward the structure of MMUs.
    111. It is axiomatic that independence can be achieved only if MMUs 
have adequate tools with which to perform their job. Therefore, the 
Commission proposes requiring each RTO and ISO to include in its tariff 
a provision imposing upon itself the obligation to provide its MMU with 
access to market data, resources, and personnel sufficient to enable 
the MMU to carry out its functions.\94\ In addition, the tariff should 
include a provision directing the MMU to report to the Commission any 
concerns it has with inadequate access to market data, resources, or 
personnel, and describe the steps it has taken with the RTO or ISO to 
resolve these concerns. We also seek comment on the question of how 
independence on the part of MMUs can best be achieved.
2. Oversight
    112. As several commenters pointed out at the technical conference, 
there is an inherent tension in a structure that requires MMUs to 
report to RTO/ISO management yet, at the same time, perform evaluations 
and issue reports that may be critical of that management. For example, 
MMUs are expected to evaluate and report on RTO/ISO market designs and 
performance, and to include RTO/ISO operations in their analyses of 
market flaws or inefficiencies. Further, if an MMU detects a potential 
tariff violation on the part of its RTO or ISO, it is obligated to 
bring the matter to the attention of the Commission. It can be 
difficult for an MMU to discharge these oversight and reporting 
obligations effectively unless it has some degree of independence from 
RTO/ISO management. Such a reporting relationship can create a conflict 
of interest because the MMU may temper its opinions out of deference to 
management, or those opinions may be overruled by management. 
Importantly, these concerns can be present whether the MMU personnel 
are in an internal or external structural relationship to their RTO or 
ISO.
    113. Therefore, the Commission proposes that each RTO and ISO, in 
addition to maintaining a market monitoring function, be required to 
have its MMU report either directly to the RTO's or ISO's board of 
directors or directly to a committee of independent board directors. 
This requirement would apply to all structural types of MMU, whether 
internal, external or a hybrid combination of the two.\95\ The 
Commission is of the view that it has the authority to impose this type 
of requirement on RTOs and ISOs, but seeks comment on this issue as 
well as on the proposal itself.
3. Functions
    114. The issue of independence is integrally related to the 
functions that the MMUs are expected to perform. Most of the functions 
performed by MMUs have remained relatively constant since the inception 
of market monitoring, and center around market analysis and the 
evaluation of participant behavior. Commenters at the technical 
conference were generally supportive of the functions which the 
Commission identified in its 2005 Policy Statement, with one exception 
discussed below.
---------------------------------------------------------------------------

    \94\ PJM's tariff, for instance, requires PJM to provide 
appropriate staffing for its MMU, and to ensure that the MMU has 
adequate resources, access to required information, and the 
cooperation of PJM staff. PJM Interconnection, L.L.C., FERC Electric 
Tariff, Attachment M, Section V.
    \95\ The Commission notes that, if adopted, this policy would 
mark a departure from the holding in PJM Interconnection, L.L.C., 
116 FERC ] 61,038, at P 38, order on reh'g 117 FERC ] 61,263 (2006). 
After giving due consideration to the comments submitted at the 
technical conference, and for the reasons stated above, the 
Commission believes that a generic change in policy may be 
appropriate and is therefore seeking comment on the issue.
---------------------------------------------------------------------------

    115. The MMU functions upon which there was general agreement at 
the technical conference were: (1) Identifying ineffective market rules 
and tariff provisions and recommending proposed rule and tariff 
changes, (2) reviewing and reporting on the performance of the 
wholesale markets, and (3) identifying and notifying the Commission 
staff of instances in which a market participant's behavior may require 
investigation. The Commission supports these three functions and 
proposes to continue them, with one important modification. In the 
Policy Statement, the MMUs were directed to advise the RTO or ISO of 
any recommendations for rule or tariff changes, with no mention being 
made of also advising the Commission. The Commission proposes adding 
the requirement that the MMUs also advise the Commission and other 
interested entities, which would include relevant state commissions and 
market participants. This added requirement would go a long way toward 
ensuring the transparency desired by many of the commenters. 
Furthermore, as noted above, MMUs should refer to the Commission any 
suspected rule or tariff violation committed by an RTO or ISO, as well 
as those committed by market participants.
    116. The Commission also proposes retaining the Protocols governing 
referral of potential market violations to the Commission, which are 
included as an Appendix to the Policy Statement. However, since 
issuance of the Policy Statement, Market Behavior Rule 2, referred to 
in the Protocols, has been rescinded and replaced by the Commission's 
Anti-Manipulation Rules.\96\ Therefore, violations currently to be 
referred to the Commission include conduct suspected of violating the 
Anti-Manipulation Rules, as well as tariff violations and violations of 
the remaining, codified Market Behavior Rules. In addition, the 
Commission proposes that the MMU also refer any suspected violations of 
other Commission-approved rules and

[[Page 36292]]

regulations, such as Codes of Conduct \97\ and Standards of Conduct.
4. Mitigation and Operations
    117. As mentioned, one of the four MMU functions listed in the 
Policy Statement was the source of some debate at the technical 
conference. The function in question is that of providing support to 
the RTO or ISO in the administration of its tariff, which usually takes 
the form of MMU-conducted market power mitigation.\98\ Certain 
commenters were concerned that such mitigation is being conducted 
without an adequate theoretical or empirical basis and is having a 
deleterious effect on the electric power market.
    118. The Commission does not believe this rulemaking is the 
appropriate forum to address issues of market power and mitigation. 
However, the Commission is concerned that an MMU's performance of these 
mitigation functions can compromise its independence in evaluating and 
reporting on market performance. In order for the MMU to support the 
RTO or ISO in tariff administration, it must be subordinate to RTO and 
ISO management. The operations and mitigation functions performed by 
MMUs directly affect market outcomes and performance. Because of this, 
there is an inherent conflict between an MMU reporting on market 
outcomes that the MMU itself has influenced. This conflict is of 
particular concern where the MMU has significant discretion in 
affecting offers, bids, and prices. There is significant potential for 
conflict between an MMU maintaining independence of RTO and ISO 
management and supporting tariff administration in a subordinate 
capacity. It may not be possible for MMUs to maintain independence 
while supporting tariff administration.
    119. For the foregoing reasons, the Commission believes operational 
activities affecting the market, including mitigation, are more 
properly performed by the RTOs and ISOs themselves as part of their 
responsibility to administer their Commission-approved tariffs. 
Maintaining a clear functional separation in this regard between RTOs 
and ISOs and the MMUs would free the MMUs to report objectively on 
whether the RTOs and ISOs have done an appropriate job in designing and 
administering wholesale power markets. Therefore, the Commission 
proposes requiring that MMUs refrain from assisting the RTO or ISO in 
tariff administration, from participating in RTO/ISO market operations, 
and from taking direct actions to influence the market, and instead 
concentrate on their role of providing market evaluation, reports, and 
advice.
---------------------------------------------------------------------------

    \96\ See Market Manipulation Order, FERC Stats. & Regs. ] 
31,202.
    \97\ The term ``Code of Conduct'' has been replaced by 
``Affiliate Restrictions'' in the Final Rule for Market-Based Rates 
for Wholesale Sales of Electric Energy, Capacity, and Ancillary 
Services by Public Utilities, 119 FERC ] 61,295 (2007).
    \98\ This function was not part of the original conception of 
market monitoring as expressed in Order No. 2000.
---------------------------------------------------------------------------

5. Ethics
    120. In order for an MMU to carry out its functions, an activity 
which requires disinterested objectivity, it is vital that MMU 
personnel maintain the highest ethical standards. Removal of the 
conflicts of interest noted above should go a long way toward 
facilitating the achievement of those standards. However, as a further 
safeguard, the Commission proposes imposing certain minimum ethics 
standards upon market monitor personnel, whether the MMU is internal or 
external to its RTO or ISO, in particular prohibiting such personnel 
from owning financial interests in any market participants. The 
Commission notes that all existing RTOs and ISOs have some type of 
conflict of interest or standard of conduct provision, although not 
always in their tariffs. The Commission proposes standardizing such 
provisions and requiring their inclusion in the tariffs themselves. The 
Commission solicits comments as to whether the provisions should be 
standardized and, if so, what particular provisions would be 
appropriate.
6. Tariff Provisions
    121. In order for MMUs to achieve transparency of function, the 
detailed obligations imposed upon them must be made clear and 
accessible. Likewise, the provisions safeguarding MMU independence and 
delineating MMU functions must be included in the tariffs of the RTOs 
and ISOs in order to be reviewed, approved and enforced by the 
Commission. Currently, MISO and SPP are the only RTOs or ISOs that 
centralize the MMU provisions in their tariffs.\99\ Others scatter 
their MMU provisions in multiple sections of their tariffs and in other 
documents or, in the case of NYISO, not in the tariff at all.\100\ The 
Commission proposes that each RTO and ISO set forth all its provisions 
involving market monitoring in one section of its tariff.

C. Information Sharing

    122. As noted in the Policy Statement, a key function which MMUs 
are expected to perform is that of analyzing the markets to determine 
if they are competitive, and proposing actions which might be useful in 
eliminating design flaws. Although RTOs and ISOs are subject to the 
exclusive jurisdiction of the Commission, we recognize the relationship 
between wholesale and retail markets. The Commission also recognizes 
the state commission interest in the performance of wholesale power 
markets. In Order No. 2000, the Commission acknowledged that 
information developed by MMUs would be beneficial not only to itself, 
but to others as well.\101\ However, inasmuch as there is a wealth of 
data gathered by MMUs, it is important to identify the types of 
information that each constituency needs to assist it in performing its 
tasks. The Commission favors both a fuller sharing of information and 
identification of the relevant information desired, so that the needs 
of the Commission, the state commissions, market participants, and the 
public may be satisfied.
1. Information Needs
    123. Representatives of state commissions and several other 
interested parties submitted comments at the technical conference 
expressing their desire to receive more information from the MMUs. The 
state commission representatives argue that they need such information 
to assist them in performing their regulatory functions, given the 
integral relationship between wholesale and retail rates. The 
Commission is sympathetic to these requests. The Commission recognizes 
that state commissions are not stakeholders, but a separate class from 
market participants. As noted above, although RTOs and ISOs are subject 
to the exclusive jurisdiction of the Commission, state commissions have 
a legitimate interest in the performance of wholesale power markets. 
However, their requests for information must be balanced, in some 
cases, against confidentiality concerns. Public disclosure of certain 
information, such as participant-specific offers or cost data, could 
harm market participants or could facilitate collusion under some 
circumstances. The Commission must therefore balance state concerns

[[Page 36293]]

regarding information access with these countervailing confidentiality 
concerns.
    124. The comments submitted at the technical conference did not 
identify the particular categories of information needed by state 
commissions. The Commission therefore proposes below general areas of 
information which it believes could be provided to the states without 
jeopardizing the need for confidentiality on the part of market 
participants. The Commission requests comments as to whether our 
proposal meets the needs of the state commissions, and whether there 
are other kinds of information that are needed by state commissions to 
fulfill their regulatory responsibilities. We further request comment 
on whether there is a generic standard or test that could be used to 
determine what specific information should be provided to a state 
commission. The Commission also proposes that some, but not all, of the 
information to be supplied to the state commissions also be made 
available to market participants. Finally, the Commission sets forth 
the information which it believes must remain protected, and solicits 
comment on whether harm could result from our proposed information 
disclosures.
2. Information To Be Provided
    125. The Commission proposes that MMUs be required to report 
comprehensively on aggregate market and RTO/ISO performance on a 
regular basis, no less frequently than quarterly, to the Commission 
staff, to staff of interested state commissions, and to the management 
and board of directors of the RTOs and ISOs. The MMUs would be required 
to deliver materials supporting their conclusions, and make one or more 
of their staff members available for a conference call attended by 
representatives of these constituencies. During this process, the MMU 
representative would be expected to work cooperatively to develop any 
further materials which might be useful to the Commission, to the state 
commissions and to the RTOs and ISOs. The Commission envisions that 
such combined reporting and conference calls would permit targeted 
requests for information and encourage a fuller exchange of relevant 
data than may be provided in the MMUs' yearly State of the Market 
reports, which are currently required by tariff or the internal 
policies of all the RTOs and ISOs.
---------------------------------------------------------------------------

    \99\ Midwest Independent Transmission System Operator, Inc., 
Open Access Transmission and Energy Markets Tariff, Module D; 
Southwest Power Pool, Inc., Open Access Transmission Tariff, 
Attachments AG, AH.
    \100\ NYISO's market monitoring plan is available on its Web 
site and may be found at http://www.nyiso.com/public/documents/tariffs/market_services.jsp
.

    \101\ Order No. 2000, FERC Stats. & Regs., Regulations Preambles 
July 1996-December 2000 ] 31,089 at 31,156.
---------------------------------------------------------------------------

    126. The Commission cautions that such reports and meetings are in 
no way intended to restrict the MMU from meeting individually with 
Commission staff, staff of state commissions, market participants, or 
other stakeholders, or sharing information with these various 
constituencies, subject to appropriate restrictions on confidentiality. 
The Commission is of the view that, in general, as much helpful and 
appropriate information about the performance of RTO/ISO markets as 
possible should be made public.
    127. The Commission proposes that offer and bid data, without 
identification of the market participants, be posted on the RTO's or 
ISO's Web site, where it will be available to the Commission, to 
interested state commissions, and to stakeholders. The Commission 
proposes a lag of three months for posting this data and solicit 
comments as to whether that time period is sufficient to protect 
commercially sensitive data and to guard against misuse of the data.
3. Tailored Requests for Information
    128. The Commission proposes that state commissions may make 
requests for additional information from the MMUs. The Commission 
understands that information such as general analyses of the market and 
aggregated price data may assist state commissions in performing their 
regulatory functions, and believes reasonable requests along those 
lines may be appropriate. The Commission seeks comment on how to 
structure this proposal to ensure that the information requests are 
useful to the states, while at the same time respectful of the limited 
resources of the MMUs, and how to ensure confidentiality with respect 
to certain market data.
    129. The Commission believes that the foregoing proposal allowing 
states to request tailored information should be for information 
regarding general market trends and performance, not information 
designed to aid state enforcement or related actions against individual 
companies. States have their own enforcement agencies which are more 
properly employed for such tasks. The limited resources of the MMUs 
should be confined to providing information regarding the workings of 
the market itself and identifying any structural flaws which the MMUs 
think should be addressed.\102\ However, a state commission would 
remain free, on a case-by-case basis, to request that the Commission 
authorize the release of otherwise proscribed data. The Commission 
would evaluate any such request to determine if it demonstrates a 
compelling need for the requested information, and decide whether 
adequate protections can be fashioned for commercially sensitive 
material.
---------------------------------------------------------------------------

    \102\ However, if during the ordinary course of its activities 
an MMU were to discover evidence of wrongdoing that was within a 
state commission's jurisdiction, it is expected that the MMU would 
report such information to the state commission.
---------------------------------------------------------------------------

4. Commission Referrals
    130. The Commission continues to believe that MMUs should respect 
the confidentiality of their referrals of suspected tariff and rule 
violations to the Commission, and not disclose such referrals to other 
entities, including state commissions.\103\ Nor does the Commission 
intend to share such information, or the result of its activities that 
are initiated based upon a MMU referral, on a generic basis. The 
Commission notes that its rules require that such information be kept 
nonpublic unless the Commission authorizes, in any given case, that it 
be publicly disclosed.\104\ Such disclosure is the exception and not 
the rule, and each such instance is carefully considered by the 
Commission with due regard to the commercially sensitive nature of the 
material and to the effect disclosure may have on the willingness of 
jurisdictional entities to file self reports with the Commission and 
otherwise cooperate in its investigations. As the Commission has 
observed previously, confidentiality provides reasonable protection to 
persons who become involved in these investigations and fosters 
cooperation with the Commission. It also protects innocent persons who 
might be erroneously alleged to have committed wrongdoing or be 
otherwise adversely affected by simply being associated with an 
investigation.\105\ The Commission notes, however, that its staff does 
give MMUs generic feedback regarding enforcement issues, and we intend 
to continue this practice in order to provide guidance in matters 
relating to their referral function.
---------------------------------------------------------------------------

    \103\ See PJM Tariff Rehearing Order, 117 FERC ] 61,263 at P 27.
    \104\ 18 CFR 1b.9 (2006). Other exceptions include cases where 
the information has been made a matter of public record in an 
adjudicatory proceeding, and where disclosure is required by the 
Freedom of Information Act, 5 U.S.C. 552 et seq. (2006).
    \105\ PJM Tariff Rehearing Order, 117 FERC ] 61,263 at P 27.
---------------------------------------------------------------------------

D. Pro Forma Tariff Section

    131. The Commission intends to include in its subsequent Notice of 
Proposed Rulemaking a proposed pro forma MMU section for the RTOs' and 
ISOs' OATTs. The Commission anticipates that each RTO and ISO may wish 
to modify certain provisions, or add others, to such pro forma tariff 
to suit its particular needs. Nonetheless, the Commission believes it 
will be useful to develop specific core provisions that are 
standardized across the various RTOs and ISOs, particularly

[[Page 36294]]

in the areas of independence, MMU functions, and information sharing. 
The Commission anticipates including in the pro forma tariff protocols 
for the referral of tariff and market manipulation violations to the 
Office of Enforcement, as well as protocols for the referral of 
perceived market design flaws and recommended tariff changes to the 
Office of Energy Markets and Reliability. The Commission solicits 
comments on the structure and content of such a pro forma section.

E. Conclusion

    132. The Commission's goal is to strengthen market monitoring, and 
we advance proposals in this ANOPR that respond to concerns expressed 
by commenters at the technical conference, as well as that reflect our 
own observations formed over the years from working within the 
framework of the existing market monitoring provisions. The Commission 
seeks comment on its proposals and on other matters germane to market 
monitoring.

VI. Responsiveness of RTOS and ISOS

    133. This section of the ANOPR addresses proposals to increase RTO/
ISO responsiveness to stakeholders. The Commission proposes one reform 
to increase the responsiveness of RTO/ISO boards and seeks comment on 
whether any other reforms are necessary.

A. The Challenge of Improving RTO and ISO Responsiveness to 
Stakeholders

    134. Order Nos. 888 and 2000 require that an ISO or RTO be 
independent from market participants. The Commission requires this 
independence to ensure that market participants have nondiscriminatory 
access to the grid and market rules are developed and administered in a 
manner that does not favor one market participant over another. After 
five to ten years of experience with several such entities, however, 
some stakeholders are concerned that RTOs and ISOs have achieved 
independence without being adequately sensitive to the needs of their 
customers and members.
    135. Given the size and complexity of RTOs and ISOs today, it is 
not surprising that tension has arisen between the goals of 
independence and responsiveness. An RTO or ISO cannot satisfy every 
group on every issue. When an RTO or ISO makes a difficult decision, 
those who support the decision often believe it has acted 
``objectively'' and ``independently,'' while those who oppose that 
decision often believe the RTO or ISO has not been ``responsive'' to 
their concerns.
    136. This natural tension between independence and responsiveness 
is compounded by the number of functions that an RTO or ISO performs 
and for which it is ultimately held accountable by these several types 
of entities. An RTO or ISO has the primary responsibility to operate 
the regional transmission system safely in accordance with good utility 
practice and reliably in accordance with Commission-approved 
reliability standards. It is responsible for providing open and non-
discriminatory transmission access under a regional transmission 
tariff. The provision of open-access transmission service in itself 
requires that many subordinate functions be carried out, such as 
maintaining an efficient transmission reservation system, scheduling 
transmission services, managing congestion on the grid, coordinating 
local transmission system enhancements, and developing the region's 
long-term transmission plan. RTOs and ISOs typically have adopted 
innovative transmission pricing mechanisms such as locational pricing 
with allocations or auctions of financial transmission rights that 
hedge transmission congestion.
    137. An RTO or ISO is also responsible for administering the 
organized energy markets. Depending on the region, there are day-ahead 
and real-time energy markets, markets for various ancillary services, 
and forward capacity markets, with provisions for ensuring that demand 
response resources can participate in these markets. It is responsible 
for all aspects of operation of these markets and for providing an 
independent market monitor. The RTO or ISO may also have 
responsibilities regarding resource adequacy. Every RTO or ISO must 
maintain a reliable system for metering and measuring power flows and 
customer services systems for billing and settling accounts for many 
large financial transactions.
    138. As an RTO's or ISO's functional responsibilities grow, some 
customers may value the new functions while others prefer the regional 
organization to focus on its original basic functions. New services 
come at a cost. Start-up costs can be significant for new services, and 
the RTO or ISO must decide how to recover the costs from its customers. 
These decisions may be controversial. In particular, determining who 
benefits from new transmission facilities and how their costs should be 
allocated can be very contentious and can lead to customer 
dissatisfaction with the RTO or ISO. Decisions related to resource 
adequacy, such as whether to adopt capacity markets or to rely more 
heavily on energy price signals to incent new generation and demand 
response, have also become very contentious.
    139. Given these challenges, the Commission is considering, as 
discussed further below, proposals to improve RTO/ISO responsiveness in 
a manner that does not compromise their independence.

B. Prior Commission Actions Regarding RTO and ISO Responsiveness

    140. In Order No. 888, the Commission encouraged but did not 
require the formation of ISOs. Order No. 888 delineated eleven 
principles defining the operations and structure of a properly 
functioning ISO.\106\ Similarly, in Order No. 2000, the Commission 
encouraged utilities to join RTOs voluntarily and set out the 
characteristics that an RTO must possess and the minimum functions that 
it must perform.\107\ Embodied in both Order Nos. 888 and 2000 is the 
requirement that the regional transmission entity be independent from 
market participants so that it can provide regional transmission and 
energy market services on a non-discriminatory basis.
---------------------------------------------------------------------------

    \106\ Order No. 888, FERC Stats. & Regs., Regulations Preambles 
January 1991-June 1996 ] 31,036 at 31,730-32.
    \107\ Order No. 2000, FERC Stats. & Regs., Regulations Preambles 
July 1996-December 2000 ] 31,089 at 30,993-94.
---------------------------------------------------------------------------

    141. Although it required independence, Order No. 2000 did not 
mandate detailed governance requirements for an RTO board of directors. 
Instead, it stated that the Commission would review governance 
proposals on a case-by-case basis.\108\ The Commission emphasized the 
importance of stakeholder input regarding both RTO formation and 
ongoing operations, and it required the RTO or ISO to consult with its 
members and other stakeholders through an advisory committee prior to 
taking action. The Commission stated that, because there is a non-
stakeholder board, it is important that this board not become 
isolated.\109\ For this reason, the Commission explained that there 
should be both formal and informal mechanisms to ensure that 
stakeholders can convey their concerns to the non-stakeholder board.
    142. The Commission also required that RTOs have an ``open 
architecture'' so that the organization and its members have the 
necessary flexibility to improve the structure, geographic scope, 
market scope, and operations of the

[[Page 36295]]

organization, as long as proposed changes continue to satisfy RTO 
minimum characteristics and functions.\110\ Stated another way, ``open 
architecture'' meant that the original RTO design could evolve as 
needed to reflect changes in member needs.
    143. Over the past few years, many RTO and ISO customers have 
raised concerns at the Commission about RTO or ISO responsiveness to 
customers on such matters as the level or growth rate of RTO or ISO 
administrative costs and the effectiveness of the customer voice in 
processes for deciding whether to undertake new expenditures. In 
response to concerns over accounting and financial reporting rules for 
RTOs and ISOs, the Commission issued a Financial Reporting Notice of 
Inquiry (NOI) on September 16, 2004. It asked for comments on RTO and 
ISO accounting matters and whether RTOs and ISOs have appropriate 
incentives to be cost-effective.\111\ This led directly to Commission 
Order No. 668, Accounting and Financial Reporting for Public Utilities 
Including RTOs.\112\ Order No. 668 amended the Commission's regulations 
to update the accounting requirements for public utilities and 
licensees, including RTOs and ISOs. Specifically, Order No. 668 created 
new financial accounts to better categorize costs and changed the 
reporting requirements for all public utilities, including RTOs and 
ISOs, to improve financial reporting of operations, revenue, and 
expense accounts. The new financial reporting requirements allow the 
Commission and other interested persons to compare public utility 
expenditures more readily than under the prior rule, which improves the 
transparency of financial information and facilitates clear 
understanding of RTO/ISO costs.\113\
    144. In addition to Commission actions, RTOs and ISOs themselves 
have undertaken efforts to improve relations and communications with 
customers and other stakeholders. For example, the CAISO has enhanced 
its participatory budget development process to allow stakeholders to 
ask questions and raise concerns well before the budget becomes final. 
PJM, at the request of its stakeholders, has introduced procedures 
under which stakeholder issues may be immediately reviewed by the 
board.\114\ PJM has also proposed to reintroduce a stakeholder 
``liaison committee''--a committee of stakeholder representatives that 
will advise the PJM board directly--and is seeking stakeholder input on 
how that committee should be structured.\115\
---------------------------------------------------------------------------

    \108\ Id. at 31,073-74.
    \109\ Id.
    \110\ Id. at 31,170.
    \111\ Financial Reporting and Cost Accounting and Recovery 
Practices for Regional Transmission Organizations and Independent 
System Operators, Notice of Inquiry, FERC Stats. & Regs. ] 35,546 
(2004).
    \112\ Accounting and Financial Reporting for Public Utilities 
Including RTOs, Order No. 668, 70 FR 77,626 (Dec. 30, 2005), FERC 
Stats. & Regs., Regulations Preambles 2001-2005 ] 31,199 (2005), 
order on reh'g, Order No. 668-A, 71 FR 28,513 (May 16, 2006), FERC 
Stats. and Regs. ] 31,215 (2006).
    \113\ Order No. 668, FERC Stats. & Regs., Regulations Preambles 
2001-2005 ] 31,199 at P 5.
    \114\ See May 4, 2007 letter from Phillip G. Harris, Chairman 
and CEO, PJM Interconnection, L.L.C., to PJM Members and 
Stakeholders, at http://www.pjm.com/committees/members/postings/20070504-letter-to-members-post.pdf.
 See also Transcript of 

Conference at 204, Conference on Competition in Wholesale Power 
Markets, Docket No. AD07-7-000 (May 8, 2007).
    \115\ Id.
---------------------------------------------------------------------------

    145. The Commission is considering below whether additional reforms 
should be adopted to further increase RTO and ISO responsiveness.

C. Proposed Commission Action To Improve RTO and ISO Responsiveness

    146. In this section, the Commission proposes reforms related to 
ISO and RTO boards and seeks comment on whether any other reforms are 
appropriate.
1. A Responsive RTO or ISO Board of Directors \116\
---------------------------------------------------------------------------

    \116\ The term ``board of directors'' is used in this ANOPR to 
refer to the highest governing body. Certain RTOs and ISOs may use 
another term. For example, the California Independent System 
Operator Corporation uses the term ``Board of Governors.''
---------------------------------------------------------------------------

    147. Customer responsiveness must begin with the RTO/ISO board. A 
well-functioning and responsible board of directors is necessary for 
establishing the strategic direction of the RTO or ISO, including 
customer orientation. Board members are expected to have the expertise 
needed to set such direction and assess whether it is being followed 
successfully. When approving an application for RTO status, the 
Commission has considered primarily the independence of board members 
in the board selection process.\117\
---------------------------------------------------------------------------

    \117\ Grid Florida, L.L.C., 94 FERC ] 61,020 (2001); Arizona 
Public Service Co., 101 FERC ] 61,033, order on reh'g, 101 FERC ] 
61,350 (2002).
---------------------------------------------------------------------------

    148. The Commission's preliminary conclusion is that 
representatives of customers and other stakeholders must have some form 
of effective direct access to the board of directors. Each RTO or ISO 
would be required to develop and implement a means to ensure that 
customers and other stakeholders have effective direct access to the 
board. The mechanism would not have to be the same for each RTO or ISO. 
One RTO or ISO might choose to form a committee of stakeholder 
representatives with some form of direct access to the board, and this 
committee may be distinct from the various technical committees that 
have already been formed. Another RTO or ISO might choose to create 
direct access by having a hybrid board of directors composed of both 
independent members and representatives of stakeholders. A third RTO or 
ISO might devise a distinct third means. However, each mechanism would 
have to be effective in allowing customers and other stakeholders to 
present their views on major issues directly to the board.
    149. The Commission seeks comment on whether RTO or ISO 
responsiveness to stakeholders requires some form of direct board 
access. If so, what steps can be taken to ensure that both majority and 
minority interests have access to the board? If not, is there a better 
way to ensure that RTO and ISO boards of directors are responsive to 
customers?
    150. The Commission stresses its intent to be flexible regarding 
how the RTOs and ISOs may improve responsiveness to stakeholders. As 
mentioned, at least two mechanisms, if carefully designed and 
implemented, could accomplish this, hybrid boards and board advisory 
committees.
    151. A hybrid board would be composed of both independent members 
and stakeholder members. Each member would have a seat on the board and 
participate fully in board decisions with an equal vote. The Commission 
believes it should be possible to structure a hybrid board that does 
not sacrifice overall board independence.\118\ Adding non-independent 
stakeholders to the board would expose the board to the concerns of 
stakeholders in the most direct manner.
---------------------------------------------------------------------------

    \118\ We remind RTOs and ISOs that the Commission's regulations 
regarding RTO governance require periodic audits of the RTO or ISO 
governance by an independent auditor. See 18 CFR 35.34(j)(1)(iv)(A) 
(2006).
---------------------------------------------------------------------------

    152. An RTO or ISO that intends to satisfy this proposed 
requirement with a hybrid board would have to address certain matters. 
Stakeholder members must not be allowed to serve their own interests 
inappropriately. Accordingly, the Commission presents here for comment 
certain restrictions that may be necessary for a hybrid board proposal. 
First, the number of stakeholder members must be a minority of the 
board. The stakeholder members cannot make up more than forty-nine 
percent of the board, and a lower percentage such as twenty-five 
percent may be more appropriate. Second, all subcommittees of the board 
should be structured so that the

[[Page 36296]]

stakeholder members together cannot overcome the unanimous vote of the 
independent board members. Third, any appointment to an RTO or ISO 
board of a senior official or director of a stakeholder company that 
would constitute an interlocking directorate position under FPA section 
305 \119\ would require prior Commission approval before the member 
would join the RTO/ISO board.\120\
---------------------------------------------------------------------------

    \119\ 16 U.S.C. Sec.  825d (2000).
    \120\ See 16 U.S.C. 825d(b)-(c) (2000); 18 CFR 45 (2006). 
Pursuant to section 305(b) of the FPA, interlocks between 
unaffiliated public utilities, interlocks between a public utility 
and other specified entities, and interlocks among affiliated public 
utilities must be submitted to the Commission for approval before a 
prospective director holds and assumes the duties of the 
interlocking position.
---------------------------------------------------------------------------

    153. A second way to satisfy the proposed requirement would be a 
board advisory committee. It would be comprised of senior executives of 
the various stakeholder groups, serving as an expert panel that would 
inform the board of stakeholder views. The board advisory committee 
would have no voting authority on board decisions. It would, however, 
have authority to make recommendations directly to the board on matters 
before the board and on matters it believes the board should address. 
The board advisory committee could advise the board about the expected 
effect on customers and other stakeholder groups of proposals before 
the board. The board advisory committee would not necessarily make 
decisions on what to recommend to the board; instead, minority views 
could also be presented directly to the board.
    154. The Commission envisions a board advisory committee of senior 
stakeholder representatives that would not necessarily consist of those 
on technical stakeholder committees in RTOs and ISOs today. Members of 
the board advisory committee would be selected to represent a 
reasonable range of diverse interests. The number of members should be 
decided with attention to forming a committee of reasonable size that 
can engage the board in thoughtful discussion.
    155. The Commission encourages interested parties to comment 
regarding the proposal and possible approaches. In addition, the 
Commission seeks responses to the following questions about customer 
access to the board of an RTO or ISO:
     How should any hybrid board be structured? What is an 
appropriate limit on the percentage of non-independent board members? 
If a variety of customer views are to be represented, what implications 
does this have for the size of the board?
     What, if any, rules and restrictions should be placed on 
the stakeholder board members of a hybrid board?
     Can the reform proposed here be met through other means 
such as increased direct board interaction with customers and other 
stakeholders, e.g., through open board meetings or through required 
attendance of board members at major stakeholder meetings of the RTO?
     Are there measures--such as customer satisfaction 
measures, cost oversight benchmarks, or stakeholder participation 
measures--that RTOs and ISOs should use to assess the success of the 
mechanism for improving responsiveness?
2. Inquiry Regarding Better Responsiveness Through Improved Practices 
and Processes
    156. The Commission also requests comment about whether any other 
reforms should be adopted to improve RTO and ISO responsiveness to its 
customers and other stakeholders. The Commission is interested in 
particular in whether RTOs and ISOs could achieve better 
responsiveness--or make their responsiveness more apparent to their 
stakeholders--through improvements in the areas of (1) RTO and ISO 
executive management practices, (2) effective RTO and ISO stakeholder 
processes, and (3) transparent RTO and ISO budget processes.
a. RTO and ISO Executive Management Practices
    157. Executive management ensures that RTO and ISO goals set by the 
board are met, including any goal to be responsive to customers and 
other stakeholders. Executive management evaluates such things as how 
to improve RTO/ISO services, whether to provide new services, and how 
to contain administrative costs. Management is likely to be the first 
to hear directly from customers about their concerns with current RTO/
ISO operations or proposed new programs or expenditures.
    158. Managers should be responsive to stakeholders but cannot be 
beholden to any particular stakeholder group. At a minimum, managers 
should seek out customer concerns and pay serious attention to these 
concerns. Managers should evaluate whether some appropriate action is 
needed to address these concerns. They may decide to address some 
concerns and not others, keeping in mind the independence of the RTO or 
ISO, its appropriate role in the region as transmission provider and 
market administrator, and the trade-off between new services and cost 
containment.
    159. The Commission requests comment on whether any reforms are 
necessary to increase management responsiveness to stakeholder 
concerns. For example, should the Commission encourage or require RTOs 
or ISOs to:
     Publish a strategic plan that includes plans for assuring 
responsiveness to customers and other stakeholders.
     Measure or otherwise assess customer satisfaction 
periodically, through a survey or other means.
     Have a formal process for gathering and evaluating 
recommendations for improving services to customers.
     Set performance criteria for executive managers based in 
part on responsiveness to stakeholders.
     Relate executive compensation to a measure of 
responsiveness to stakeholders.
b. Effective RTO and ISO Stakeholder Processes
    160. The stakeholder processes in RTOs and ISOs today serve several 
purposes. They are intended to provide the views of various customer 
and stakeholder groups to the RTOs and ISOs. Some are also intended to 
help the RTOs and ISOs make decisions on sometimes contentious 
transmission and market matters. The Commission is interested in 
comments about how well these processes are working and how their 
effectiveness might be improved.
    161. The Commission requests replies to the following questions 
about RTO and ISO stakeholder processes:
     What stakeholder processes have proved to be particularly 
effective?
     How can the effectiveness of a stakeholder process be 
assessed?
     Does the voting structure of RTO and ISO stakeholder 
groups achieve balanced representation?
     Are minority interests adequately represented in 
stakeholder processes?
     How should an RTO or ISO respond when it must make a 
decision, such as deciding how to comply with a Commission regulation, 
and a stakeholder consensus cannot be reached?
     What actions, if any, can the Commission take to improve 
stakeholder processes? For example, should the Commission ask each RTO 
or ISO to review and report on the strengths and weaknesses of its 
current stakeholder processes?
c. Transparent RTO and ISO Budgeting Processes
    162. Some market participants contend that they do not have an

[[Page 36297]]

adequate opportunity to review or understand an RTO's or ISO's budget 
in time to influence the budget decision. They point in particular to 
RTOs and ISOs that use a formula rate to pass costs through to 
customers. Although the Commission has found the current cost recovery 
mechanisms for all these entities to be just and reasonable,\121\ 
stakeholders express concern about ineffective review of significant 
cost increases before the costs flow through a formula rate. The NYISO 
and Midwest ISO, for example, recover their costs of administering the 
transmission grid and market operations through a formula rate.\122\ 
Some customers believe that the budget for an RTO or ISO with a formula 
rate may not include enough details to understand the reason for an 
expenditure or its effect on their rates.\123\ This suggests that, in 
an RTO or ISO with a formula rate, there may be a greater need for 
customer discussion of budget decisions with major cost consequences 
before the costs are incurred.
---------------------------------------------------------------------------

    \121\ See California Independent System Operator Corp., 103 FERC 
] 61,114 (2003), order on reh'g, 106 FERC ] 61,032 (2004); 
California Independent System Operator Corp., 110 FERC ] 61,090 
(2005); Midwest Independent Transmission System Operator, Inc., 97 
FERC ] 61,033 (2001); Midwest Independent Transmission System 
Operator, Inc., 101 FERC 61,221 (2002), order on reh'g, 103 FERC ] 
61,035 (2003); New England Power Pool, 96 FERC ] 61,261 (2001); ISO 
New England, Inc., 105 FERC ] 61,397 (2003); New York Independent 
System Operator, 86 FERC ] 61,062 (1999); PJM Interconnection, 
L.L.C., 112 FERC 61,236 (2005), order approving settlement, 115 FERC 
] 61,249 (2006).
    \122\ The CAISO, PJM, and ISO-NE, in contrast, use stated rates 
for their grid administration and market services charges.
    \123\ After-the-fact review is considered insufficient. Even if 
the Commission were to disallow an expenditure after the fact as not 
used and useful or otherwise imprudently incurred, an RTO or ISO has 
no profits to be reduced by the amount of any disallowed costs. Many 
market participants assert that there is no good remedy for these 
RTOs and ISOs once imprudent costs are incurred. RTO and ISO 
customers are among the first to tell the Commission that, in 
practice, once costs are incurred by a not-for-profit RTO or ISO 
with a formula rate, these costs must be passed through to its 
customers.
---------------------------------------------------------------------------

    163. The Commission requests comment on possible approaches to 
address these concerns. For example, should each RTO and ISO:
     Review its cost accountability processes with its 
customers and other stakeholders and consider how to improve them?
     Present budget information to customers with adequate 
detail, transparency, and cost support? For example, an RTO or ISO with 
a formula rate could develop its budget presentation to stakeholders 
using the format required for a filing with the Commission to change a 
previously-filed stated rate. This would provide stakeholders with 
clear information about the proposed expenditures, its effect on rates, 
and how the proposed budget relates to recent budgets.
     Provide its customers a timely opportunity to review 
budget proposals, ask budget questions, and comment before major 
expenditures are finally decided?
     Submit to the Commission as an informational filing the 
budget materials provided to stakeholders for review?

VII. Additional Questions

    164. It is our preliminary view that that the Commission should 
institute a proceeding under section 206 of the FPA \124\ to reform RTO 
and ISO tariffs to address certain issues discussed above. The 
Commission may conduct this process either through a notice-and-comment 
rulemaking under the Administrative Procedure Act \125\ or an 
adjudicative process.
---------------------------------------------------------------------------

    \124\ 16 U.S.C. 824e (2000).
    \125\ 5 U.S.C. 553 (2000).
---------------------------------------------------------------------------

    165. The Commission requests comment on which of these procedures 
is likely to produce the most effective reforms, and on the appropriate 
time frame in which to conduct the proceedings. The Commission also 
seeks input as to the length of time that might be necessary for RTOs 
and ISOs to implement any reforms that result from this process. 
Specifically, the Commission requests input as to how much time--
including time for stakeholder processes--might be needed for technical 
development of compliance filings.

VIII. Comment Procedures

    166. The Commission invites interested persons to submit comments 
on these matters and any related matters or alternative proposals that 
commenters may wish to discuss. Comments are due August 16, 2007. 
Comments must refer to Docket No. AD07-7-000 and must include the 
commenter's name, the organization he or she represents, if applicable, 
and his or her address.
    167. Comments may be filed electronically via the eFiling link on 
the Commission's Web site at http://www.ferc.gov. The Commission 

accepts most standard word processing formats and commenters may attach 
additional files with supporting information in certain other file 
formats. Commenters filing electronically do not need to make a paper 
filing.
    168. Commenters that are not able to file comments electronically 
must send an original and 14 copies of their comments to: Federal 
Energy Regulatory Commission, Secretary of the Commission, 888 First 
Street, NE., Washington, DC, 20426.
    169. All comments will be placed in the Commission's public files 
and may be viewed, printed, or downloaded remotely as described in the 
Document Availability section below. Commenters are not required to 
serve copies of their comments on other commenters.

IX. Document Availability

    170. 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.
    171. From the Commission's Home Page on the Internet, this 
information is available in its eLibrary. The full text of this 
document is available in the eLibrary both in PDF and Microsoft Word 
format for viewing, printing, and/or downloading. To access this 
document in eLibrary, type the docket number of this document, 
excluding the last three digits, in the docket number field.
    172. User assistance is available for eLibrary and FERC's Web site 
during normal business hours from our Help line at (202) 502-8222 or 
the Public Reference Room at public.reference@ferc.gov.

    By direction of the Commission. Commissioner Kelly concurring in 
part and dissenting in part with a separate statement attached.
Kimberly D. Bose,
Secretary.
KELLY, Commissioner, concurring in part and dissenting in part:

    I generally support the efforts of this Advanced Notice of 
Proposed Rulemaking (ANOPR) in setting forth proposals and seeking 
comment on improvements to the operation of organized wholesale 
electric markets. I am writing separately to express my views on 
certain of the proposals related to strengthening market monitoring, 
improving demand response and promoting RTO/ISO responsiveness.
    First, I would have added certain proposals to the ANOPR to 
strengthen market monitoring. For reasons I have previously 
explained,\126\ I would have proposed requiring RTOs/ISOs to file 
tariff provisions to allow them to take enforcement action with 
respect to objectively identifiable

[[Page 36298]]

behavior that does not subject the seller to sanctions or 
consequences other than those expressly approved by the Commission 
and set forth in the tariff, and with the right of appeal to the 
Commission, consistent with the Policy Statement on Market 
Monitoring Units.\127\ In addition, the ANOPR states that the 
Commission does not intend to share with the MMU information about 
suspected tariff and rule violations referred by the MMU to the 
Commission. I believe the Commission should generally provide 
information to the MMUs on the referrals they have made to the 
Commission, subject to appropriate confidentiality restrictions. 
Such feedback could be structured so as to provide responsible 
disclosure of information while preserving confidentiality. In 
addition, I would have proposed requiring the MMU to make 
recommendations related to its reports on RTO/ISO performance. 
Therefore, I concur in part on the ANOPR.
---------------------------------------------------------------------------

    \126\ See PJM Interconnection, L.L.C., 116 FERC ] 61,038, order 
on reh'g, 117 FERC ] 61,263 (2006).
    \127\ See 111 FERC ] 61,267 (2005) at P 5.
---------------------------------------------------------------------------

    Second, I disagree with two of the proposals being made in the 
ANOPR. One proposal involves facilitating greater participation of 
demand response in organized markets by modifying market power 
mitigation rules in organized markets, such as raising the energy 
bid caps and market-wide caps in an emergency situation. Before the 
Commission considers whether to pursue such market rule 
modifications, I think it is important to address other barriers 
that may significantly restrict demand response participation. For 
example, the FERC Staff Demand Response Assessment concluded that 
the technologies needed to support significant deployment of demand 
resources, such as advanced metering, have little market 
penetration.\128\ Without the necessary technology already in place 
that would allow demand resources to respond to price signals in 
wholesale or retail markets, it is unclear how quickly they could 
develop the ability to respond after energy bid caps or market-wide 
caps are raised or eliminated. In other words, the technology and 
associated demand response capability must be in place before we 
consider raising or eliminating these price caps. Otherwise these 
higher energy prices may not elicit any demand reduction in a 
fashion capable of disciplining those prices and keeping them just 
and reasonable. In addition, rather than asking questions in this 
ANOPR on how to value demand response, I think the Commission should 
have proposed a compensation method and postponed consideration of 
modifying market power mitigation rules until after the valuation 
issue had been addressed.
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    \128\ FERC Staff Demand Response Assessment, Docket No. AD06-2-
000, at page xii.
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    Third, although I recognize that some stakeholder groups have 
raised concerns about the responsiveness of the RTO/ISO, I disagree 
with the ANOPR's proposal to promote responsiveness by establishing 
a hybrid RTO/ISO board of directors composed of both independent 
members and non-independent stakeholder members. Under this 
proposal, each member would have a seat on the board and participate 
fully in board decisions with an equal vote. I think it would be 
inadvisable and difficult to implement such a proposal.
    Order Nos. 888 and 2000 require that an ISO or RTO be 
independent from market participants so that they can provide 
regional transmission and energy market services on a non-
discriminatory basis. A fundamental principle for ISOs, as set forth 
in Order No. 888, is that the ISO should be independent of any 
individual market participant or any one class of participants 
(e.g., transmission owners or end-users).\129\ Similarly, Order No. 
2000 emphasized that independence is the bedrock principle on which 
the ISOs and RTOs must be built and stressed that an RTO ``needs to 
be independent in both reality and perception.''\130\ I believe that 
establishing a hybrid board would jeopardize the fundamental 
principle of independence upon which ISOs and RTOs are based.
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    \129\ Order No. 888, FERC Stats. & Regs. ] 31,036 at 31,730-31.
    \130\ Order No. 2000, FERC Stats. & Regs. ] 31,089 at 31,061.
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    Moreover, although the ANOPR states that stakeholder members 
would be directed not to serve their own interests inappropriately, 
it is not clear to me how one would distinguish between 
``inappropriate'' advocacy for one's interests, and perfectly 
reasonable advocacy for one's interests. Additionally, a hybrid 
board composed of independent and non-independent board members 
could needlessly complicate the board dynamic and make cooperative 
decision-making more difficult and time consuming. Currently, the 
independent board coupled with the stakeholder process, can be 
viewed as similar to the judicial model of governance. The 
stakeholders are like adversaries in a judicial proceeding arguing 
their cases to a disinterested judge, the independent board, which 
is capable of balancing the various equities in reaching a timely 
decision that is fair to all.
    A stakeholder board, even a hybrid one, would be more akin to 
the legislative model with no overarching independent judge making 
the final calls. Such a model requires constant negotiation and can 
often lead to stalemate or decisions that address only the lowest 
common denominator rather than the ideal approach. While that model 
is certainly appropriate in many situations, I do not believe it is 
workable for the board of an RTO or ISO given the many important and 
time-critical issues they deal with. Furthermore, most investor 
owned utilities, with whom RTOs and ISOs share many features, do not 
appear to follow the legislative model of governance and it is not 
clear to me why the RTOs and ISOs should be treated differently. If 
the Commission is to consider providing stakeholders with some form 
of direct board access, I think that the board advisory committee 
proposed in this ANOPR would more effectively serve this purpose.
    Accordingly, for the reasons stated above, I concur in part and 
dissent in part on this ANOPR.

Suedeen G. Kelly

 [FR Doc. E7-12550 Filed 6-29-07; 8:45 am]

BILLING CODE 6717-01-P
