Wholesale Competition in Regions With Organized Electric Markets, 36276-36298 [E7-12550]
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Federal Register / Vol. 72, No. 126 / Monday, July 2, 2007 / Proposed Rules
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.
DEPARTMENT OF ENERGY
Federal Energy Regulatory
Commission
18 CFR Part 35
[Docket Nos. RM07–19–000 and AD07–7–
000]
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: https://
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
DATES:
Wholesale Competition in Regions
With Organized Electric Markets
June 22, 2007.
Federal Energy Regulatory
Commission, DOE.
ACTION: Advance notice of proposed
rulemaking.
AGENCY:
SUMMARY: The Federal Energy
Regulatory Commission (Commission) is
issuing an Advance Notice of Proposed
Rulemaking (ANOPR) with regard to
Regulatory Commission, Secretary of the
Commission, 888 First Street, NE.,
Washington, DC 20426. Please refer to
the Comment Procedures section of the
ANOPR for additional information on
how to file paper comments.
FOR FURTHER INF0RMATION CONTACT:
David Kathan (Technical Information),
Office of Energy Markets and
Reliability, Federal Energy Regulatory
Commission, 888 First Street, NE.,
Washington, DC 20426,
David.Kathan@ferc.gov, (202) 502–
6404.
Elizabeth Rylander (Legal Information),
Office of the General Counsel, Federal
Energy Regulatory Commission, 888
First Street, NE., Washington, DC
20426, Elizabeth.Rylander@ferc.gov,
(202) 502–8466.
SUPPLEMENTARY INFORMATION:
Paragraph
numbers
I. Introduction .........................................................................................................................................................................................
II. Background .........................................................................................................................................................................................
A. Brief History ...............................................................................................................................................................................
B. Competition Issues and Commission Actions ..........................................................................................................................
C. Issues Addressed in the ANOPR ...............................................................................................................................................
III. Demand Response and Pricing During Power Shortages in Organized Markets ..........................................................................
A. Importance of Demand Response to Competition in RTO/ISO Areas ....................................................................................
B. Prior Commission Actions To Address Demand Response .....................................................................................................
C. Remaining Problems with Demand Response in Organized Markets .....................................................................................
D. Proposed Commission Actions To Improve Demand Response and Market Pricing During a Power Shortage ..................
IV. Long-Term Power Contracting in Organized Markets ....................................................................................................................
A. Importance of Long-Term Power Contracts and Factors Affecting Contracting Decisions by Buyers and Sellers ..............
B. Commission Actions To Support Long-Term Power Contracts ...............................................................................................
C. Proposed Commission Actions To Facilitate Long-Term Power Contracting .........................................................................
V. Market Monitoring Policies ...............................................................................................................................................................
A. History of Market Monitoring ....................................................................................................................................................
B. Independence and Function ......................................................................................................................................................
C. Information Sharing ....................................................................................................................................................................
D. Pro Forma Tariff Section ............................................................................................................................................................
E. Conclusion ...................................................................................................................................................................................
VI. Responsiveness of RTOS and ISOS .................................................................................................................................................
A. The Challenge of Improving RTO and ISO Responsiveness to Stakeholders ........................................................................
B. Prior Commission Actions Regarding RTO and ISO Responsiveness .....................................................................................
C. Proposed Commission Action To Improve RTO and ISO Responsiveness ............................................................................
VII. Additional Questions ......................................................................................................................................................................
VIII. Comment Procedures .....................................................................................................................................................................
IX. Document Availability .....................................................................................................................................................................
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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
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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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.
2. These issues are: (1) The role of
demand response in organized markets,
including greater reliance on market
prices to elicit demand reductions
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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
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
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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.
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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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
alternative recommendations for achieving the
objective.
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).
4 Pub. L. No. 109–58, 119 Stat. 594 (2005).
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strengthened the legal framework for
continuing wholesale competition as
federal policy for this country.
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.
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 investorowned, 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
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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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
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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.
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.
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.
16. Congress addressed these
problems in the Energy Policy Act of
1992 (EPAct 1992).10 EPAct 1992 eased
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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).
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).
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).
10 Pub. L. No. 102–486, 106 Stat. 2776 (1992).
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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.
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
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.
11 16
U.S.C. 824e (2000).
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).
13 U.S. Department of Energy, Energy Information
Administration, Status of State Restructuring of the
Electric Power Industry, at https://www.eia.doe.gov/
cneaf/electricity/epar1/state.html.
12 Promoting
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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.
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
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.
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 https://www.nepga.org/contents/
factsheet9041006.pdf.
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Information Administration (EIA), the
percentage of generating capacity in the
United States owned by independent
power producers has grown from less
than 2 percent in 1990 to more than 35
percent by 2005.19 A result has been to
shift the risk of investment from
customers to shareholders. In addition,
under wholesale competition, the
efficiency of existing nuclear, coal, and
other types of generation has improved
significantly, lowering costs to
consumers and reducing environmental
effects, and the increased capacity
factors and availability of these units
has further lowered electric generating
costs.20 The RTO and ISO-organized
markets opened opportunities for
renewable energy sources; an increasing
fraction of new generation is from nontraditional 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
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
19 U.S. Department of Energy, Energy Information
Administration, Electric Power Annual 2005, Table
2.1 (November 2006), at https://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]ellstructured 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), https://www.caiso.com/14c6/
14c6c4291aa40.pdf.
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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.
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.
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 https://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 https://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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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
27 Promoting Transmission Investment through
Pricing Reform, Order No. 679, 71 FR 43,294 (July
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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, preoperations, 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.
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,
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.
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).
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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.
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
31 See Supplemental Notice, Demand Response in
Wholesale Markets, Docket No. AD07–11–000
(April 6, 2007).
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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
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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
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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.
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
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).
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), https://www.brattle.com/
_documents/Publications/ArticleReport2441.pdf.
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36281
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.
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 Prizewinning 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.
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
34 Vernon Smith and Lynne Kiesling, MarketBased Model for ISO-Sponsored Demand Response
Programs, (September 2005), https://
www.defgllc.com/Downloads/
051018_DEFG_DRwp02.pdf .
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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 costeffectiveness 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
B. Prior Commission Actions To
Address Demand Response
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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
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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wholesale power markets of RTOs and
ISOs.37
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.
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
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).
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).
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
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a curtailment service provider, typically
provides this aggregation service. The
aggregate demand reduction may be bid
directly into the energy and ancillary
services markets.
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 nongeneration 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
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
¶ 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).
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.
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.
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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. 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.
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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 wellsuited 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
FERC Staff Demand Response Assessment.
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.
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).
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.
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-plusreserves 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
47 See
48 For
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50 ISO-NE places a minimum size of 5 MW for
participation. See ISO–NE, ISO New England
Manual for Market Rule 1 Accounting (May 31,
2007), at section 12.3.5.3, https://www.iso-ne.com/
rules_proceds/isone_mnls/
m_28_market_rule_1_accounting_(revision_27)
_05_31_07.doc.
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disincentive for a demand resource to
bid into the operating reserves market.51
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 dayahead 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 realtime 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.
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
51 See FERC Staff Demand Response Assessment
at 123.
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).
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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.
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
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.
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prices may reduce their incentive to
explore various hedging activities, such
as participating in interruptible demand
response programs, entering into longterm 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 highestvalued 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.
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
54 The
Commission approved this change in 2003.
New York Independent System Operator, Inc., 102
FERC ¶ 61,313 (2003).
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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.
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
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.
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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
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
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
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.
57 In particular, any proposal must comply with
BAL–002 (Disturbance Control Performance) and
EOP–002 (Capacity and Energy Emergencies).
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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.
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
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
67. The Commission also requests
comment on whether an RTO or ISO
58 This true-up process substitutes for an energy
imbalance charge in most RTO and ISO spot
markets.
59 Although covering operating reserve costs, the
deviation charge may also cover other costs not
affected by the direction of the deviation.
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), https://www.pjm.com/contributions/pjmmanuals/pdf/m28.pdf.
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36285
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
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.
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because they lack standing as an LSE or
because they individually cannot meet a
requirement that a demand response bid
be of minimum size.
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.
72. The Commission requests
comments on the proposal to require
RTOs and ISOs to amend their market
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.
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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
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
63 See Technical Conference on Demand
Response and Advanced Metering on January 25,
2006, Tr. 26 (Richard Tempchin, EEI) (Docket No.
AD06–2–000), https://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), https://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).
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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?
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 realtime 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 marketwide $1,000 per MWh offer cap. If the
market-wide cap was also raised, the
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 marketclearing 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).
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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
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 priceinsensitive 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.
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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.
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 marketclearing 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
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36287
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 costeffectiveness 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
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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 longterm 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 longterm 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, intermediateterm, and long-term power supplies.
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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.
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.
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.
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).
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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.
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
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).
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).
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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.
C. Proposed Commission Actions To
Facilitate Long-Term Power Contracting
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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
91. Through this ANOPR the
Commission intends to consider
whether there are other concrete steps
that can be taken to facilitate long-term
contracting.
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
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.
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 longterm 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?
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).
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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
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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market monitoring plan as part of its
RTO proposal. The Order did not,
however, impose a specific MMU
structure on the RTOs.77
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
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
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).
78 Order No. 2000, FERC Stats. & Regs.,
Regulations Preambles July 1996–December 2000
¶ 31,089 at ¶ 31,156.
79 Id.
80 Id.
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).
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sanctioned behavior expressly set forth
in the RTO/ISO tariffs.82
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
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:
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 realtime 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,
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82 Market
Behavior Rules, 105 FERC ¶ 61,218 at
P 182, 184.
83 Market Behavior Rules Rehearing Order, 107
FERC ¶ 61,175 at P 165.
84 Id. P 168.
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.
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.
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together with the Protocols it
incorporates, represents the last generic
pronouncement by the Commission on
the duties of MMUs.
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
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
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
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 AntiManipulation 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).
89 PJM Interconnection, L.L.C., 117 FERC
¶ 61,263, at P 19 (2006) (PJM Tariff Rehearing
Order).
90 Id. P 20.
91 Review of Market Monitoring Policies, Second
Notice of Technical Conference, Docket No. AD07–
8–000 (2007).
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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.
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
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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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.
to market data, resources, or personnel,
and describe the steps it has taken with
the RTO or ISO to resolve these
concerns. We also seek comment on the
question of how independence on the
part of MMUs can best be achieved.
1. Structure and Tools
109. The Commission has never
required that MMUs conform to any
standardized organizational structure.
As a result, RTOs and ISOs have
developed varying structural
relationships between themselves and
their MMUs. PJM, for instance, has an
internal market monitor; MISO has an
external market monitor, and the other
RTOs and ISOs have hybrid structures.
Some commenters at the technical
conference favored an internal market
monitor, one whose personnel are
employees of the RTO or ISO. These
commenters contended that such
employees are closer to the actual
operations of the RTO or ISO and as a
result have better access to information.
Other commenters favored an external
market monitor, an independent
contractor who is hired by the RTO or
ISO. These commenters contended that
such an entity inherently has more
independence from the RTO or ISO than
do employees of the organization.
However, most commenters were of the
opinion that the particular structural
relationship between the MMU and the
RTO or ISO was of secondary
importance, provided that the RTO/ISO
tariff contained provisions ensuring
independence on the part of the MMU.
110. From our own experience, the
Commission has observed no
appreciable difference among the
performance of the market monitors that
can be attributed to whether they are
external or internal to their RTO or ISO.
The Commission therefore declines to
impose a ‘‘one size fits all’’ approach
toward the structure of MMUs.
111. It is axiomatic that independence
can be achieved only if MMUs have
adequate tools with which to perform
their job. Therefore, the Commission
proposes requiring each RTO and ISO to
include in its tariff a provision imposing
upon itself the obligation to provide its
MMU with access to market data,
resources, and personnel sufficient to
enable the MMU to carry out its
functions.94 In addition, the tariff
should include a provision directing the
MMU to report to the Commission any
concerns it has with inadequate access
2. Oversight
112. As several commenters pointed
out at the technical conference, there is
an inherent tension in a structure that
requires MMUs to report to RTO/ISO
management yet, at the same time,
perform evaluations and issue reports
that may be critical of that management.
For example, MMUs are expected to
evaluate and report on RTO/ISO market
designs and performance, and to
include RTO/ISO operations in their
analyses of market flaws or
inefficiencies. Further, if an MMU
detects a potential tariff violation on the
part of its RTO or ISO, it is obligated to
bring the matter to the attention of the
Commission. It can be difficult for an
MMU to discharge these oversight and
reporting obligations effectively unless
it has some degree of independence
from RTO/ISO management. Such a
reporting relationship can create a
conflict of interest because the MMU
may temper its opinions out of
deference to management, or those
opinions may be overruled by
management. Importantly, these
concerns can be present whether the
MMU personnel are in an internal or
external structural relationship to their
RTO or ISO.
113. Therefore, the Commission
proposes that each RTO and ISO, in
addition to maintaining a market
monitoring function, be required to have
its MMU report either directly to the
RTO’s or ISO’s board of directors or
directly to a committee of independent
board directors. This requirement would
apply to all structural types of MMU,
whether internal, external or a hybrid
combination of the two.95 The
Commission is of the view that it has
the authority to impose this type of
requirement on RTOs and ISOs, but
seeks comment on this issue as well as
on the proposal itself.
94 PJM’s tariff, for instance, requires PJM to
provide appropriate staffing for its MMU, and to
ensure that the MMU has adequate resources,
access to required information, and the cooperation
of PJM staff. PJM Interconnection, L.L.C., FERC
Electric Tariff, Attachment M, Section V.
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3. Functions
114. The issue of independence is
integrally related to the functions that
the MMUs are expected to perform.
Most of the functions performed by
95 The Commission notes that, if adopted, this
policy would mark a departure from the holding in
PJM Interconnection, L.L.C., 116 FERC ¶ 61,038, at
P 38, order on reh’g 117 FERC ¶ 61,263 (2006).
After giving due consideration to the comments
submitted at the technical conference, and for the
reasons stated above, the Commission believes that
a generic change in policy may be appropriate and
is therefore seeking comment on the issue.
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MMUs have remained relatively
constant since the inception of market
monitoring, and center around market
analysis and the evaluation of
participant behavior. Commenters at the
technical conference were generally
supportive of the functions which the
Commission identified in its 2005
Policy Statement, with one exception
discussed below.
115. The MMU functions upon which
there was general agreement at the
technical conference were: (1)
Identifying ineffective market rules and
tariff provisions and recommending
proposed rule and tariff changes, (2)
reviewing and reporting on the
performance of the wholesale markets,
and (3) identifying and notifying the
Commission staff of instances in which
a market participant’s behavior may
require investigation. The Commission
supports these three functions and
proposes to continue them, with one
important modification. In the Policy
Statement, the MMUs were directed to
advise the RTO or ISO of any
recommendations for rule or tariff
changes, with no mention being made of
also advising the Commission. The
Commission proposes adding the
requirement that the MMUs also advise
the Commission and other interested
entities, which would include relevant
state commissions and market
participants. This added requirement
would go a long way toward ensuring
the transparency desired by many of the
commenters. Furthermore, as noted
above, MMUs should refer to the
Commission any suspected rule or tariff
violation committed by an RTO or ISO,
as well as those committed by market
participants.
116. The Commission also proposes
retaining the Protocols governing
referral of potential market violations to
the Commission, which are included as
an Appendix to the Policy Statement.
However, since issuance of the Policy
Statement, Market Behavior Rule 2,
referred to in the Protocols, has been
rescinded and replaced by the
Commission’s Anti-Manipulation
Rules.96 Therefore, violations currently
to be referred to the Commission
include conduct suspected of violating
the Anti-Manipulation Rules, as well as
tariff violations and violations of the
remaining, codified Market Behavior
Rules. In addition, the Commission
proposes that the MMU also refer any
suspected violations of other
Commission-approved rules and
96 See Market Manipulation Order, FERC Stats. &
Regs. ¶ 31,202.
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regulations, such as Codes of Conduct 97
and Standards of Conduct.
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4. Mitigation and Operations
117. As mentioned, one of the four
MMU functions listed in the Policy
Statement was the source of some
debate at the technical conference. The
function in question is that of providing
support to the RTO or ISO in the
administration of its tariff, which
usually takes the form of MMUconducted market power mitigation.98
Certain commenters were concerned
that such mitigation is being conducted
without an adequate theoretical or
empirical basis and is having a
deleterious effect on the electric power
market.
118. The Commission does not
believe this rulemaking is the
appropriate forum to address issues of
market power and mitigation. However,
the Commission is concerned that an
MMU’s performance of these mitigation
functions can compromise its
independence in evaluating and
reporting on market performance. In
order for the MMU to support the RTO
or ISO in tariff administration, it must
be subordinate to RTO and ISO
management. The operations and
mitigation functions performed by
MMUs directly affect market outcomes
and performance. Because of this, there
is an inherent conflict between an MMU
reporting on market outcomes that the
MMU itself has influenced. This conflict
is of particular concern where the MMU
has significant discretion in affecting
offers, bids, and prices. There is
significant potential for conflict between
an MMU maintaining independence of
RTO and ISO management and
supporting tariff administration in a
subordinate capacity. It may not be
possible for MMUs to maintain
independence while supporting tariff
administration.
119. For the foregoing reasons, the
Commission believes operational
activities affecting the market, including
mitigation, are more properly performed
by the RTOs and ISOs themselves as
part of their responsibility to administer
their Commission-approved tariffs.
Maintaining a clear functional
separation in this regard between RTOs
and ISOs and the MMUs would free the
MMUs to report objectively on whether
the RTOs and ISOs have done an
97 The
term ‘‘Code of Conduct’’ has been replaced
by ‘‘Affiliate Restrictions’’ in the Final Rule for
Market-Based Rates for Wholesale Sales of Electric
Energy, Capacity, and Ancillary Services by Public
Utilities, 119 FERC ¶ 61,295 (2007).
98 This function was not part of the original
conception of market monitoring as expressed in
Order No. 2000.
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appropriate job in designing and
administering wholesale power markets.
Therefore, the Commission proposes
requiring that MMUs refrain from
assisting the RTO or ISO in tariff
administration, from participating in
RTO/ISO market operations, and from
taking direct actions to influence the
market, and instead concentrate on their
role of providing market evaluation,
reports, and advice.
5. Ethics
120. In order for an MMU to carry out
its functions, an activity which requires
disinterested objectivity, it is vital that
MMU personnel maintain the highest
ethical standards. Removal of the
conflicts of interest noted above should
go a long way toward facilitating the
achievement of those standards.
However, as a further safeguard, the
Commission proposes imposing certain
minimum ethics standards upon market
monitor personnel, whether the MMU is
internal or external to its RTO or ISO,
in particular prohibiting such personnel
from owning financial interests in any
market participants. The Commission
notes that all existing RTOs and ISOs
have some type of conflict of interest or
standard of conduct provision, although
not always in their tariffs. The
Commission proposes standardizing
such provisions and requiring their
inclusion in the tariffs themselves. The
Commission solicits comments as to
whether the provisions should be
standardized and, if so, what particular
provisions would be appropriate.
6. Tariff Provisions
121. In order for MMUs to achieve
transparency of function, the detailed
obligations imposed upon them must be
made clear and accessible. Likewise, the
provisions safeguarding MMU
independence and delineating MMU
functions must be included in the tariffs
of the RTOs and ISOs in order to be
reviewed, approved and enforced by the
Commission. Currently, MISO and SPP
are the only RTOs or ISOs that
centralize the MMU provisions in their
tariffs.99 Others scatter their MMU
provisions in multiple sections of their
tariffs and in other documents or, in the
case of NYISO, not in the tariff at all.100
The Commission proposes that each
RTO and ISO set forth all its provisions
99 Midwest Independent Transmission System
Operator, Inc., Open Access Transmission and
Energy Markets Tariff, Module D; Southwest Power
Pool, Inc., Open Access Transmission Tariff,
Attachments AG, AH.
100 NYISO’s market monitoring plan is available
on its Web site and may be found at https://
www.nyiso.com/public/documents/tariffs/
market_services.jsp.
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involving market monitoring in one
section of its tariff.
C. Information Sharing
122. As noted in the Policy Statement,
a key function which MMUs are
expected to perform is that of analyzing
the markets to determine if they are
competitive, and proposing actions
which might be useful in eliminating
design flaws. Although RTOs and ISOs
are subject to the exclusive jurisdiction
of the Commission, we recognize the
relationship between wholesale and
retail markets. The Commission also
recognizes the state commission interest
in the performance of wholesale power
markets. In Order No. 2000, the
Commission acknowledged that
information developed by MMUs would
be beneficial not only to itself, but to
others as well.101 However, inasmuch as
there is a wealth of data gathered by
MMUs, it is important to identify the
types of information that each
constituency needs to assist it in
performing its tasks. The Commission
favors both a fuller sharing of
information and identification of the
relevant information desired, so that the
needs of the Commission, the state
commissions, market participants, and
the public may be satisfied.
1. Information Needs
123. Representatives of state
commissions and several other
interested parties submitted comments
at the technical conference expressing
their desire to receive more information
from the MMUs. The state commission
representatives argue that they need
such information to assist them in
performing their regulatory functions,
given the integral relationship between
wholesale and retail rates. The
Commission is sympathetic to these
requests. The Commission recognizes
that state commissions are not
stakeholders, but a separate class from
market participants. As noted above,
although RTOs and ISOs are subject to
the exclusive jurisdiction of the
Commission, state commissions have a
legitimate interest in the performance of
wholesale power markets. However,
their requests for information must be
balanced, in some cases, against
confidentiality concerns. Public
disclosure of certain information, such
as participant-specific offers or cost
data, could harm market participants or
could facilitate collusion under some
circumstances. The Commission must
therefore balance state concerns
101 Order No. 2000, FERC Stats. & Regs.,
Regulations Preambles July 1996–December 2000
¶ 31,089 at 31,156.
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regarding information access with these
countervailing confidentiality concerns.
124. The comments submitted at the
technical conference did not identify
the particular categories of information
needed by state commissions. The
Commission therefore proposes below
general areas of information which it
believes could be provided to the states
without jeopardizing the need for
confidentiality on the part of market
participants. The Commission requests
comments as to whether our proposal
meets the needs of the state
commissions, and whether there are
other kinds of information that are
needed by state commissions to fulfill
their regulatory responsibilities. We
further request comment on whether
there is a generic standard or test that
could be used to determine what
specific information should be provided
to a state commission. The Commission
also proposes that some, but not all, of
the information to be supplied to the
state commissions also be made
available to market participants. Finally,
the Commission sets forth the
information which it believes must
remain protected, and solicits comment
on whether harm could result from our
proposed information disclosures.
2. Information To Be Provided
125. The Commission proposes that
MMUs be required to report
comprehensively on aggregate market
and RTO/ISO performance on a regular
basis, no less frequently than quarterly,
to the Commission staff, to staff of
interested state commissions, and to the
management and board of directors of
the RTOs and ISOs. The MMUs would
be required to deliver materials
supporting their conclusions, and make
one or more of their staff members
available for a conference call attended
by representatives of these
constituencies. During this process, the
MMU representative would be expected
to work cooperatively to develop any
further materials which might be useful
to the Commission, to the state
commissions and to the RTOs and ISOs.
The Commission envisions that such
combined reporting and conference
calls would permit targeted requests for
information and encourage a fuller
exchange of relevant data than may be
provided in the MMUs’ yearly State of
the Market reports, which are currently
required by tariff or the internal policies
of all the RTOs and ISOs.
126. The Commission cautions that
such reports and meetings are in no way
intended to restrict the MMU from
meeting individually with Commission
staff, staff of state commissions, market
participants, or other stakeholders, or
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sharing information with these various
constituencies, subject to appropriate
restrictions on confidentiality. The
Commission is of the view that, in
general, as much helpful and
appropriate information about the
performance of RTO/ISO markets as
possible should be made public.
127. The Commission proposes that
offer and bid data, without
identification of the market participants,
be posted on the RTO’s or ISO’s Web
site, where it will be available to the
Commission, to interested state
commissions, and to stakeholders. The
Commission proposes a lag of three
months for posting this data and solicit
comments as to whether that time
period is sufficient to protect
commercially sensitive data and to
guard against misuse of the data.
3. Tailored Requests for Information
128. The Commission proposes that
state commissions may make requests
for additional information from the
MMUs. The Commission understands
that information such as general
analyses of the market and aggregated
price data may assist state commissions
in performing their regulatory functions,
and believes reasonable requests along
those lines may be appropriate. The
Commission seeks comment on how to
structure this proposal to ensure that the
information requests are useful to the
states, while at the same time respectful
of the limited resources of the MMUs,
and how to ensure confidentiality with
respect to certain market data.
129. The Commission believes that
the foregoing proposal allowing states to
request tailored information should be
for information regarding general market
trends and performance, not
information designed to aid state
enforcement or related actions against
individual companies. States have their
own enforcement agencies which are
more properly employed for such tasks.
The limited resources of the MMUs
should be confined to providing
information regarding the workings of
the market itself and identifying any
structural flaws which the MMUs think
should be addressed.102 However, a
state commission would remain free, on
a case-by-case basis, to request that the
Commission authorize the release of
otherwise proscribed data. The
Commission would evaluate any such
request to determine if it demonstrates
a compelling need for the requested
information, and decide whether
102 However, if during the ordinary course of its
activities an MMU were to discover evidence of
wrongdoing that was within a state commission’s
jurisdiction, it is expected that the MMU would
report such information to the state commission.
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36293
adequate protections can be fashioned
for commercially sensitive material.
4. Commission Referrals
130. The Commission continues to
believe that MMUs should respect the
confidentiality of their referrals of
suspected tariff and rule violations to
the Commission, and not disclose such
referrals to other entities, including state
commissions.103 Nor does the
Commission intend to share such
information, or the result of its activities
that are initiated based upon a MMU
referral, on a generic basis. The
Commission notes that its rules require
that such information be kept nonpublic
unless the Commission authorizes, in
any given case, that it be publicly
disclosed.104 Such disclosure is the
exception and not the rule, and each
such instance is carefully considered by
the Commission with due regard to the
commercially sensitive nature of the
material and to the effect disclosure may
have on the willingness of jurisdictional
entities to file self reports with the
Commission and otherwise cooperate in
its investigations. As the Commission
has observed previously, confidentiality
provides reasonable protection to
persons who become involved in these
investigations and fosters cooperation
with the Commission. It also protects
innocent persons who might be
erroneously alleged to have committed
wrongdoing or be otherwise adversely
affected by simply being associated with
an investigation.105 The Commission
notes, however, that its staff does give
MMUs generic feedback regarding
enforcement issues, and we intend to
continue this practice in order to
provide guidance in matters relating to
their referral function.
D. Pro Forma Tariff Section
131. The Commission intends to
include in its subsequent Notice of
Proposed Rulemaking a proposed pro
forma MMU section for the RTOs’ and
ISOs’ OATTs. The Commission
anticipates that each RTO and ISO may
wish to modify certain provisions, or
add others, to such pro forma tariff to
suit its particular needs. Nonetheless,
the Commission believes it will be
useful to develop specific core
provisions that are standardized across
the various RTOs and ISOs, particularly
103 See PJM Tariff Rehearing Order, 117 FERC
¶ 61,263 at P 27.
104 18 CFR 1b.9 (2006). Other exceptions include
cases where the information has been made a matter
of public record in an adjudicatory proceeding, and
where disclosure is required by the Freedom of
Information Act, 5 U.S.C. 552 et seq. (2006).
105 PJM Tariff Rehearing Order, 117 FERC
¶ 61,263 at P 27.
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in the areas of independence, MMU
functions, and information sharing. The
Commission anticipates including in the
pro forma tariff protocols for the referral
of tariff and market manipulation
violations to the Office of Enforcement,
as well as protocols for the referral of
perceived market design flaws and
recommended tariff changes to the
Office of Energy Markets and Reliability.
The Commission solicits comments on
the structure and content of such a pro
forma section.
E. Conclusion
132. The Commission’s goal is to
strengthen market monitoring, and we
advance proposals in this ANOPR that
respond to concerns expressed by
commenters at the technical conference,
as well as that reflect our own
observations formed over the years from
working within the framework of the
existing market monitoring provisions.
The Commission seeks comment on its
proposals and on other matters germane
to market monitoring.
VI. Responsiveness of RTOS and ISOS
133. This section of the ANOPR
addresses proposals to increase RTO/
ISO responsiveness to stakeholders. The
Commission proposes one reform to
increase the responsiveness of RTO/ISO
boards and seeks comment on whether
any other reforms are necessary.
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A. The Challenge of Improving RTO and
ISO Responsiveness to Stakeholders
134. Order Nos. 888 and 2000 require
that an ISO or RTO be independent from
market participants. The Commission
requires this independence to ensure
that market participants have
nondiscriminatory access to the grid
and market rules are developed and
administered in a manner that does not
favor one market participant over
another. After five to ten years of
experience with several such entities,
however, some stakeholders are
concerned that RTOs and ISOs have
achieved independence without being
adequately sensitive to the needs of
their customers and members.
135. Given the size and complexity of
RTOs and ISOs today, it is not
surprising that tension has arisen
between the goals of independence and
responsiveness. An RTO or ISO cannot
satisfy every group on every issue.
When an RTO or ISO makes a difficult
decision, those who support the
decision often believe it has acted
‘‘objectively’’ and ‘‘independently,’’
while those who oppose that decision
often believe the RTO or ISO has not
been ‘‘responsive’’ to their concerns.
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136. This natural tension between
independence and responsiveness is
compounded by the number of
functions that an RTO or ISO performs
and for which it is ultimately held
accountable by these several types of
entities. An RTO or ISO has the primary
responsibility to operate the regional
transmission system safely in
accordance with good utility practice
and reliably in accordance with
Commission-approved reliability
standards. It is responsible for providing
open and non-discriminatory
transmission access under a regional
transmission tariff. The provision of
open-access transmission service in
itself requires that many subordinate
functions be carried out, such as
maintaining an efficient transmission
reservation system, scheduling
transmission services, managing
congestion on the grid, coordinating
local transmission system
enhancements, and developing the
region’s long-term transmission plan.
RTOs and ISOs typically have adopted
innovative transmission pricing
mechanisms such as locational pricing
with allocations or auctions of financial
transmission rights that hedge
transmission congestion.
137. An RTO or ISO is also
responsible for administering the
organized energy markets. Depending
on the region, there are day-ahead and
real-time energy markets, markets for
various ancillary services, and forward
capacity markets, with provisions for
ensuring that demand response
resources can participate in these
markets. It is responsible for all aspects
of operation of these markets and for
providing an independent market
monitor. The RTO or ISO may also have
responsibilities regarding resource
adequacy. Every RTO or ISO must
maintain a reliable system for metering
and measuring power flows and
customer services systems for billing
and settling accounts for many large
financial transactions.
138. As an RTO’s or ISO’s functional
responsibilities grow, some customers
may value the new functions while
others prefer the regional organization
to focus on its original basic functions.
New services come at a cost. Start-up
costs can be significant for new services,
and the RTO or ISO must decide how
to recover the costs from its customers.
These decisions may be controversial. In
particular, determining who benefits
from new transmission facilities and
how their costs should be allocated can
be very contentious and can lead to
customer dissatisfaction with the RTO
or ISO. Decisions related to resource
adequacy, such as whether to adopt
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capacity markets or to rely more heavily
on energy price signals to incent new
generation and demand response, have
also become very contentious.
139. Given these challenges, the
Commission is considering, as
discussed further below, proposals to
improve RTO/ISO responsiveness in a
manner that does not compromise their
independence.
B. Prior Commission Actions Regarding
RTO and ISO Responsiveness
140. In Order No. 888, the
Commission encouraged but did not
require the formation of ISOs. Order No.
888 delineated eleven principles
defining the operations and structure of
a properly functioning ISO.106
Similarly, in Order No. 2000, the
Commission encouraged utilities to join
RTOs voluntarily and set out the
characteristics that an RTO must
possess and the minimum functions that
it must perform.107 Embodied in both
Order Nos. 888 and 2000 is the
requirement that the regional
transmission entity be independent
from market participants so that it can
provide regional transmission and
energy market services on a nondiscriminatory basis.
141. Although it required
independence, Order No. 2000 did not
mandate detailed governance
requirements for an RTO board of
directors. Instead, it stated that the
Commission would review governance
proposals on a case-by-case basis.108
The Commission emphasized the
importance of stakeholder input
regarding both RTO formation and
ongoing operations, and it required the
RTO or ISO to consult with its members
and other stakeholders through an
advisory committee prior to taking
action. The Commission stated that,
because there is a non-stakeholder
board, it is important that this board not
become isolated.109 For this reason, the
Commission explained that there should
be both formal and informal
mechanisms to ensure that stakeholders
can convey their concerns to the nonstakeholder board.
142. The Commission also required
that RTOs have an ‘‘open architecture’’
so that the organization and its members
have the necessary flexibility to improve
the structure, geographic scope, market
scope, and operations of the
106 Order No. 888, FERC Stats. & Regs.,
Regulations Preambles January 1991–June 1996
¶ 31,036 at 31,730–32.
107 Order No. 2000, FERC Stats. & Regs.,
Regulations Preambles July 1996–December 2000
¶ 31,089 at 30,993–94.
108 Id. at 31,073–74.
109 Id.
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organization, as long as proposed
changes continue to satisfy RTO
minimum characteristics and
functions.110 Stated another way, ‘‘open
architecture’’ meant that the original
RTO design could evolve as needed to
reflect changes in member needs.
143. Over the past few years, many
RTO and ISO customers have raised
concerns at the Commission about RTO
or ISO responsiveness to customers on
such matters as the level or growth rate
of RTO or ISO administrative costs and
the effectiveness of the customer voice
in processes for deciding whether to
undertake new expenditures. In
response to concerns over accounting
and financial reporting rules for RTOs
and ISOs, the Commission issued a
Financial Reporting Notice of Inquiry
(NOI) on September 16, 2004. It asked
for comments on RTO and ISO
accounting matters and whether RTOs
and ISOs have appropriate incentives to
be cost-effective.111 This led directly to
Commission Order No. 668, Accounting
and Financial Reporting for Public
Utilities Including RTOs.112 Order No.
668 amended the Commission’s
regulations to update the accounting
requirements for public utilities and
licensees, including RTOs and ISOs.
Specifically, Order No. 668 created new
financial accounts to better categorize
costs and changed the reporting
requirements for all public utilities,
including RTOs and ISOs, to improve
financial reporting of operations,
revenue, and expense accounts. The
new financial reporting requirements
allow the Commission and other
interested persons to compare public
utility expenditures more readily than
under the prior rule, which improves
the transparency of financial
information and facilitates clear
understanding of RTO/ISO costs.113
144. In addition to Commission
actions, RTOs and ISOs themselves have
undertaken efforts to improve relations
and communications with customers
and other stakeholders. For example,
the CAISO has enhanced its
participatory budget development
process to allow stakeholders to ask
questions and raise concerns well before
110 Id.
at 31,170.
Reporting and Cost Accounting and
Recovery Practices for Regional Transmission
Organizations and Independent System Operators,
Notice of Inquiry, FERC Stats. & Regs. ¶ 35,546
(2004).
112 Accounting and Financial Reporting for Public
Utilities Including RTOs, Order No. 668, 70 FR
77,626 (Dec. 30, 2005), FERC Stats. & Regs.,
Regulations Preambles 2001–2005 ¶ 31,199 (2005),
order on reh’g, Order No. 668–A, 71 FR 28,513 (May
16, 2006), FERC Stats. and Regs. ¶ 31,215 (2006).
113 Order No. 668, FERC Stats. & Regs.,
Regulations Preambles 2001–2005 ¶ 31,199 at P 5.
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111 Financial
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the budget becomes final. PJM, at the
request of its stakeholders, has
introduced procedures under which
stakeholder issues may be immediately
reviewed by the board.114 PJM has also
proposed to reintroduce a stakeholder
‘‘liaison committee’’—a committee of
stakeholder representatives that will
advise the PJM board directly—and is
seeking stakeholder input on how that
committee should be structured.115
145. The Commission is considering
below whether additional reforms
should be adopted to further increase
RTO and ISO responsiveness.
C. Proposed Commission Action To
Improve RTO and ISO Responsiveness
146. In this section, the Commission
proposes reforms related to ISO and
RTO boards and seeks comment on
whether any other reforms are
appropriate.
1. A Responsive RTO or ISO Board of
Directors 116
147. Customer responsiveness must
begin with the RTO/ISO board. A wellfunctioning and responsible board of
directors is necessary for establishing
the strategic direction of the RTO or
ISO, including customer orientation.
Board members are expected to have the
expertise needed to set such direction
and assess whether it is being followed
successfully. When approving an
application for RTO status, the
Commission has considered primarily
the independence of board members in
the board selection process.117
148. The Commission’s preliminary
conclusion is that representatives of
customers and other stakeholders must
have some form of effective direct
access to the board of directors. Each
RTO or ISO would be required to
develop and implement a means to
ensure that customers and other
stakeholders have effective direct access
to the board. The mechanism would not
have to be the same for each RTO or
ISO. One RTO or ISO might choose to
form a committee of stakeholder
114 See May 4, 2007 letter from Phillip G. Harris,
Chairman and CEO, PJM Interconnection, L.L.C., to
PJM Members and Stakeholders, at
https://www.pjm.com/committees/members/
postings/20070504-letter-to-members-post.pdf. See
also Transcript of Conference at 204, Conference on
Competition in Wholesale Power Markets, Docket
No. AD07–7–000 (May 8, 2007).
115 Id.
116 The term ‘‘board of directors’’ is used in this
ANOPR to refer to the highest governing body.
Certain RTOs and ISOs may use another term. For
example, the California Independent System
Operator Corporation uses the term ‘‘Board of
Governors.’’
117 Grid Florida, L.L.C., 94 FERC ¶ 61,020 (2001);
Arizona Public Service Co., 101 FERC ¶ 61,033,
order on reh’g, 101 FERC ¶ 61,350 (2002).
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36295
representatives with some form of direct
access to the board, and this committee
may be distinct from the various
technical committees that have already
been formed. Another RTO or ISO might
choose to create direct access by having
a hybrid board of directors composed of
both independent members and
representatives of stakeholders. A third
RTO or ISO might devise a distinct third
means. However, each mechanism
would have to be effective in allowing
customers and other stakeholders to
present their views on major issues
directly to the board.
149. The Commission seeks comment
on whether RTO or ISO responsiveness
to stakeholders requires some form of
direct board access. If so, what steps can
be taken to ensure that both majority
and minority interests have access to the
board? If not, is there a better way to
ensure that RTO and ISO boards of
directors are responsive to customers?
150. The Commission stresses its
intent to be flexible regarding how the
RTOs and ISOs may improve
responsiveness to stakeholders. As
mentioned, at least two mechanisms, if
carefully designed and implemented,
could accomplish this, hybrid boards
and board advisory committees.
151. A hybrid board would be
composed of both independent
members and stakeholder members.
Each member would have a seat on the
board and participate fully in board
decisions with an equal vote. The
Commission believes it should be
possible to structure a hybrid board that
does not sacrifice overall board
independence.118 Adding nonindependent stakeholders to the board
would expose the board to the concerns
of stakeholders in the most direct
manner.
152. An RTO or ISO that intends to
satisfy this proposed requirement with a
hybrid board would have to address
certain matters. Stakeholder members
must not be allowed to serve their own
interests inappropriately. Accordingly,
the Commission presents here for
comment certain restrictions that may
be necessary for a hybrid board
proposal. First, the number of
stakeholder members must be a
minority of the board. The stakeholder
members cannot make up more than
forty-nine percent of the board, and a
lower percentage such as twenty-five
percent may be more appropriate.
Second, all subcommittees of the board
should be structured so that the
118 We remind RTOs and ISOs that the
Commission’s regulations regarding RTO
governance require periodic audits of the RTO or
ISO governance by an independent auditor. See 18
CFR 35.34(j)(1)(iv)(A) (2006).
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stakeholder members together cannot
overcome the unanimous vote of the
independent board members. Third, any
appointment to an RTO or ISO board of
a senior official or director of a
stakeholder company that would
constitute an interlocking directorate
position under FPA section 305 119
would require prior Commission
approval before the member would join
the RTO/ISO board.120
153. A second way to satisfy the
proposed requirement would be a board
advisory committee. It would be
comprised of senior executives of the
various stakeholder groups, serving as
an expert panel that would inform the
board of stakeholder views. The board
advisory committee would have no
voting authority on board decisions. It
would, however, have authority to make
recommendations directly to the board
on matters before the board and on
matters it believes the board should
address. The board advisory committee
could advise the board about the
expected effect on customers and other
stakeholder groups of proposals before
the board. The board advisory
committee would not necessarily make
decisions on what to recommend to the
board; instead, minority views could
also be presented directly to the board.
154. The Commission envisions a
board advisory committee of senior
stakeholder representatives that would
not necessarily consist of those on
technical stakeholder committees in
RTOs and ISOs today. Members of the
board advisory committee would be
selected to represent a reasonable range
of diverse interests. The number of
members should be decided with
attention to forming a committee of
reasonable size that can engage the
board in thoughtful discussion.
155. The Commission encourages
interested parties to comment regarding
the proposal and possible approaches.
In addition, the Commission seeks
responses to the following questions
about customer access to the board of an
RTO or ISO:
• How should any hybrid board be
structured? What is an appropriate limit
on the percentage of non-independent
board members? If a variety of customer
views are to be represented, what
implications does this have for the size
of the board?
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119 16
U.S.C. § 825d (2000).
16 U.S.C. 825d(b)–(c) (2000); 18 CFR 45
(2006). Pursuant to section 305(b) of the FPA,
interlocks between unaffiliated public utilities,
interlocks between a public utility and other
specified entities, and interlocks among affiliated
public utilities must be submitted to the
Commission for approval before a prospective
director holds and assumes the duties of the
interlocking position.
120 See
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• What, if any, rules and restrictions
should be placed on the stakeholder
board members of a hybrid board?
• Can the reform proposed here be
met through other means such as
increased direct board interaction with
customers and other stakeholders, e.g.,
through open board meetings or through
required attendance of board members
at major stakeholder meetings of the
RTO?
• Are there measures—such as
customer satisfaction measures, cost
oversight benchmarks, or stakeholder
participation measures—that RTOs and
ISOs should use to assess the success of
the mechanism for improving
responsiveness?
2. Inquiry Regarding Better
Responsiveness Through Improved
Practices and Processes
156. The Commission also requests
comment about whether any other
reforms should be adopted to improve
RTO and ISO responsiveness to its
customers and other stakeholders. The
Commission is interested in particular
in whether RTOs and ISOs could
achieve better responsiveness—or make
their responsiveness more apparent to
their stakeholders—through
improvements in the areas of (1) RTO
and ISO executive management
practices, (2) effective RTO and ISO
stakeholder processes, and (3)
transparent RTO and ISO budget
processes.
a. RTO and ISO Executive Management
Practices
157. Executive management ensures
that RTO and ISO goals set by the board
are met, including any goal to be
responsive to customers and other
stakeholders. Executive management
evaluates such things as how to improve
RTO/ISO services, whether to provide
new services, and how to contain
administrative costs. Management is
likely to be the first to hear directly from
customers about their concerns with
current RTO/ISO operations or
proposed new programs or
expenditures.
158. Managers should be responsive
to stakeholders but cannot be beholden
to any particular stakeholder group. At
a minimum, managers should seek out
customer concerns and pay serious
attention to these concerns. Managers
should evaluate whether some
appropriate action is needed to address
these concerns. They may decide to
address some concerns and not others,
keeping in mind the independence of
the RTO or ISO, its appropriate role in
the region as transmission provider and
market administrator, and the trade-off
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between new services and cost
containment.
159. The Commission requests
comment on whether any reforms are
necessary to increase management
responsiveness to stakeholder concerns.
For example, should the Commission
encourage or require RTOs or ISOs to:
• Publish a strategic plan that
includes plans for assuring
responsiveness to customers and other
stakeholders.
• Measure or otherwise assess
customer satisfaction periodically,
through a survey or other means.
• Have a formal process for gathering
and evaluating recommendations for
improving services to customers.
• Set performance criteria for
executive managers based in part on
responsiveness to stakeholders.
• Relate executive compensation to a
measure of responsiveness to
stakeholders.
b. Effective RTO and ISO Stakeholder
Processes
160. The stakeholder processes in
RTOs and ISOs today serve several
purposes. They are intended to provide
the views of various customer and
stakeholder groups to the RTOs and
ISOs. Some are also intended to help the
RTOs and ISOs make decisions on
sometimes contentious transmission
and market matters. The Commission is
interested in comments about how well
these processes are working and how
their effectiveness might be improved.
161. The Commission requests replies
to the following questions about RTO
and ISO stakeholder processes:
• What stakeholder processes have
proved to be particularly effective?
• How can the effectiveness of a
stakeholder process be assessed?
• Does the voting structure of RTO
and ISO stakeholder groups achieve
balanced representation?
• Are minority interests adequately
represented in stakeholder processes?
• How should an RTO or ISO respond
when it must make a decision, such as
deciding how to comply with a
Commission regulation, and a
stakeholder consensus cannot be
reached?
• What actions, if any, can the
Commission take to improve
stakeholder processes? For example,
should the Commission ask each RTO or
ISO to review and report on the
strengths and weaknesses of its current
stakeholder processes?
c. Transparent RTO and ISO Budgeting
Processes
162. Some market participants
contend that they do not have an
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adequate opportunity to review or
understand an RTO’s or ISO’s budget in
time to influence the budget decision.
They point in particular to RTOs and
ISOs that use a formula rate to pass
costs through to customers. Although
the Commission has found the current
cost recovery mechanisms for all these
entities to be just and reasonable,121
stakeholders express concern about
ineffective review of significant cost
increases before the costs flow through
a formula rate. The NYISO and Midwest
ISO, for example, recover their costs of
administering the transmission grid and
market operations through a formula
rate.122 Some customers believe that the
budget for an RTO or ISO with a
formula rate may not include enough
details to understand the reason for an
expenditure or its effect on their
rates.123 This suggests that, in an RTO
or ISO with a formula rate, there may be
a greater need for customer discussion
of budget decisions with major cost
consequences before the costs are
incurred.
163. The Commission requests
comment on possible approaches to
address these concerns. For example,
should each RTO and ISO:
• Review its cost accountability
processes with its customers and other
stakeholders and consider how to
improve them?
• Present budget information to
customers with adequate detail,
transparency, and cost support? For
example, an RTO or ISO with a formula
rate could develop its budget
presentation to stakeholders using the
format required for a filing with the
Commission to change a previously-
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121 See
California Independent System Operator
Corp., 103 FERC ¶ 61,114 (2003), order on reh’g,
106 FERC ¶ 61,032 (2004); California Independent
System Operator Corp., 110 FERC ¶ 61,090 (2005);
Midwest Independent Transmission System
Operator, Inc., 97 FERC ¶ 61,033 (2001); Midwest
Independent Transmission System Operator, Inc.,
101 FERC 61,221 (2002), order on reh’g, 103 FERC
¶ 61,035 (2003); New England Power Pool, 96 FERC
¶ 61,261 (2001); ISO New England, Inc., 105 FERC
¶ 61,397 (2003); New York Independent System
Operator, 86 FERC ¶ 61,062 (1999); PJM
Interconnection, L.L.C., 112 FERC 61,236 (2005),
order approving settlement, 115 FERC ¶ 61,249
(2006).
122 The CAISO, PJM, and ISO–NE, in contrast, use
stated rates for their grid administration and market
services charges.
123 After-the-fact review is considered
insufficient. Even if the Commission were to
disallow an expenditure after the fact as not used
and useful or otherwise imprudently incurred, an
RTO or ISO has no profits to be reduced by the
amount of any disallowed costs. Many market
participants assert that there is no good remedy for
these RTOs and ISOs once imprudent costs are
incurred. RTO and ISO customers are among the
first to tell the Commission that, in practice, once
costs are incurred by a not-for-profit RTO or ISO
with a formula rate, these costs must be passed
through to its customers.
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22:50 Jun 29, 2007
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filed stated rate. This would provide
stakeholders with clear information
about the proposed expenditures, its
effect on rates, and how the proposed
budget relates to recent budgets.
• Provide its customers a timely
opportunity to review budget proposals,
ask budget questions, and comment
before major expenditures are finally
decided?
• Submit to the Commission as an
informational filing the budget materials
provided to stakeholders for review?
VII. Additional Questions
164. It is our preliminary view that
that the Commission should institute a
proceeding under section 206 of the
FPA 124 to reform RTO and ISO tariffs to
address certain issues discussed above.
The Commission may conduct this
process either through a notice-andcomment rulemaking under the
Administrative Procedure Act 125 or an
adjudicative process.
165. The Commission requests
comment on which of these procedures
is likely to produce the most effective
reforms, and on the appropriate time
frame in which to conduct the
proceedings. The Commission also
seeks input as to the length of time that
might be necessary for RTOs and ISOs
to implement any reforms that result
from this process. Specifically, the
Commission requests input as to how
much time—including time for
stakeholder processes—might be needed
for technical development of
compliance filings.
VIII. Comment Procedures
166. The Commission invites
interested persons to submit comments
on these matters and any related matters
or alternative proposals that
commenters may wish to discuss.
Comments are due August 16, 2007.
Comments must refer to Docket No.
AD07–7–000 and must include the
commenter’s name, the organization he
or she represents, if applicable, and his
or her address.
167. Comments may be filed
electronically via the eFiling link on the
Commission’s Web site at https://
www.ferc.gov. The Commission accepts
most standard word processing formats
and commenters may attach additional
files with supporting information in
certain other file formats. Commenters
filing electronically do not need to make
a paper filing.
168. Commenters that are not able to
file comments electronically must send
an original and 14 copies of their
124 16
125 5
PO 00000
U.S.C. 824e (2000).
U.S.C. 553 (2000).
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comments to: Federal Energy Regulatory
Commission, Secretary of the
Commission, 888 First Street, NE.,
Washington, DC, 20426.
169. All comments will be placed in
the Commission’s public files and may
be viewed, printed, or downloaded
remotely as described in the Document
Availability section below. Commenters
are not required to serve copies of their
comments on other commenters.
IX. Document Availability
170. In addition to publishing the full
text of this document in the Federal
Register, the Commission provides all
interested persons an opportunity to
view and/or print the contents of this
document via the Internet through
FERC’s Home Page (https://www.ferc.gov.
and in FERC’s Public Reference Room
during normal business hours (8:30 a.m.
to 5 p.m. Eastern time) at 888 First
Street, NE., Room 2A, Washington, DC
20426.
171. From the Commission’s Home
Page on the Internet, this information is
available in its eLibrary. The full text of
this document is available in the
eLibrary both in PDF and Microsoft
Word format for viewing, printing, and/
or downloading. To access this
document in eLibrary, type the docket
number of this document, excluding the
last three digits, in the docket number
field.
172. User assistance is available for
eLibrary and FERC’s Web site during
normal business hours from our Help
line at (202) 502–8222 or the Public
Reference Room at
public.reference@ferc.gov.
By direction of the Commission.
Commissioner Kelly concurring in part and
dissenting in part with a separate statement
attached.
Kimberly D. Bose,
Secretary.
KELLY, Commissioner, concurring in part
and dissenting in part:
I generally support the efforts of this
Advanced Notice of Proposed Rulemaking
(ANOPR) in setting forth proposals and
seeking comment on improvements to the
operation of organized wholesale electric
markets. I am writing separately to express
my views on certain of the proposals related
to strengthening market monitoring,
improving demand response and promoting
RTO/ISO responsiveness.
First, I would have added certain proposals
to the ANOPR to strengthen market
monitoring. For reasons I have previously
explained,126 I would have proposed
requiring RTOs/ISOs to file tariff provisions
to allow them to take enforcement action
with respect to objectively identifiable
126 See PJM Interconnection, L.L.C., 116 FERC
¶ 61,038, order on reh’g, 117 FERC ¶ 61,263 (2006).
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behavior that does not subject the seller to
sanctions or consequences other than those
expressly approved by the Commission and
set forth in the tariff, and with the right of
appeal to the Commission, consistent with
the Policy Statement on Market Monitoring
Units.127 In addition, the ANOPR states that
the Commission does not intend to share
with the MMU information about suspected
tariff and rule violations referred by the
MMU to the Commission. I believe the
Commission should generally provide
information to the MMUs on the referrals
they have made to the Commission, subject
to appropriate confidentiality restrictions.
Such feedback could be structured so as to
provide responsible disclosure of information
while preserving confidentiality. In addition,
I would have proposed requiring the MMU
to make recommendations related to its
reports on RTO/ISO performance. Therefore,
I concur in part on the ANOPR.
Second, I disagree with two of the
proposals being made in the ANOPR. One
proposal involves facilitating greater
participation of demand response in
organized markets by modifying market
power mitigation rules in organized markets,
such as raising the energy bid caps and
market-wide caps in an emergency situation.
Before the Commission considers whether to
pursue such market rule modifications, I
think it is important to address other barriers
that may significantly restrict demand
response participation. For example, the
FERC Staff Demand Response Assessment
concluded that the technologies needed to
support significant deployment of demand
resources, such as advanced metering, have
little market penetration.128 Without the
necessary technology already in place that
would allow demand resources to respond to
price signals in wholesale or retail markets,
it is unclear how quickly they could develop
the ability to respond after energy bid caps
or market-wide caps are raised or eliminated.
In other words, the technology and
111 FERC ¶ 61,267 (2005) at P 5.
128 FERC Staff Demand Response Assessment,
Docket No. AD06–2–000, at page xii.
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127 See
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associated demand response capability must
be in place before we consider raising or
eliminating these price caps. Otherwise these
higher energy prices may not elicit any
demand reduction in a fashion capable of
disciplining those prices and keeping them
just and reasonable. In addition, rather than
asking questions in this ANOPR on how to
value demand response, I think the
Commission should have proposed a
compensation method and postponed
consideration of modifying market power
mitigation rules until after the valuation
issue had been addressed.
Third, although I recognize that some
stakeholder groups have raised concerns
about the responsiveness of the RTO/ISO, I
disagree with the ANOPR’s proposal to
promote responsiveness by establishing a
hybrid RTO/ISO board of directors composed
of both independent members and nonindependent stakeholder members. Under
this proposal, each member would have a
seat on the board and participate fully in
board decisions with an equal vote. I think
it would be inadvisable and difficult to
implement such a proposal.
Order Nos. 888 and 2000 require that an
ISO or RTO be independent from market
participants so that they can provide regional
transmission and energy market services on
a non-discriminatory basis. A fundamental
principle for ISOs, as set forth in Order No.
888, is that the ISO should be independent
of any individual market participant or any
one class of participants (e.g., transmission
owners or end-users).129 Similarly, Order No.
2000 emphasized that independence is the
bedrock principle on which the ISOs and
RTOs must be built and stressed that an RTO
‘‘needs to be independent in both reality and
perception.’’130 I believe that establishing a
hybrid board would jeopardize the
fundamental principle of independence upon
which ISOs and RTOs are based.
129 Order No. 888, FERC Stats. & Regs. ¶ 31,036
at 31,730–31.
130 Order No. 2000, FERC Stats. & Regs. ¶ 31,089
at 31,061.
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Moreover, although the ANOPR states that
stakeholder members would be directed not
to serve their own interests inappropriately,
it is not clear to me how one would
distinguish between ‘‘inappropriate’’
advocacy for one’s interests, and perfectly
reasonable advocacy for one’s interests.
Additionally, a hybrid board composed of
independent and non-independent board
members could needlessly complicate the
board dynamic and make cooperative
decision-making more difficult and time
consuming. Currently, the independent board
coupled with the stakeholder process, can be
viewed as similar to the judicial model of
governance. The stakeholders are like
adversaries in a judicial proceeding arguing
their cases to a disinterested judge, the
independent board, which is capable of
balancing the various equities in reaching a
timely decision that is fair to all.
A stakeholder board, even a hybrid one,
would be more akin to the legislative model
with no overarching independent judge
making the final calls. Such a model requires
constant negotiation and can often lead to
stalemate or decisions that address only the
lowest common denominator rather than the
ideal approach. While that model is certainly
appropriate in many situations, I do not
believe it is workable for the board of an RTO
or ISO given the many important and timecritical issues they deal with. Furthermore,
most investor owned utilities, with whom
RTOs and ISOs share many features, do not
appear to follow the legislative model of
governance and it is not clear to me why the
RTOs and ISOs should be treated differently.
If the Commission is to consider providing
stakeholders with some form of direct board
access, I think that the board advisory
committee proposed in this ANOPR would
more effectively serve this purpose.
Accordingly, for the reasons stated above,
I concur in part and dissent in part on this
ANOPR.
Suedeen G. Kelly
[FR Doc. E7–12550 Filed 6–29–07; 8:45 am]
BILLING CODE 6717–01–P
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]]>Agencies
[Federal Register Volume 72, Number 126 (Monday, July 2, 2007)]
[Proposed Rules]
[Pages 36276-36298]
From the Federal Register Online via the Government Printing Office [www.gpo.gov]
[FR Doc No: E7-12550]
[[Page 36275]]
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Part V
Department of Energy
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Federal Energy Regulatory Commission
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18 CFR Part 35
Wholesale Competition in Regions With Organized Electric Markets;
Proposed Rule
Federal Register / Vol. 72, No. 126 / Monday, July 2, 2007 / Proposed
Rules
[[Page 36276]]
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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.
-----------------------------------------------------------------------
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: https://www.ferc.gov. Follow the
instructions for submitting comments via the eFiling link found in the
Comment Procedures section of the ANOPR.
Mail: Commenters unable to file comments electronically
must mail or hand deliver an original and 14 copies of their comments
to the Federal Energy Regulatory Commission, Secretary of the
Commission, 888 First Street, NE., Washington, DC 20426. Please refer
to the Comment Procedures section of the ANOPR for additional
information on how to file paper comments.
FOR FURTHER INF0RMATION CONTACT:
David Kathan (Technical Information), Office of Energy Markets and
Reliability, Federal Energy Regulatory Commission, 888 First Street,
NE., Washington, DC 20426, David.Kathan@ferc.gov, (202) 502-6404.
Elizabeth Rylander (Legal Information), Office of the General Counsel,
Federal Energy Regulatory Commission, 888 First Street, NE.,
Washington, DC 20426, Elizabeth.Rylander@ferc.gov, (202) 502-8466.
SUPPLEMENTARY INFORMATION:
Paragraph
numbers
I. Introduction............................................ 1
II. Background............................................. 4
A. Brief History....................................... 14
B. Competition Issues and Commission Actions........... 25
C. Issues Addressed in the ANOPR....................... 30
III. Demand Response and Pricing During Power Shortages in 34
Organized Markets.........................................
A. Importance of Demand Response to Competition in RTO/ 36
ISO Areas.............................................
B. Prior Commission Actions To Address Demand Response. 41
C. Remaining Problems with Demand Response in Organized 47
Markets...............................................
D. Proposed Commission Actions To Improve Demand 57
Response and Market Pricing During a Power Shortage...
IV. Long-Term Power Contracting in Organized Markets....... 83
A. Importance of Long-Term Power Contracts and Factors 84
Affecting Contracting Decisions by Buyers and Sellers.
B. Commission Actions To Support Long-Term Power 88
Contracts.............................................
C. Proposed Commission Actions To Facilitate Long-Term 92
Power Contracting.....................................
V. Market Monitoring Policies.............................. 95
A. History of Market Monitoring........................ 98
B. Independence and Function........................... 108
C. Information Sharing................................. 122
D. Pro Forma Tariff Section............................ 131
E. Conclusion.......................................... 132
VI. Responsiveness of RTOS and ISOS........................ 133
A. The Challenge of Improving RTO and ISO 134
Responsiveness to Stakeholders........................
B. Prior Commission Actions Regarding RTO and ISO 140
Responsiveness........................................
C. Proposed Commission Action To Improve RTO and ISO 146
Responsiveness........................................
VII. Additional Questions.................................. 164
VIII. Comment Procedures................................... 166
IX. Document Availability.................................. 170
I. Introduction
1. The Federal Energy Regulatory Commission (Commission) is
considering potential reforms to improve the operation of organized
wholesale electric markets.\1\ In response to issues raised by various
market participants and industry observers about improvements to
enhance wholesale electric markets, the Commission held two
conferences, on February 27, 2007 and May 8, 2007, to learn more about
these issues. The first dealt with all wholesale power markets while
the second focused on organized RTO/ISO markets. Based on the comments
received at these two conferences, the Commission identified four
specific and narrow issues, as described below, that are not already
being fully addressed by the Commission in other proceedings and that
may be appropriate to address in a generic proceeding.
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\1\ Organized market regions are areas of the country in which a
regional transmission organization (RTO) or independent system
operator (ISO) operates day-ahead and/or real-time energy markets.
---------------------------------------------------------------------------
2. These issues are: (1) The role of demand response in organized
markets, including greater reliance on market prices to elicit demand
reductions during power shortages; (2) increasing opportunities for
long-term power contracting; (3) strengthening market monitoring; and
(4) the responsiveness of RTOs and ISOs to customers and other
stakeholders. This Advance Notice of Proposed Rulemaking (ANOPR)
identifies specific concerns in these four areas and presents the
Commission's preliminary views on proposed reforms.\2\ The Commission
seeks
[[Page 36277]]
comments on the proposed reforms. After receiving and considering these
comments, the Commission will determine whether to issue a Notice of
Proposed Rulemaking (NOPR) and the scope of the proposed rule, if a
NOPR is warranted.
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\2\ Throughout this document, the term ``propose'' is used as a
short form of stating that it is the Commission's preliminary view
that the proposal that follows may be a reasonable way to achieve a
regulatory objective, and that the Commission requests comments on
the proposal and on alternative recommendations for achieving the
objective.
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3. Finally, the actions proposed here are intended to complement
other Commission actions, discussed further below, intended to improve
the operation of wholesale competition in regions with and without RTOs
and ISOs and their organized markets. There are opportunities to
improve the operation of wholesale markets in both types of regions.
Many of the Commission's prior actions--such as Order No. 890 \3\--
apply to both types of regions, while others by their nature apply only
to RTO/ISO regions, such as assuring load-serving entities (LSEs) of
long-term transmission rights in regions with locational marginal
pricing and congestion hedges. The issues being explored in this
proceeding are discrete and apply to regions with organized spot
markets, market monitors, and an RTO or ISO. The actions considered
address concerns that numerous market participants and many of our
state colleagues have raised in this proceeding and elsewhere. The
Commission is not seeking to fundamentally redesign organized markets
or to appropriate jurisdiction from our state colleagues. Our goal is
to make incremental improvements to the operation of organized markets
without undoing or upsetting the significant efforts that have already
been made in providing demonstrable benefits to wholesale customers. In
particular, we acknowledge and commend the ISOs and RTOs and their
respective transmission owners and stakeholders for their work over the
past several years in fulfilling the Commission's policies supporting
wholesale competition and non-discriminatory access to transmission.
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\3\ Preventing Undue Discrimination and Preference in
Transmission Service, Order No. 890, 72 FR 12,266 (Feb. 16, 2007),
FERC Stats. & Regs. ] 31,241 (2007), reh'g pending (Reform of the
Open Access Transmission Tariff (OATT) rules or OATT Reform).
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II. Background
4. National policy for many years has been, and continues to be, to
foster competition in wholesale power markets. As the third major
federal law enacted in the last 30 years to embrace wholesale
competition, the Energy Policy Act of 2005 (EPAct 2005) \4\
strengthened the legal framework for continuing wholesale competition
as federal policy for this country.
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\4\ Pub. L. No. 109-58, 119 Stat. 594 (2005).
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5. The Commission's core responsibility is to ``guard the consumer
from exploitation by non-competitive electric power companies.'' \5\
The Commission has always used two general approaches to meet this
responsibility--regulation and competition. The first was the primary
approach for most of the last century and remains the primary approach
for wholesale transmission service, and the second has been the primary
approach in recent years for wholesale generation service.
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\5\ National Association for the Advancement of Colored People
v. FPC, 520 F.2d 432, 438 (D.C. Cir. 1975), aff'd, 425 U.S. 662
(1976).
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6. The Commission has never relied exclusively on competition to
assure just and reasonable rates and has never withdrawn from
regulation of wholesale electric markets. Rather, the Commission has
shifted the balance of the two approaches over time as circumstances
changed. Advances in technology, exhaustion of economies of scale in
most electric generation, and new federal and state laws have changed
our views of the right mix of these two approaches. Our goal has always
been to find the best possible mix of regulation and competition to
protect consumers from the exercise of monopoly power.
7. In each major energy bill over the last few decades, Congress
has acted to open up the wholesale electric power market by
facilitating entry of new generators to compete with traditional
utilities. The Commission has acted quickly and strongly over the years
to implement this national policy.
8. Congress has not deregulated the wholesale electric power
business, however, and the Commission has not done so by regulation. To
the contrary, the Commission has issued many new regulations and orders
designed to foster competition nationally and to support competitive
markets in specific regions. Because the United States does not have a
national electric power market, our approach to implementing
competition has been to recognize and foster the development of
regional markets.
9. There are significant differences among the regional wholesale
power markets. There are differences in industry structure, differences
in the mix of ownership (such as investor-owned, cooperatively-owned,
and publicly-owned utilities), differences in the mix of fuels and
energy sources for electric generation, and differences in population
densities and weather patterns, to name a few. Some regions pursue
wholesale competition exclusively by relying on direct bilateral
contracting between sellers and buyers, and others employ a mix of
bilateral contracting with organized spot markets and other markets to
increase opportunities for the sale or purchase of electric power. In
regions with organized spot markets, the markets are administered by an
RTO or ISO, which themselves have differences regarding such matters as
market design, transmission responsibilities, and decision-making
procedures. The Commission's approach to supporting wholesale
competition is to recognize and respect these differences in market
structure and other differences across the various regions.
10. Wholesale competition can serve customers well in all regions,
including RTO and ISO regions with organized markets and regions
without such organizations and markets. There are strengths and
weaknesses to the approach taken by each, and wholesale competition
faces challenges in both areas.
11. The best way to address these challenges may differ among the
regions, however. For example, in all regions the cost of the fuels
used for electric generation has increased in recent years, as it has
throughout the world. Those regions of the United States that depend on
natural gas for electric generation have felt this the most.
Competitive spot markets reflect these cost changes quickly in market
prices, while longer-term fixed price bilateral contracts or cost-of-
service regulation may reflect cost increases or decreases more
gradually in the wholesale price. Wholesale customers in all regions
want better long-term contracting opportunities. All regions face the
problem that retail customers are often unaware of supply shortages and
continue their normal consumption even on days when supplies are tight
and wholesale prices are high. Allocating the costs of a major new
regional transmission facility fairly is a challenge faced by every
region.
12. Regions with an RTO or ISO may be better able than other
regions to address some of these issues, but they may also face more
difficult challenges. For example, much of the recent dissatisfaction
with organized competitive markets appears to be directly linked to
rising natural gas prices.
13. National policy is to promote wholesale competition in all
regions, and customers now are calling especially for actions to
improve the operation of wholesale competitive
[[Page 36278]]
markets in the organized market regions. Hence, the focus of this ANOPR
is not whether wholesale competition is the correct federal policy; the
focus is on further improving the operation of wholesale competitive
markets in organized market regions.\6\ The Commission seeks comment on
proposed reforms to improve the operation of wholesale markets in these
regions.
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\6\ There are organized markets in the following RTOs and ISOs:
PJM Interconnection, L.L.C. (PJM), New York Independent System
Operator, Inc. (NYISO), Midwest Independent Transmission System
Operator, Inc. (Midwest ISO), ISO New England, Inc. (ISO-NE),
California Independent Service Operator Corp. (CAISO), Southwest
Power Pool, Inc. (SPP), and the Electric Reliability Council of
Texas (ERCOT).
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A. Brief History
14. Numerous federal and state legislative and regulatory
activities have supported competition in the U.S. electric industry
over the last three decades. Congress enacted the Public Utility
Regulatory Policies Act of 1978 (PURPA) \7\ as a response to the energy
crises of the 1970s. PURPA required electric utilities to interconnect
with, and offer to purchase power from, qualifying cogeneration and
small power production facilities at avoided cost rates set by state
regulatory authorities. It gave the Commission limited authority to
order wholesale transmission on a case-by-case basis, upon application
by an eligible entity. A consequence of PURPA was the emergence of a
new class of power generators that were independent of traditional
utilities.
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\7\ Pub. L. No. 95-617, 92 Stat. 3117 (codified in scattered
sections of 15, 16, 26, 30, 42, and 43 U.S.C.) (1978).
---------------------------------------------------------------------------
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).
---------------------------------------------------------------------------
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 https://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
[[Page 36279]]
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 https://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 https://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), https://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 https://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
https://tonto.eia.doe.gov/dnav/ng/hist/n9190us3a.htm.
\25\ See Summer Market Assessment. These NYMEX and ICE prices
are not estimates but prices actually produced on those two trading
systems.
\26\ Id.
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23. Some perceived challenges in the organized wholesale markets
may be closely related to difficulties in state retail choice programs.
Retail choice programs tend to be in areas served by organized
wholesale markets, and the distinction between wholesale and retail
competition challenges is often blurred. It appears that some areas
with retail choice depend on their RTO or ISO to provide or arrange for
the provision of some functions previously carried out by vertically
integrated utilities. This has created challenges for wholesale market
design, particularly with regard to whether it effectively provides for
resource adequacy. Because wholesale and retail markets are
intertwined, any examination of retail choice typically involves a
critique of the combination of the particular retail choice program and
the RTO's or ISO's wholesale market design.
24. The Commission continues to believe that wholesale competition
benefits customers by providing more choice, spurring innovative
services and technologies, shifting risk away from customers, improving
efficiency, and providing incentives for cost reductions and for the
construction of new resources. As stated above, the purpose of this
ANOPR is to explore reasonable proposals for improving wholesale
organized markets.
B. Competition Issues and Commission Actions
25. In proceedings outside this ANOPR, the Commission has addressed
or is addressing many issues related to improving wholesale electric
power competition in all regions, both with and without organized
markets. The Commission has taken actions to improve wholesale
transmission and competitive wholesale power opportunities.
26. The Commission's transmission actions have included reform of
the OATT, development of long-term transmission rights policies,
incentives for new transmission infrastructure, and approval of
transmission cost allocation policies. OATT reform applies to
transmission-owning and operating public utilities in all regions. It
adds greater consistency and transparency to available transfer
capability calculations, requires an open and coordinated regional
transmission planning process, and reforms energy imbalance charges.
Additionally, it provides for a new ``conditional firm'' point-to-point
transmission service. Long-term transmission rights in RTOs and ISOs
were strengthened in Order Nos. 681 and 681-A. These orders, as
directed by EPAct 2005, provide for long-term transmission price
certainty in the organized electricity markets, which supports long-
term power supply arrangements. In Order No. 679,\27\ the
[[Page 36280]]
Commission acted to bolster investment in the nation's transmission
infrastructure in response to section 1241 of EPAct 2005.\28\ This rule
allows those building transmission to apply for recovery of prudently
incurred costs for construction work in progress, pre-operations, and
abandoned facilities, and it provides for application for an incentive
rate of return on equity for new transmission investment. To further
encourage transmission investment, and provide certainty about who pays
for new transmission, the Commission, in separate orders for each RTO
or ISO--including two this year \29\--has approved cost allocation
policies for new and existing transmission, thereby removing any
barrier to new investment caused by uncertainty about transmission cost
allocation.
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\27\ Promoting Transmission Investment through Pricing Reform,
Order No. 679, 71 FR 43,294 (July 31, 2006), FERC Stats. & Regs. ]
31,222, order on reh'g, Order No. 679-A, 72 FR 1,152 (January 10,
2007), FERC Stats. & Regs. ] 31,236 (2006), order on reh'g, 119 FERC
] 61,062 (2007).
\28\ Section 1241 of EPAct 2005 is to be codified at section 219
of the FPA, 16 U.S.C. 824s.
\29\ PJM Interconnection, L.L.C., Opinion No. 494, 119 FERC ]
61,063 (2007), reh'g pending (approving PJM's cost allocation
proposal for existing transmission facilities, and requiring
revisions to its proposal for new transmission facilities); Midwest
Independent Transmission System Operator, Inc., 118 FERC ] 61,209
(2007), reh'g pending (conditionally approving cost allocation for
economic upgrades). In 2006, the Commission approved the Midwest
ISO's proposed cost allocation for reliability upgrades. Midwest
Independent Transmission System Operator, Inc., 114 FERC ] 61,106,
order on technical conference, 117 FERC ] 61,241 (2006), order on
reh'g, 118 FERC ] 61,208 (2007), reh'g pending.
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27. The Commission also has undertaken numerous actions in support
of competitive wholesale power opportunities. For example, the
Commission established interconnection rules for large, small and wind
generators. In addition, the Commission has not only granted initial
approval to the organized markets of the RTO and ISO regions but has
continued to work with each region to improve the design of its markets
as the region and the Commission have gained experience with the
different regional approaches. Further, we have approved various market
power mitigation rules and provided for market monitoring in the
organized markets of RTOs and ISOs. Also, in response to EPAct 2005,
the Commission prepared a report that assesses electric demand response
resources by region.\30\ The Commission has also opened a proceeding on
demand response in wholesale markets, and we held a technical
conference on April 23, 2007, to examine demand resources in markets,
grid operations and expansion, and best practices for the measurement
and evaluation of demand response resources.\31\ These Commission
actions, along with other prior actions of the Commission, are intended
to work together to improve the operation of competitive wholesale
markets across the nation, in regions with and without organized
markets. The proposals in this ANOPR complement these actions and are
part of our ongoing effort to maintain and encourage competitive
wholesale electric energy markets.
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\30\ Federal Energy Regulatory Commission, Assessment of Demand
Response and Advanced Metering: Staff Report, Docket No. AD06-2-000
(August 8, 2006) (FERC Staff Demand Response Assessment).
\31\ See Supplemental Notice, Demand Response in Wholesale
Markets, Docket No. AD07-11-000 (April 6, 2007).
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28. With the passage of EPAct 2005, Congress granted the Commission
additional authorities to support wholesale competition. Key provisions
in EPAct 2005 include authority to impose civil penalties for market
manipulation, to prevent exercise of market power through expanded
power to review mergers and generation facility transfers, and to
require market transparency. EPAct 2005 also included a number of
provisions designed to strengthen the interstate power grid, both to
assure reliability and support competitive markets, encouraging the
Commission to increase transmission investment through incentives,
providing for backstop federal siting of transmission facilities,
encouraging the deployment of advanced technologies, and authorizing
the Commission to approve and enforce mandatory reliability standards.
The Commission has taken these and other new responsibilities seriously
and has complied with all Congressional directives and deadlines.
29. In addition, the Commission has recognized that there are
issues that need to be addressed where the Commission and state
commissions share an interest, such as demand response and competitive
procurement. The Commission is engaged with the National Association of
Regulatory Utility Commissioners (NARUC) in two collaborative efforts,
the NARUC-FERC Collaborative Dialogue on Demand Response and the NARUC-
FERC Competitive Procurement Collaborative.
C. Issues Addressed in the ANOPR
30. Competition remains national policy with respect to wholesale
power markets. Competition continues to be sound policy in wholesale
markets, when combined with effective regulation. The Commission has a
duty to improve the operation of wholesale power markets to support
competition. One way to accomplish that is by pursuing regulatory
reform. To that end, the Commission initiated this proceeding, designed
to identify the challenges facing competitive wholesale power markets,
identify workable solutions to those challenges that will complement
other Commission actions to improve the operation of competitive
wholesale markets, and determine which solutions are within the
Commission's authority. This proceeding also responds to concerns
raised by market participants regarding needed improvements to the
operation of competitive wholesale markets.
31. In order to gather more information and allow public comment,
the Commission held a conference on competition issues on February 27,
2007. At this first competition conference, most speakers addressed
issues affecting the RTO and ISO regions, including the level of
wholesale prices, the need for long-term power contracts, the
effectiveness of market monitoring, and the lack of adequate demand
response. The Commission held a second competition conference on May 8,
2007, to examine in more detail several specific concerns and
challenges identified in the first conference. This second conference
focused on regions with RTOs and ISOs and organized markets and dealt
with: (1) Demand response and market prices during a power shortage;
(2) fostering long-term power contracting; and (3) the responsiveness
of RTOs and ISOs to customers and other stakeholders. The panel on
demand response emphasized allowing customers to respond to high
prices, particularly when generating capacity falls short of demand,
providing adequate compensation for demand reductions, and allowing
many small retail demand reductions to be aggregated for use in the
wholesale power market. The panel on long-term power contracting
discussed the role and availability of long-term contracts, as well as
the importance of long-term transmission service and a robust
transmission system. The RTO and ISO accountability panel discussed the
need for RTOs and ISOs to be more responsive to their stakeholders; it
considered several means of achieving this such as allowing a few
stakeholder representatives to serve on hybrid boards of RTOs or ISOs.
On April 5, 2007, the Commission also held a technical conference on
market monitoring policies and heard from interested commenters on
issues such as the development of the concept and
[[Page 36281]]
functions of market monitoring and the MMUs' role with respect to the
Commission, ISOs and RTOs, and various stakeholders.
32. Based on comments received at these three conferences, the
Commission decided to consider in this ANOPR four issues in organized
market regions that are not already being fully addressed by the
Commission in other proceedings. These areas are: (1) The role of
demand response in organized markets and greater use of market prices
to elicit demand reductions during a power shortage; (2) increasing
opportunities for long-term power contracting; (3) strengthening market
monitoring; and (4) enhancing the responsiveness of RTOs and ISOs to
customers and other stakeholders.
33. At this time, the Commission is not addressing in this ANOPR
potential reforms outside the organized market regions. As discussed in
our first technical conference, the primary concerns of wholesale
customers and competitors in other regions are nondiscriminatory access
to transmission and nondiscriminatory rules for power procurement.
These two areas, although critically important, are being addressed by
the Commission in other proceedings. In Order No. 890, the Commission
reformed the OATT to ensure that it continues to provide
nondiscriminatory access to transmission service. Much work remains to
be done, however, and the Commission is focusing on the compliance
phase of OATT reform to ensure that it is implemented properly,
particularly in the area of regional transmission planning and the
calculation of available transfer capability. With regard to power
procurement, the Commission believes that competitive procurement can
enhance the ability of LSEs to acquire reliable wholesale power
supplies at reasonable prices. The Commission recognizes, however, that
wholesale power procurement raises issues that are important to both
the Commission and state commissions. The Commission is therefore
pursuing a cooperative dialogue with NARUC to develop guidelines for
best practices for power procurement. Since these two main areas of
concern are being pursued in other proceedings, the Commission will not
address reforms outside the RTO/ISO regions in this proceeding.
Similarly, issues related to demand response are important to both this
Commission and state commissions. Concerns with participation of demand
response in organized and bilateral markets were voiced in our
technical conferences. The Commission is pursuing a collaborative
dialogue with state commissions on best practices and coordination on
demand response issues, and lessons learned there may be applicable to
bilateral markets.
III. Demand Response and Pricing During Power Shortages in Organized
Markets
34. A well-functioning competitive wholesale electric market should
reflect current supply and demand conditions. The Commission has
expressed the view on numerous occasions that the wholesale electric
power market works best when demand can respond to the wholesale
price.\32\ The Commission's policy is to facilitate the participation
of demand response in the organized power markets, in part because
demand response helps to hold down wholesale power prices, increases
awareness of energy usage, provides for more efficient operation of
markets, mitigates market power, and enhances reliability. This policy
reflects the Commission's view that the value of electric power to
customers is not always the same. It changes over time and varies from
place to place. The value can be very different for two customers at
the same time and place, one of whom may prefer to reduce consumption
if the price is high and another who may be willing to pay a high price
to avoid curtailment in an emergency.
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\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).
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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.
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\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), https://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.
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\34\ Vernon Smith and Lynne Kiesling, Market-Based Model for
ISO-Sponsored Demand Response Programs, (September 2005), https://
www.defgllc.com/Downloads/051018_DEFG_DRwp02.pdf .
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37. First, demand response can help reduce wholesale prices and
wholesale price volatility. The reduction is valued especially during
peak periods, but demand response can also lower price and volatility
during off-peak periods. Demand response can lower wholesale prices
directly and indirectly. The direct effect occurs when a demand
reduction is bid directly into the wholesale market: lower demand means
a lower wholesale price. Demand response at retail, if not bid directly
into the wholesale market by a large retail customer, affects the
wholesale market indirectly because it reduces the need for power by
the retail customers' LSE and in turn reduces that LSE's need to
purchase power from the wholesale market. For example, where an LSE
offers retail customers some form of
[[Page 36282]]
time-of-use rates, the retail customers' response to rates during a
higher-priced period reduces the LSE's wholesale demand and helps lower
wholesale prices. This lower wholesale price may result in lower retail
prices.
38. Second, demand response tends to flatten an area's load
profile. With a flatter load profile, the distribution of generation
types tends to shift toward lower-cost base load generation and away
from higher-cost peaking generation, and this tends to lower the
overall average cost to produce energy.
39. Third, demand response can help reduce the potential for market
manipulation by reducing generator market power. As more demand
response is available during peak periods, power suppliers need to
account more for the price responsiveness of load when they consider
higher-price bids. The more demand response is able to reduce the peak
price, the more downward pressure it places on generator bidding
strategies by increasing the risk to a supplier that it will not be
dispatched if it bids too high.
40. RTOs such as PJM, NYISO, and ISO-NE have quantified the cost-
effectiveness of demand response in their wholesale markets. They
assessed both the reduction in market prices due to demand reductions
and the value of demand response to system reliability. These
assessments conclude that the demand response programs they operate
produce net benefits associated with lower wholesale prices. For
example, ISO-NE found that the benefits of its various economic and
emergency demand response programs in 2005 more than compensate for its
costs, largely payments to demand response participants and its own
extra operating costs.\35\ PJM and NYISO found similar positive results
in evaluations of their programs.\36\
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\35\ ISO-NE, An Evaluation of the Performance of the Demand
Response Programs Implemented by ISO-NE in 2005, Docket No. ER02-
2330-040 (Dec. 30, 2005).
\36\ NYISO, NYISO 2006 Demand Response Programs, Docket No.
ER01-3001-016 (Feb. 16, 2007); PJM, Assessment of PJM Load Response
Programs, Docket No. ER02-1326-006 (Aug. 29, 2006).
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B. Prior Commission Actions To Address Demand Response
41. The Commission has issued numerous orders over the last several
years on various aspects of electric demand response in organized
markets. A goal of most of these orders was to remove unnecessary
obstacles to demand response participating in the wholesale power
markets of RTOs and ISOs.\37\
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\37\ See, e.g., New York Independent System Operator, Inc., 92
FERC ] 61,073, order on clarification, 92 FERC ] 61,181 (2000),
order on reh'g, 97 FERC ] 61,154 (2001); New England Power Pool and
ISO New England, Inc., 100 FERC ] 61,287, order on reh'g, 101 FERC ]
61,344 (2002), order on reh'g, 103 FERC ] 61,304, order on reh'g,
105 FERC ] 61,211 (2003); PJM Interconnection, L.L.C., 95 FERC ]
61,306 (2001); PJM Interconnection, L.L.C., 99 FERC ] 61,139 (2002);
PJM Interconnection, L.L.C., 99 FERC ] 61,227 (2002).
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42. These orders approved various types of demand response
programs, including programs to allow demand response to be used as a
capacity resource and as a resource during system emergencies,\38\
programs to allow wholesale buyers and qualifying large retail buyers
to bid a demand reduction directly into the day-ahead and real-time
energy markets and certain ancillary service markets, particularly as a
provider of operating reserves, as well as programs to accept bids from
aggregators of retail customers (ARCs).\39\ The Commission also has
approved special demand response applications such as use of demand
response for synchronized reserves and regulation service.\40\ The
theme underlying the Commission's approval of these programs has been
to allow demand resources to participate in these markets on a basis
that is comparable to other resources.
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\38\ See, e.g., PJM Interconnection, L.L.C., 117 FERC ] 61,331
(2006); Devon Power L.L.C., 115 FERC ] 61,340 (2006). These orders
allow demand resources to provide capacity resources.
\39\ We will use the phrase ``aggregation of retail customers''
to refer to RTOs and ISOs accepting bids from parties that aggregate
demand response bids (which are mostly from retail loads), or ARCs.
See, e.g., New York Independent System Operator, Inc., 95 FERC ]
61,223 (2001); New England Power Pool and ISO New England, Inc., 100
FERC ] 61,287, order on reh'g, 101 FERC ] 61,344 (2002), order on
reh'g, 103 FERC ] 61,304, order on reh'g, 105 FERC ] 61,211 (2003);
PJM Interconnection, L.L.C., 99 FERC ] 61,227 (2002).
\40\ See, e.g., PJM Interconnection, L.L.C., 114 FERC ] 61,201
(2006).
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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.
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\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).
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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\
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\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.
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45. The Commission has also encouraged demand response outside of
its orders. The Commission has conducted several technical conferences
on demand response over the last several years, most recently on April
23, 2007.\46\ The NARUC-FERC
[[Page 36283]]
Collaborative Dialogue on Demand Response began in November 2006 to
explore state/federal coordination of efforts to promote and integrate
demand response into retail and wholesale markets and planning. Also,
as mentioned, in August 2006 the Commission published the staff report
on demand response and advanced metering as directed by EPAct 2005
section 1252(e)(3).\47\
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\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.
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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).
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\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.
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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.
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\50\ ISO-NE places a minimum size of 5 MW for participation. See
ISO-NE, ISO New England Manual for Market Rule 1 Accounting (May 31,
2007), at section 12.3.5.3, https://www.iso-ne.com/rules_proceds/
isone_mnls/m_28_market_rule_1_accounting--(revision--27)--05--
31--07.doc.
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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\
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\51\ See FERC Staff Demand Response Assessment at 123.
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52. Demand response providers need market rules that all
