[Federal Register: July 2, 2007 (Volume 72, Number 126)]
[Proposed Rules]
[Page 36275-36298]
[DOCID:fr02jy07-19]

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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<EMAIL_ADDRESS>(202) 502-6404.
Elizabeth Rylander (Legal Information), Office of the General Counsel,
Federal Energy Regulatory Commission, 888 First Street, NE.,
Washington, DC 20426<EMAIL_ADDRESS>(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

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

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

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

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

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

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\
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    \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

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 <IP_ADDRESS>, 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.
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    \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

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.
---------------------------------------------------------------------------

    \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

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\
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \57\ In particular, any proposal must comply with BAL-002
(Disturbance Control Performance) and EOP-002 (Capacity and Energy
Emergencies).
---------------------------------------------------------------------------

    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

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?
---------------------------------------------------------------------------

    \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

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

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.
---------------------------------------------------------------------------

    \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

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\
---------------------------------------------------------------------------

    \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\
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    \76\ Order No. 2000, FERC Stats. and Regs., Regulations
Preambles July 1996-December 2000 ] 31,089 at ] 31,016 (regarding
RTOs).
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    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\
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    \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).
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    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\
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    \78\ Order No. 2000, FERC Stats. & Regs., Regulations Preambles
July 1996-December 2000 ] 31,089 at ] 31,156.
    \79\ Id.
    \80\ Id.
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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

sanctioned behavior expressly set forth in the RTO/ISO tariffs.\82\
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    \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.
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    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\
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    \83\ Market Behavior Rules Rehearing Order, 107 FERC ] 61,175 at
P 165.
    \84\ Id. P 168.
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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:
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    \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.
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    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.
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    \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).
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    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\
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    \89\ PJM Interconnection, L.L.C., 117 FERC ] 61,263, at P 19
(2006) (PJM Tariff Rehearing Order).
    \90\ Id. P 20.
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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\
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    \91\ Review of Market Monitoring Policies, Second Notice of
Technical Conference, Docket No. AD07-8-000 (2007).
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    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.
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    \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.
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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

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