[Federal Register Volume 73, Number 46 (Friday, March 7, 2008)]
[Proposed Rules]
[Pages 12576-12619]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: E8-3984]
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Part IV
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 Rules
Federal Register / Vol. 73, No. 46 / Friday, March 7, 2008 / Proposed
Rules
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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
Issued February 22, 2008.
AGENCY: Federal Energy Regulatory Commission, DOE.
ACTION: Notice of proposed rulemaking.
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SUMMARY: The Federal Energy Regulatory Commission (Commission) is
proposing to amend its regulations under the Federal Power Act to
improve the operation of organized wholesale electric markets in the
areas of: Demand response and market pricing during a period of
operating reserve shortage; long-term power contracting; market-
monitoring policies; and the responsiveness of regional transmission
organizations (RTOs) and independent system operators (ISOs) to
stakeholders and customers, and ultimately to the consumers who benefit
from and pay for electricity services. The Commission proposes to
require that each RTO and ISO make certain filings that propose
amendments to its tariff, in order to comply with the proposed
requirements in each area, or that demonstrate that its existing tariff
and market design already satisfy the requirements. The Commission
invites all interested persons to submit comments in response to the
regulations proposed herein.
DATES: Comments are due April 21, 2008.
ADDRESSES: You may submit comments, identified by docket number by any
of the following methods.
Agency Web site: http://ferc.gov. Documents created
electronically using word processing software should be filed in native
applications or print-to-PDF format and not in a scanned format.
Mail/Hand Delivery: Commenters unable to file comments
electronically must mail or hand deliver an original and 14 copies of
their comments to: Federal Energy Regulatory Commission, Secretary of
the Commission, 888 First Street, NE., Washington, DC 20426.
Instructions: For detailed instructions on submitting comments and
additional information on the rulemaking process, see the Comment
Procedures Section of this document.
FOR FURTHER INFORMATION CONTACT: David Kathan (Technical Information),
Office of Energy Market Regulation, Federal Energy Regulatory
Commission, 888 First Street, NE., Washington, DC 20426,
[email protected], (202) 502-6404.
Tina Ham (Legal Information), Office of the General Counsel,
Federal Energy Regulatory Commission, 888 First Street, NE.,
Washington, DC 20426,[email protected], (202) 502-6224.
SUPPLEMENTARY INFORMATION:
Table of Contents
Paragraph
numbers
I. Introduction............................................. 1
II. Background.............................................. 12
III. Proposals To Expand the Scope of the Proceeding........ 16
IV. Discussion.............................................. 26
A. Demand Response and Pricing During Periods of 26
Operating Reserve Shortages in Organized Markets.......
1. Background....................................... 27
a. Importance of Demand Response to Competition 28
in RTO/ISO Areas...............................
b. Prior Commission Actions To Address Demand 32
Response.......................................
2. The Need for Commission Action................... 37
3. Proposed Reforms................................. 46
a. Ancillary Services Provided by Demand 47
Response Resources.............................
i. Preliminary Proposals in the ANOPR....... 47
ii. Comments on the ANOPR Proposals and 50
Questions..................................
iii. Commission Proposal.................... 56
b. Deviation Charge............................. 65
i. Preliminary Proposals in the ANOPR....... 65
ii. Comments on the ANOPR Proposals and 67
Questions..................................
iii. Commission Proposal.................... 72
c. Aggregation of Retail Customers.............. 80
i. Preliminary Proposals in the ANOPR....... 80
ii. Comments on the ANOPR Proposals and 82
Questions..................................
iii. Commission Proposal.................... 86
d. Potential Future Demand Response Reforms..... 94
e. Market Rules Governing Price Formation During 97
Periods of Operating Reserve Shortage..........
i. Preliminary Proposals in the ANOPR....... 97
ii. Comments on the ANOPR Proposals and 99
Questions..................................
iii. Commission Proposal.................... 107
B. Long-Term Power Contracting in Organized Markets..... 129
1. Background....................................... 130
2. The Need for Commission Action................... 134
3. Preliminary Proposals in the ANOPR............... 138
4. Comments on the ANOPR Proposals and Questions.... 142
5. Proposed Reforms................................. 155
C. Market-Monitoring Policies........................... 162
1. Background....................................... 163
2. Prior Commission Actions Regarding Market 165
Monitoring.........................................
3. The Need for Commission Action................... 169
4. Proposed Reforms................................. 171
a. Independence and Function.................... 172
i. Structure and Tools...................... 173
ii. Oversight............................... 183
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iii. Functions.............................. 191
iv. Mitigation and Operations............... 200
v. Ethics................................... 211
vi. Tariff Provisions....................... 215
b. Information Sharing.......................... 219
i. Enhanced Information Dissemination....... 220
ii. Tailored Requests for Information....... 231
iii. Commission Referrals................... 238
c. Pro Forma Tariff............................. 241
i. Preliminary Proposals in the ANOPR....... 241
ii. Comments on the ANOPR Proposals and 242
Questions..................................
iii. Commission Proposal.................... 243
D. Responsiveness of RTOs and ISOs to Stakeholders and 245
Customers..............................................
1. Background....................................... 247
2. Preliminary Proposals in the ANOPR............... 249
3. Comments on the ANOPR Proposals and Questions.... 254
a. Comments on the Hybrid Board Approach........ 255
b. Comments on the Board Advisory Committee 264
Approach.......................................
c. Comments on the Need To Increase Management 268
Responsiveness.................................
d. Comments on Regional Differences............. 270
4. The Need for Commission Action................... 272
5. Proposed Reform.................................. 275
V. Applicability of the Proposed Rule and Compliance 282
Procedures.................................................
VI. Information Collection Statement........................ 286
VII. Environmental Analysis................................. 290
VIII. Regulatory Flexibility Act Certification.............. 291
IX. Comment Procedures...................................... 292
X. Document Availability.................................... 296
APPENDIX A: Commenter Acronyms
I. Introduction
1. The Federal Energy Regulatory Commission (Commission) is
proposing reforms to improve the operation of organized wholesale
electric power markets.\1\ Ensuring the competitiveness of organized
wholesale markets is integral to the Commission fulfilling its
statutory mandate to ensure adequate and reliable non-discriminatory
service at just and reasonable rates. Effective competition protects
consumers by providing greater supply options, encouraging new entry
and innovation, and encouraging demand response and energy efficiency.
In the past several years, the Commission has received both formal and
informal comments from market participants, consumer and industry
organizations, state regulators, and others recommending improvements
to competitive wholesale markets.
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\1\ Organized market regions are areas of the country in which a
regional transmission organization (RTO) or independent system
operator (ISO) operates day-ahead and/or real-time energy markets.
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2. In response to these comments, the Commission held three public
conferences in 2007 in order to gather more information on competition
at the wholesale level and other related issues. At the first
conference on competition issues, held on February 27, 2007, most
speakers addressed issues affecting the RTO and ISO regions, including
the levels of wholesale prices, the need for long-term power contracts,
the effectiveness of market monitoring, and the lack of adequate demand
response.\2\ On April 5, 2007, the Commission also held a technical
conference on market monitoring policies and heard from interested
commenters on issues such as the development of the concept and
functions of market monitoring and the market monitoring units' (MMU)
role with respect to the Commission, ISOs and RTOs, and various
stakeholders.\3\ The Commission then 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 organized markets administered by
RTOs and ISOs and dealt with: (1) Demand response, including the role
of demand response during a period of operating reserve shortage; (2)
fostering long-term power contracting; and (3) the responsiveness of
RTOs and ISOs to customers and other stakeholders.\4\
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\2\ See Second Supplemental Notice of Conference, Conference on
Competition in Wholesale Power Markets, Docket No. AD07-7-000 (Feb.
26, 2007).
\3\ See Notice of Agenda for the Conference, Review of Market
Monitoring Policies, Docket No. AD07-8-000 (Mar. 30, 2007).
\4\ See Supplemental Notice of Conference, Conference on
Competition in Wholesale Power Markets, Docket No. AD07-7-000 (Apr.
19, 2007).
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3. Based on the record compiled at these three conferences, the
Commission issued an Advance Notice of Proposed Rulemaking (ANOPR) \5\
on June 22, 2007 to identify and implement improvements to specific
aspects of organized wholesale markets. In the ANOPR, the Commission
identified four issues in organized market regions that were not being
adequately addressed or under consideration in other proceedings. These
areas were: (1) The role of demand response in organized markets and
greater use of market prices to elicit demand response during a period
of operating reserve 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, and ultimately to the consumers who benefit from and pay
for electricity services.
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\5\ Wholesale Competition in Regions with Organized Electric
Markets, Advance Notice of Proposed Rulemaking, 72 FR 36,276 (July
2, 2007), FERC Stats. & Regs. ] 32,617 (2007).
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4. The Commission received several thousand pages of comments from
over a hundred commenters in response to the ANOPR (a list of
commenters and their abbreviated names the Commission will use for them
in this document appears in Appendix A).\6\ After review of the
comments, and pursuant to our responsibility under
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sections 205 and 206 of the Federal Power Act (FPA) \7\ to ensure that
rates, charges, classifications, and service of public utilities (and
any rule, regulation, practice, or contract affecting any of these) are
just and reasonable and not unduly discriminatory, the Commission is
making several proposals in this NOPR designed to ensure just and
reasonable rates and to remedy undue discrimination and preference and
to improve wholesale competition in regions with organized markets.
These proposals reflect the record compiled by the Commission in its
conferences and in comments to the ANOPR. These proposals, along with
background information and a summary of comments received, will be
described in detail in the sections below.
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\6\ We do not summarize in this NOPR every comment received in
response to the ANOPR. The Commission has reviewed and considered
each comment submitted, however, and appreciates the careful
consideration the commenters have given to this proceeding.
\7\ 16 U.S.C. 824d-824e (2000).
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5. In proposing the reforms in the four areas described below, the
Commission recognizes that there are differences of opinion on the
appropriate scope of this rulemaking, as well as on the four specific
issues described in the ANOPR. We are therefore guided by the record in
this proceeding and the need to undertake timely and concrete reforms
where the record supports them. From the commencement of our first
technical conference in this proceeding, our goal has been to identify
any specific reforms that can be made to optimize the efficiency of
organized markets for the benefit of customers, and ultimately the
consumers who benefit from and pay for electricity services. As we
explain further below, however, this proceeding does not represent the
final effort to improve the efficiency of competitive markets. Rather,
we will continue to evaluate other specific reforms that may be
necessary.
6. In the area of demand response and the use of market prices to
elicit demand response, the Commission proposes several requirements
for ISOs and RTOs. These proposals include requirements to: (1) Accept
bids from demand response resources in their markets for certain
ancillary services, comparable to any other resources; (2) 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; (3) permit an aggregator of retail customers
(ARC) to bid demand response on behalf of retail customers directly
into the organized energy market; (4) modify their market rules, as
necessary, to allow the market-clearing price, during periods of
operating reserve shortage, to reach a level that rebalances supply and
demand so as to maintain reliability while providing sufficient
provisions for mitigating market power; and (5) study whether further
reforms are necessary to eliminate barriers to demand response in
organized markets.
7. In the section on long-term power contracting, the Commission
proposes that ISOs and RTOs be required to dedicate a portion of their
Web sites for market participants to post offers to buy or sell power
on a long-term basis. This proposal is designed to promote greater use
of long-term contracts through improving transparency among market
participants.
8. In the area of improving market monitoring, the Commission
proposes that each RTO and ISO provide its MMU with access to market
data, resources and personnel sufficient to carry out its duties, and
that the MMU (or the external MMU in a hybrid structure) report
directly to the RTO or ISO board. In addition, the Commission proposes
to require that the MMU's functions include: (1) Identifying
ineffective market rules and recommending proposed rules and tariff
changes; (2) reviewing and reporting on the performance of the
wholesale markets to the RTO or ISO, the Commission, and other
interested entities; and (3) notifying appropriate Commission staff of
instances in which a market participant's behavior requires
investigation. The Commission also proposes expanding the list of
recipients to receive MMU recommendations regarding rule and tariff
changes, and broadening the scope of behavior to be reported to the
Commission. The Commission further proposes to remove the MMU from
tariff administration, require each RTO and ISO to include ethics
standards for MMU employees in its tariff, and consolidate all its MMU
provisions in one section of its tariff. The Commission also proposes
expanding the dissemination of MMU market information to a broader
constituency, with reports made on a more frequent basis, and reducing
the time period before energy market bid and offer data are released to
the public.
9. Finally, the Commission proposes to establish new criteria
intended to ensure that an RTO or ISO is responsive to its customers
and stakeholders, and ultimately to the consumers who benefit from and
pay for electricity services. These principles will include: (1)
Inclusiveness; (2) fairness in balancing diverse interests; (3)
representation of minority positions; and (4) ongoing responsiveness.
10. In each of these four areas, the Commission will require RTOs
and ISOs to consult with their stakeholders and make a compliance
filing that details why the entity's existing practices comply with the
final rule in this proceeding, or the entity's plans to attain
compliance.
11. Finally, as indicated above, these reforms do not represent our
final effort to improve the functioning of competitive organized
markets for the benefit of consumers. For example, although we are
proposing specific reforms to eliminate barriers to demand response, we
propose to require each RTO or ISO to study whether further reforms are
necessary to eliminate barriers to demand response in organized
markets. Any reforms must ensure that demand response resources are
treated on a comparable basis as other resources. We also are ordering
a staff technical conference on proposals by American Forest and
Portland Cement Association, et al. to modify the design of organized
markets. Finally, we direct, as explained further below, each RTO or
ISO to provide a forum for affected consumers to voice specific
concerns (and to propose regional solutions) on how to improve the
efficient operation of competitive markets. The Commission therefore
will continue to evaluate reforms in this area, but will not allow the
prospect of other reforms to delay the benefits to consumers from those
proposed herein.
II. Background
12. As the Commission noted in the ANOPR, national policy has been,
and continues to be, to foster competition in wholesale electric power
markets.\8\ This policy was embraced in the recent Energy Policy Act of
2005 (EPAct 2005),\9\ and is reflected in Commission policy and
practice. The Commission, in fulfilling its responsibility to ``guard
the consumer from exploitation by non-competitive electric power
companies,'' \10\ relies on both its own regulations and competition to
ensure consumer protection. In doing so, the Commission is aware of the
need to vary the mix of regulation and competition based on the
circumstances of the time, taking into account advances of technology,
changes in economies of scale, and new state and federal laws that
affect the energy industry.
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\8\ ANOPR, FERC Stats. & Regs. ] 32,617 at P 4.
\9\ Pub. L. No. 109-58, 119 Stat. 594 (2005).
\10\ Nat'l Ass'n for the Advancement of Colored People v. FPC,
520 F.2d 432, 438 (DC Cir. 1975), aff'd, 425 U.S. 662 (1976).
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13. The Commission has acted over the last few decades to implement
Congressional policy to expand the wholesale electric power markets to
facilitate entry of new generators and to support competitive markets.
Absent a
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single national power market, the development of regional markets is
the best method of facilitating competition within the power industry,
and the Commission has made sustained efforts to recognize and foster
such markets. The Commission acknowledges that significant differences
exist between regions, including differences in industry structure, mix
of ownership, sources for electric generation, population densities,
and weather patterns. Some regions have organized spot markets
administered by an RTO or ISO, and others rely solely on bilateral
contracting between wholesale sellers and buyers. The Commission
recognizes and respects these differences across various regions. At
the same time, wholesale competition can serve customers well in all
regions. The focus of this proceeding is on further improving the
operation of wholesale competitive markets in organized market
regions.\11\
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\11\ The following RTOs and ISOs have organized markets: PJM
Interconnection, LLC (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), and Southwest Power
Pool, Inc. (SPP).
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14. Some perceived challenges in the organized wholesale markets
may be closely related to state retail issues, and the distinction
between wholesale and retail competition challenges is often blurred.
For example, wholesale customers typically have more advanced meters
than retail customers; organized market rates vary with time of day
whereas retail rates typically do not; and retail choice programs,
which tend to be in areas served by organized wholesale markets, may
rely on RTOs or ISOs 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. Although the
Commission acknowledges that issues with retail markets are often
intertwined with wholesale market issues, the Commission will not
address retail market issues in this proceeding. This rulemaking is
designed to focus on wholesale markets; issues related to retail
markets will vary by state and are more appropriately considered in
separate proceedings before the affected state(s) or the Commission
where the specific interaction between the retail and wholesale market
can be explored.
15. Comments received on the ANOPR and made during technical
conferences highlight several potential problems with wholesale
competition both inside and outside the organized market regions that
are within the scope of this proceeding. In the ANOPR, the Commission
noted that it was not addressing potential reforms outside the
organized market regions, explaining that many of the important
concerns discussed during the first technical conference (e.g.,
nondiscriminatory access to transmission, nondiscriminatory rules for
power procurement) were already being addressed in other proceedings.
Similarly, the Commission has chosen to limit this proceeding to four
discrete areas involving wholesale competition within organized
markets. As explained further below, however, these are not the final
reforms the Commission may pursue with respect to organized markets;
rather, we will continue to evaluate specific proposals that may serve
to strengthen organized markets.
III. Proposals To Expand the Scope of the Proceeding
16. Several parties propose to expand the scope of this proceeding
beyond the four areas covered in the ANOPR. We received a request from
APPA, in its comments on the ANOPR, and a request from AARP, et al., a
group consisting of 41 entities, for a large-scale investigation of the
workings of organized markets with respect to their ability to produce
just and reasonable rates. APPA and AARP, et al. state that the current
market system allows incumbent sellers (those power suppliers with
older power plants) to make excess profits while disadvantaging certain
power suppliers with new generation. APPA and AARP, et al. argue that
this has resulted in increased cost to consumers without the
corresponding benefit of new generation being built. APPA and AARP, et
al. claim that the Commission has a responsibility under sections 205
and 206 of the FPA to investigate the workings of organized markets
based on their allegations of unjust and unreasonable rates.
17. The Commission acknowledges the concerns of APPA and AARP, et
al.; however, we decline to initiate the broad investigation APPA and
AARP, et al. have requested as part of this proceeding. As noted above,
by listening to the concerns of market participants, and evaluating the
record of this proceeding, we have identified four specific areas in
which reforms can improve wholesale electricity market operations.
Through the competition conferences and the ANOPR process, we have
developed a solid record in favor of making those reforms, and a strong
sense of what the Commission can do to be helpful in these four areas.
It is important that the Commission move forward with regard to the
specific reforms under consideration in this proposed rulemaking to
foster improvements in the near term to the competitive operation of
existing organized markets administered by RTOs and ISOs. Further, we
also note that the approach we are taking in this NOPR is consistent
with the ISO/RTO Council's proposal.\12\
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\12\ ISO/RTO Council urges the Commission to focus on
determining the appropriate means of addressing issues that are ripe
for this NOPR and which ones might be better considered in existing
forums. It states that existing stakeholder processes provide an
appropriate forum for targeted consideration of various issues,
including the ones raised by APPA and AARP, et al. ISO/RTO Council
at 1, 3.
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18. In contrast to the specific reforms proposed herein, APPA and
AARP, et al. request a broad, generic inquiry into alleged (but not
specified) market design flaws. Their request not only fails to offer
any specific solutions, but also fails to appreciate the differences in
market design that exist in each region. Over the past five years, the
Commission has undertaken significant market design reforms in most
regions. We have not adopted a standard market design, but rather have
undertaken different reforms, at different times in each region to
reflect the differing characteristics of each market. The Commission
has devoted considerable resources over the years to improving the
market designs in each organized market to ensure that they produce
just and reasonable rates. We summarize some of these efforts below.
19. For example, in response to the California energy crisis of
2000-2001, the Commission worked with CAISO and its stakeholders to
develop a Market Redesign and Technology Upgrade program designed to
improve the efficiency and proper working of the market through
improved modeling and new forward markets,\13\ which the Commission
subsequently approved in part. In 2004, the Commission approved the
Midwest ISO's open access transmission and energy markets tariff, which
provides for terms and conditions necessary to implement a market-based
congestion management program and energy spot markets.\14\ This
includes a day-ahead energy market and a real-time energy market,
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locational marginal pricing, and a market for financial transmission
rights.
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\13\ Cal. Indep. Sys. Operator Corp., 116 FERC ] 61,274 (2006),
order on reh'g, 119 FERC ] 61,076 (2007).
\14\ Midwest Indep. Transmission Sys. Operator, Inc., 108 FERC ]
61,163, order on reh'g, 109 FERC ] 61,157 (2004), order on reh'g 111
FERC ] 61,043, reh'g denied, 112 FERC ] 61,086 (2005), aff'd sub
nom. Wisconsin Public Power, Inc. v. FERC, 493 F.3d 239 (DC Cir.
2007).
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20. The Commission has also acted on proposals developed by
regional entities to ensure that adequate price signals exist in the
market for both short-term and long-term electric power transactions,
by addressing pricing issues during reserve shortages and by approving
forward capacity markets. The Commission has approved a demand curve
for capacity markets in the region operated by NYISO. The Commission
approved PJM's Reliability Pricing Model to provide an auction process
for forward capacity contracting. The Commission also approved a
settlement agreement for ISO-NE to create a transitional forward
capacity market to meet the needs of its stakeholders.\15\ These
actions were designed to minimize the disruption during periods of
operating reserve shortage and encourage new investment in generation,
while accepting variation between regions and allowing for regional
choice.
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\15\ Devon Power, LLC, 115 FERC ] 61,340, order on reh'g, 117
FERC ] 61,133 (2006), appeal pending sub nom. Maine Pub. Utils.
Comm'n v. FERC, No. 06-1403 (DC Cir. 2007).
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21. The Commission has also issued region-specific orders providing
for cost allocation for new transmission investment, removing
uncertainty over the cost responsibility for the development of new
transmission. In Opinion No. 494,\16\ the Commission approved PJM's
policy for determining recovery of transmission costs for existing and
new facilities, providing for region-wide cost sharing for certain new
extra high-voltage transmission facilities. The Commission also
approved the Midwest ISO's transitional pricing scheme, which
incorporates cost sharing for new transmission facilities.\17\
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\16\ PJM Interconnection, LLC, 119 FERC ] 61,063 (2007) (Opinion
No. 494), reh'g pending.
\17\ Midwest Indep. Transmission Sys. Operator, Inc., 114 FERC ]
61,106, order on reh'g and technical conference, 117 FERC ] 61,241
(2006), order on reh'g, 118 FERC ] 61,208 (2007), appeal pending sub
nom. Public Service Comm'n of Wisconsin v. FERC, No. 06-1408 (D.C.
Cir., filed Dec. 13, 2006); Midwest Indep. Transmission Sys.
Operator, Inc., 118 FERC ] 61,209, order on reh'g, 120 FERC ] 61,080
(2007).
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22. In addition to these region-specific actions, the Commission
has addressed incentives for the building of new generation and
transmission in all regions with organized markets. In Order No.
679,\18\ the Commission allowed parties building transmission to apply
for recovery of prudently incurred costs for construction work in
progress, pre-operations, and abandoned facilities, and it provided for
application for an incentive rate of return on equity for new
transmission investment. As a further means of reducing uncertainty and
spurring investment, the Commission finalized rules for interconnection
for large, small and wind generators. These rules remove barriers to
interconnection by streamlining the process of, and improving
incentives for, building new generation. The Commission has also acted
to improve certainty in the cost of transmission for electric customers
by creating rules for long-term transmission rights in Order Nos. 681
and 681-A.\19\
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\18\ Promoting Transmission Investment through Pricing Reform,
Order No. 679, FERC Stats. & Regs. ] 31,222, order on reh'g, Order
No. 679-A, FERC Stats. & Regs. ] 31,236 (2006), order on reh'g, 119
FERC ] 61,062 (2007).
\19\ Long-Term Firm Transmission Rights in Organized Electricity
Markets, Order No. 681, FERC Stats. & Regs. ] 31,226, order on
reh'g, Order No. 681-A, 117 FERC ] 61,201 (2006).
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23. In Order No. 890, the Commission reformed the open access
transmission tariff (OATT) to ensure that it continues to provide
nondiscriminatory access to transmission service. Among other things,
Order No. 890 requires an open and transparent regional transmission
planning process.\20\ The Commission is now focusing on the compliance
phase of OATT reform to ensure that it is implemented properly.\21\ The
Commission also has been pursuing a cooperative dialogue with the
National Association of Regulatory Utility Commissioners (NARUC) to
identify and analyze models for competitive power procurement. This
effort is designed to enhance the ability of load-serving entities
(LSEs) to acquire reliable power supplies at competitive prices. As
noted in the ANOPR, the Commission has also acted to investigate demand
response in organized markets, through a Commission report and a recent
technical conference. This conference was designed to examine demand
response resources in markets, grid operations and expansion, and best
practices for the measurement and evaluation of demand response
resources.\22\ The Commission also held a technical conference on
December 11, 2007 to explore issues surrounding the management of
interconnection queues.\23\
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\20\ This addresses, in part, concerns raised by some commenters
regarding posting of future transmission constraints and congestion
costs.
\21\ ANOPR, FERC Stats. & Regs. ] 32,617 at P 33 (citing
Preventing Undue Discrimination and Preference in Transmission
Service, Order No. 890, 72 FR 12,266 (Mar. 15, 2007), FERC Stats. &
Regs. ] 31,241, order on reh'g, Order No. 890-A, FERC Stats. & Regs.
] 31,261 (2007)).
\22\ Supplemental Notice, Demand Response in Wholesale Markets,
Docket No. AD07-11-000 (April 6, 2007).
\23\ Notice of Technical Conference, Interconnection Queuing
Practices, Docket No. AD08-2-000 (November 2, 2007).
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24. In recognition of our continuing respect for regional
differences in market design, we believe that, if there are specific
concerns about the market designs in a particular region, they should
be considered, in the first instance, at the regional level. We
therefore direct each RTO or ISO to provide a forum for affected
consumers to voice specific concerns (and to propose regional
solutions) to the issues raised generically by APPA and AARP, et al.
Although most existing stakeholder processes already allow for the
submission of such proposals, we encourage RTOs and ISOs to give
priority to any significant concerns that may be raised on these
issues, including concerns as to the value to the market of significant
changes to the market rules. For example, PJM recently has conducted a
series of forums on long-term contracts to gather information and
facilitate the exchange of ideas on this important issue. We encourage
similar efforts on the concerns raised by APPA and AARP, et al. Any
proposed solutions should be vetted through the stakeholder process and
ultimately considered by the boards of the RTOs or ISOs. Ultimately,
such matters may be brought to the Commission after consideration by
the region. We encourage each region to commence the consideration of
any such issues in the near future and not await the issuance of a
final rule in this proceeding.
25. However, those entities that have such concerns have a
responsibility to propose solutions to address those concerns. For
example, American Forest submitted comments that contained a mechanism,
the Financial Performance Obligation (FPO), to address concerns that
they raised regarding the structure of organized markets. Portland
Cement Association, et al., also included a proposed solution in its
comments to address their concerns regarding the organized markets. We
are encouraged by entities that actually propose solutions rather than
merely identify concerns without proposing any meaningful ways to
address those concerns. While we do not adopt these proposals in this
proceeding, we believe that they warrant additional consideration.
Therefore, as explained below, we direct Staff to convene a technical
conference regarding the American Forest and Portland Cement
Association, et al., proposals so that the Commission and the industry
can learn
[[Page 12581]]
more about the proposals and the merit of adopting such changes where
appropriate.
IV. Discussion
A. Demand Response and Pricing During Periods of Operating Reserve
Shortages in Organized Markets
26. This section of the NOPR proposes several reforms to further
eliminate barriers to demand response in organized energy markets.
These reforms must ensure that demand response is treated comparably to
other resources. The Commission proposes to require RTOs and ISOs to:
(1) Accept bids from demand response resources in their markets for
certain ancillary services, comparable to other resources; (2)
eliminate, during a system emergency, certain charges to buyers in the
energy market for voluntarily reducing demand; and (3) permit ARCs to
bid demand response on behalf of retail customers directly into the
RTO's or ISO's organized markets.\24\ We also propose that RTOs and
ISOs modify their rules governing price formation during periods of
operating reserve shortage. These proposals, if adopted, would require
market rules to ensure that demand response can participate directly
and is treated comparably to supply resources in the organized electric
energy and ancillary services markets. We also propose to require that
each RTO and ISO study further reforms to address any remaining
barriers to ensure that demand response is treated comparably to other
resources and to report to the Commission within six months of the date
of the final rule in this proceeding. In addition, we propose that each
RTO or ISO must adopt reasonable standards necessary for system
operators to call on demand response resources, and mechanisms to
measure, verify, and ensure compliance with any such standards.\25\ As
discussed further below, we intend to direct staff to convene a
technical conference to explore issues that the RTOs and ISOs should
include as part of these studies. The specific reforms being proposed
here are therefore the next step in removing barriers to demand
response, but not the final step.
---------------------------------------------------------------------------
\24\ We will use the phrase ``aggregation of retail customers''
to refer to parties that aggregate demand response bids (which are
mostly from retail loads), or ARCs.
\25\ We understand that some RTOs and ISOs may already be
developing measurement and verification requirements, as well as
appropriate mechanisms to ensure compliance. It is not our intention
that these programs be delayed based on our proposals here.
---------------------------------------------------------------------------
1. Background
27. 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.\26\ Based on the view that the value to
customers of electric power varies,\27\ the Commission's policy is to
eliminate barriers to 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; enhances reliability; and encourages new technologies that
support the use of renewable energy resources, distributed generation,
and advanced metering. The reforms we propose today would further
facilitate demand response by removing several barriers to demand
response. This will benefit customers of electric energy because
increased demand response will improve price signals and provide for
greater flexibility. We provide background on the benefits of demand
response and prior Commission actions addressing demand response below.
---------------------------------------------------------------------------
\26\ 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, LLC,
95 FERC ] 61,306 (2001); PJM Interconnection, LLC, 99 FERC ] 61,227
(2002); Southwest Power Pool, Inc., 116 FERC ] 61,289 (2006).
\27\ That is, for two customers at the same time and place, one
customer may prefer to reduce consumption if the price is high, and
the other may be willing to pay a high price to avoid curtailment in
an emergency.
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a. Importance of Demand Response to Competition in RTO/ISO Areas
28. A well-functioning competitive wholesale electric market should
reflect current supply and demand conditions. Enabling demand-side
responses, as well as supply-side resources, improves the economic
operation of electric power markets by aligning prices more closely
with the value customers place on electric power.
29. Demand response helps to reduce prices in competitive wholesale
markets in at least three ways. First, demand response has both a
direct effect and an indirect effect on wholesale demand. The direct
effect occurs when demand response 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 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.\28\
---------------------------------------------------------------------------
\28\ See Federal Energy Regulatory Commission, Assessment of
Demand Response and Advanced Metering: Staff Report, Docket No.
AD06-2-000, at 11 (August 8, 2006) (2006 FERC Staff Demand Response
Assessment).
---------------------------------------------------------------------------
30. Second, demand response tends to flatten an area's load
profile. The combination of reductions in peak demand and a shift of at
least a portion of this peak demand to non-peak periods due to demand
response would tend to make peak and off-peak demand less divergent--a
flatter load profile. A flatter load profile would reduce the need to
use the more costly resources during periods of high demand, which
tends to shift the distribution of resource types toward lower-cost
base load generation and away from higher-cost peaking generation. This
effect tends to lower the overall average cost to produce energy.\29\
---------------------------------------------------------------------------
\29\ Id.
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31. Third, demand response can help reduce generator market power.
As more demand response generally is available during peak periods,
power suppliers need to account more for the price responsiveness of
load when they consider submitting 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.\30\
---------------------------------------------------------------------------
\30\ Id. at 12.
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b. Prior Commission Actions To Address Demand Response
32. 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.\31\
---------------------------------------------------------------------------
\31\ See, e.g., New York Indep. Sys. 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, LLC, 95 FERC ] 61,306 (2001);
PJM Interconnection, LLC, 99 FERC ] 61,139 (2002); PJM
Interconnection, LLC, 99 FERC ] 61,227 (2002).
---------------------------------------------------------------------------
33. These orders approved various types of demand response
programs, including programs to allow demand response to be used as a
capacity resource \32\ and as a resource during
[[Page 12582]]
system emergencies,\33\ to allow wholesale buyers and qualifying large
retail buyers to bid demand response 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 ARCs.\34\ The Commission also has approved special
demand response applications such as use of demand response for
synchronized reserves and regulation service.\35\ The theme underlying
the Commission's approval of these programs has been to allow demand
response resources to participate in these markets on a basis that is
comparable to other resources.
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\32\ See, e.g., PJM Interconnection, LLC, 117 FERC ] 61,331
(2006); Devon Power LLC, 115 FERC ] 61,340, order on reh'g, 117 FERC
] 61,133 (2006), appeal pending sub nom. Maine Pub. Utils. Comm'n v.
FERC, No. 06-1403 (DC Cir. 2007).
\33\ See, e.g., New York Indep. Sys. Operator, Inc., 95 FERC ]
61,136 (2001); NSTAR Services Co. v. New England Power Pool, 95 FERC
] 61,250 (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, LLC, 99 FERC ] 61,139 (2002).
\34\ See, e.g., New York Indep. Sys. 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, LLC, 99 FERC ] 61,227 (2002).
\35\ See, e.g., PJM Interconnection, LLC, 114 FERC ] 61,201
(2006).
---------------------------------------------------------------------------
34. The Commission has approved programs that allow smaller retail
customers--that cannot individually meet the RTO or ISO minimum bid
size threshold--to combine individual demand response into a larger
block for bidding into the organized markets, if permitted by state
law, without having to go through their LSE.\36\ A third-party ARC,
often called a curtailment service provider, typically provides this
aggregation service. The aggregate demand response may be bid directly
into the energy and ancillary services markets.
---------------------------------------------------------------------------
\36\ Supra note 34.
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35. 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).\37\ Order No. 890 requires any
public utility with an OATT to allow qualified demand response
resources to participate in its regional transmission planning process
on a comparable basis to generation resources and to allow qualified
demand response to provide certain ancillary services. Specifically,
the Commission agreed with Alcoa's request that load resources (i.e.,
demand response) should be permitted to self-supply and sell ancillary
services to third parties.\38\ In doing so, the Commission 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.\39\ 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.\40\
---------------------------------------------------------------------------
\37\ See Mandatory Reliability Standards for the Bulk-Power
System, Order No. 693, 72 FR 16,416 (April 4, 2007), FERC Stats. &
Regs. ] 31,242, order on reh'g, Order No. 693-A, 120 FERC ] 61,053
(2007).
\38\ Order No. 890, FERC Stats. & Regs. ] 31,241 at P 887-88.
\39\ E.g., Order No. 890, FERC Stats. & Regs. ] 31,241 at OATT
Schedule 5 (Operating Reserve--Spinning Reserve Service). Order No.
890 does not require transmission providers, however, to purchase
ancillary services from non-generation resources or generation
resources.
\40\ 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, FERC Stats. & Regs. ]
31,242 at P 330-35, 404-06, 573.
---------------------------------------------------------------------------
36. The Commission has also worked closely with state regulators to
examine demand response issues. The NARUC-FERC Collaborative Dialogue
on Demand Response began in November 2006 to explore state-federal
coordination of efforts to promote and integrate demand response into
retail and wholesale markets. The Commission has conducted several
technical conferences on demand response over the last several years,
most recently on April 23, 2007.\41\ In addition, as mentioned, in
response to a requirement of EPAct 2005 \42\ to assess demand response
capability nationally, in August 2006 the Commission published a staff
report on demand response and advanced metering.\43\ In September 2007,
the Commission published its second annual staff report on demand
response and advanced metering.\44\
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\41\ For example, the Commission conducted a technical
conference on January 25, 2006 to help prepare for a survey and a
staff report on demand response in Docket No. AD06-2-000. See supra
note 28. The April 23, 2007 conference was convened in Docket No.
AD07-11-000.
\42\ Public Law No. 109-58, Sec. 1252(e)(3), 119 Stat. 594, 966
(2005).
\43\ See 2006 FERC Staff Demand Response Assessment.
\44\ See Federal Energy Regulatory Commission, 2007 Assessment
of Demand Response and Advanced Metering: Staff Report, (September
2007) (2007 FERC Staff Demand Response Assessment).
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2. The Need for Commission Action
37. While the Commission and the various RTOs and ISOs have done
much to eliminate barriers to demand response in organized power
markets, more needs to be done to ensure comparable treatment of all
resources. The 2006 FERC Staff Demand Response Assessment estimated the
total installed demand response capability from existing programs
nationally to be 37,500 MWs, or about five percent of current peak
demand.\45\ Several reports indicate that the potential demand response
capability available in the United States may be much greater.\46\
---------------------------------------------------------------------------
\45\ 2006 FERC Staff Demand Response Assessment at 7.
\46\ 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), available at http://www.brattle.com/_documents/UploadLibrary/Upload574.pdf.
---------------------------------------------------------------------------
38. The Commission's policy is to eliminate barriers to the
participation of demand response in the organized power markets by
ensuring comparable treatment of resources. This position is consistent
with EPAct 2005, which states that demand response shall be encouraged
and unnecessary barriers to demand response participation in energy,
capacity, and ancillary service markets shall be eliminated.\47\ The
Commission can take additional steps to further encourage demand
response to improve the operation of the organized energy and ancillary
services markets by removing several unnecessary barriers to demand
response participation.\48\
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\47\ Section 1252(f) of the EPAct 2005 states that, ``[i]t is
the policy of the United States that time-based pricing and other
forms of demand response whereby electricity customers are provided
with electricity price signals and the ability to benefit by
responding to them, shall be encouraged, the deployment of such
technology and devices that enable electricity customers to
participate in such pricing and demand response systems shall be
facilitated, and unnecessary barriers to demand response
participation in energy, capacity, and ancillary service markets
shall be eliminated.''
\48\ We note that while the Commission can remove some obstacles
to demand participation in organized markets, more effective demand
response also requires the action of state commissions. An effective
way for demand to respond to price is at the retail level, through
some form of time-based retail rates (e.g., 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.
---------------------------------------------------------------------------
39. The Commission can further eliminate barriers to the
participation of demand response in certain ancillary services markets.
Some forms of demand response are well suited to provide the ancillary
services of spinning reserves, supplemental
[[Page 12583]]
reserves, energy imbalance, and regulation and frequency response.\49\
Because demand is always connected and demand response, in principle,
can always be available, some forms of demand response resources may be
able to provide a rapid, near real-time response.\50\ Nevertheless, not
all RTOs and ISOs allow demand response to participate in ancillary
services markets. ISO-NE, NYISO, and CAISO allow demand response
resources to provide supplemental (non-spinning) reserves. As of mid-
2007, only PJM allows demand response resources to provide synchronized
reserves (PJM's term for spinning reserves) and regulation service.\51\
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\49\ See 2006 FERC Staff Demand Response Assessment at 51. For
an explanation of each of these ancillary services, see the pro
forma OATT, Schedules 3 through 6, contained in Order No. 890.
\50\ 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.
\51\ We note, however, that no resource has yet qualified to
provide this service to PJM.
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40. In Order No. 890, the Commission modified the definitions of
certain ancillary services in the pro forma open access transmission
tariff to clarify that demand response is eligible to supply these
ancillary services on a comparable basis to generation resources. Order
No. 890 concluded, however, that procurement and pricing of ancillary
services--including issues related to competitive procurement--were
beyond the scope of that rulemaking. Though RTOs and ISOs procure
ancillary services through competitive market means, they are not
currently required to accept bids from qualified demand response
providers to provide ancillary services even if those providers are
technically capable of doing so. This hinders the integration of
qualified demand response resources into these RTO and ISO ancillary
services markets.
41. One reason for the lack of participation of demand response in
some ancillary service markets may be that market rules for bidding and
participating in ancillary services markets were developed with
generation in mind and may not accommodate demand response resources.
For example, many demand response resources can respond quickly and at
a low cost if called upon for a short duration, which may make them
well suited for providing operating reserves. If market rules require,
however, that a single bid be made into a joint energy-plus-reserves
market (also known as a ``co-optimized'' market), those seeking to
offer operating reserves risk being dispatched to provide energy or
other ancillary services for which they are not well suited. As a
result, a potential operating reserve provider that does not wish to be
called upon frequently or for a prolonged period in the energy market
may simply decide not to participate in a co-optimized market, and
consequently not be a source for providing demand response resources as
operating reserves. Market rules that do not allow a demand response
provider to limit the frequency and duration of interruption may
thereby create a disincentive for a demand response resource to bid
into the operating reserves market.\52\
---------------------------------------------------------------------------
\52\ See 2006 FERC Staff Demand Response Assessment at 123.
---------------------------------------------------------------------------
42. Further, 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. While the
design of today's organized markets does allow some flexible and some
price-sensitive bidding into day-ahead and real-time energy markets,
the Commission is nevertheless concerned that some market features may
inhibit LSEs and other demand response providers from bidding load
reductions into energy markets. For example, in most organized markets,
if an LSE's actual purchase from the real-time market differs from the
purchase it scheduled in the day-ahead market, it may be assessed an
uplift charge (separate from any imbalance charge). This uplift charge
recovers certain costs of extra generation when day-ahead purchases
exceed real-time purchases. However, these costs may be minimal during
an emergency when there is no extra generation. Further, this uplift
charge may unnecessarily discourage an LSE from urging retail customers
to conserve energy during a system emergency. RTO and ISO tariffs also
do not impose these types of charges on generators that generate more
power during system emergencies than scheduled. Eliminating this uplift
charge for demand response sought by RTOs or ISOs from buyers in an
emergency removes a disincentive for this demand response and promotes
comparable treatment of demand and supply resources.
43. Organized energy market rules also may restrict the type of bid
that a LSE or ARC may submit.\53\ There is usually a minimum bid size
threshold in an RTO or ISO market. Also, it is hard for some demand
response providers to participate 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. Aggregation programs can improve
the participation of small retail loads that lack standing as an LSE or
individually cannot meet a requirement that a demand response bid be of
minimum size. These programs allow a larger number of customers to
access demand response programs, which increases the potential market
and reliability benefits realized from demand response in wholesale
markets. The 2006 FERC Staff Demand Response Assessment and comments
that we have received indicate, however, that more needs to be done to
facilitate the direct participation of ARCs in energy markets.
---------------------------------------------------------------------------
\53\ In some cases, this may be intended to treat a demand
response resource bid the same as a generation bid, but more often,
bidding features available to generation, such as a guaranteed
minimum price, are not available to demand response resources.
---------------------------------------------------------------------------
44. Another factor that may limit participation in demand response
programs is the use of bid caps and price caps in wholesale 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 period of operating reserve shortage and that
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. Consequently,
both generation and demand response can be in short supply at once, and
the market-clearing price may not reflect the actual cost of providing
more power or the value to customers of not being interrupted. Further,
as discussed in the long-term contracting section below, capping the
exposure of LSEs to higher prices may reduce their incentive to explore
various hedging activities, such as participating in interruptible
demand response programs, entering into long-term contracts or similar
power supply procurement options, and building new generating units.
45. Certain demand response programs may themselves act to dampen
prices during a period of operating reserve shortage. The term
``emergency demand response program'' is used here to refer to a demand
response program where participants agree to reduce demand if called on
by the RTO or ISO during a system emergency. They may be paid a fixed
price rather than the market-clearing price when called on.
[[Page 12584]]
As a result, the market-clearing price may decrease because demand is
reduced when an emergency demand response resource is used, even though
that resource is the highest-valued resource used at the time. The
reduced price 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\
---------------------------------------------------------------------------
\54\ The Commission approved this change in 2003. New York
Indep. Sys. Operator, Inc., 102 FERC ] 61,313 (2003).
---------------------------------------------------------------------------
3. Proposed Reforms
46. In order to further eliminate barriers to demand response in
organized markets, the Commission proposes reforms to obligate RTOs and
ISOs to: (1) Accept bids from demand response resources in its markets
for certain ancillary services, comparable to any other resources; (2)
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; (3) permit an ARC to bid a demand
response on behalf of retail customers directly into the RTO's or ISO's
organized energy markets, unless the laws or regulations of the
relevant electric retail regulatory authority do not permit a retail
customer to participate; and (4) modify their market rules to allow the
market-clearing price to accurately reflect the value of energy during
periods of operating reserve shortage. The Commission also proposes to
require RTOs and ISOs to study whether further reforms are necessary to
eliminate barriers to demand response in organized markets. We believe
that these proposals ensure comparable treatment of demand response
resources. We discuss these proposals in greater detail below.
9. Ancillary Services Provided by Demand Response Resources
i. Preliminary Proposals in the ANOPR
47. In the ANOPR, the Commission sought comment on obligating RTOs
and ISOs to purchase demand response resources in their markets for
certain ancillary services, similar to any other resources, if the
resources meet the necessary technical requirements and submit a bid
under the generally-applicable bidding rules at or below the market-
clearing price. The Commission contemplated granting an exception where
the seller would not be permitted to do so by state retail laws or
regulations. The Commission proposed to require 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. To
be eligible to supply these ancillary services, the Commission stated
that demand response resources must be capable of reducing demand
within seconds or minutes and must meet the RTO's or ISO's reasonable
size, telemetry, metering, and bidding requirements.
48. The Commission also sought comment on requiring modifications
to RTO and ISO tariffs to provide that demand response resources must
be allowed to provide spinning and supplemental reserves without also
being required to sell into the energy market.
49. The Commission requested comment on, among other things,
whether each RTO or ISO should propose its own minimum requirements
(for example, as to minimum size bids, measurement, and telemetry) or
whether the Commission should specify the appropriate minimum
requirements in a Commission rule.
ii. Comments on the ANOPR Proposals and Questions
50. Most of the commenters that address the Commission's proposal
in the ANOPR support having an RTO or ISO accept bids from demand
response resources for certain ancillary services on a comparable
basis. For example, BlueStar Energy states that the Commission's
proposal ``will lead to greater economic efficiency, and reduce costs
and risks for retail customers.'' \55\ Industrial Coalitions states
that the Commission's current proposal is the next logical step, after
Order No. 890, in promoting the integration of demand response
resources into all RTO- and ISO-coordinated markets and services.\56\
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\55\ BlueStar Energy at 2.
\56\ Industrial Coalitions at 13-14.
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51. Other commenters raise concerns with the ability of smaller
entities to fully participate as resource providers for ancillary
services. APPA argues that it may be difficult to reconcile the
technical requirements for end users, necessitated by the instantaneous
nature of certain ancillary services, with the desire of many larger
loads for reliability, flexibility, and convenience, thus making it
unlikely that many demand response resources will want to provide
ancillary services.\57\ The California PUC argues that requiring demand
response resources to satisfy all requirements for service provision
comparable to those applied to supply resources could construct
considerable barriers to participation of small demand response
resources.\58\
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\57\ APPA at 48.
\58\ California PUC at 7.
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52. NYISO and National Grid support the participation of demand
response to the extent practical in the ancillary services market. They
request, however, that the Commission clarify that it would not require
the RTO or ISO to ``purchase'' certain ancillary services from demand
response resources but to accept bids from them.\59\
---------------------------------------------------------------------------
\59\ NYISO at 28; National Grid at 5.
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53. Multiple commenters supported the Commission's proposal to
allow demand response resources to provide reserves without being
required to sell into the energy market. Alcoa, for example, states
that demand-responsive load supplying ancillary services does not
create market power concerns because such services are not the primary
business of demand response resources.\60\ Strategic Energy states that
the proposal would allow customers to offer operating reserves without
disrupting the company business via prolonged shutdowns to satisfy an
energy schedule.\61\
---------------------------------------------------------------------------
\60\ Alcoa at 18-19.
\61\ Strategic Energy at 4.
---------------------------------------------------------------------------
54. Conversely, several commenters oppose the Commission's
proposal. ISO-NE does not support the proposal because its core market
design does not allow separate bids to be placed in the energy and
reserve markets for any resources.\62\ NYISO concurs, claiming that the
proposal would not be efficient in New York because NYISO's market
design co-optimizes energy and ancillary services through an integrated
dispatch process and generators in New York must make themselves
available to supply energy in order to be eligible to supply ancillary
services.\63\ Thus, any change to NYISO's market design could lead to
inefficient scheduling outcomes. NYISO does state, however, that its
existing bidding procedures are flexible enough to permit demand
response resources to structure their bids in a way that virtually
eliminates the possibility that they may be selected to provide energy
involuntarily. NYISO asserts that it could develop new bidding rules
that would allow demand response resources to specify that they: (1)
Could not be called on for more than an hour or a certain maximum
number of times per day; or (2) would be subject to energy management
limits. NYISO asserts that such rules would allow demand side resources
to convey their limitations on frequency and duration of
[[Page 12585]]
activation without undermining the co-optimized market design.
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\62\ ISO-NE at 19.
\63\ NYISO at 32.
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55. A majority of commenters assert that the Commission should
allow RTOs and ISOs to develop their own minimum requirements for
demand response participation in ancillary services markets. EEI states
that the Commission recognized that the various organized markets and
state regulatory programs are different and had different physical and
state requirements.\64\ Dominion Resources, Pepco, PGC, PG&E, and SPP
agree. EEI further argues that given all the regional differences in
control systems and market software, having a standardized set of
requirements may result in unnecessary expense and delay in
implementation in certain regions by requiring incompatible
infrastructure. PGC claims that a ``one-size fits all'' minimum
requirements rule would be inappropriate, and states that allowing each
RTO or ISO region to establish its own requirements would permit each
system the flexibility to modify requirements as they gain additional
experience with demand response resources.\65\ Pepco argues for RTO/
ISO-established technical requirements because the types of generation
resources available, transmission constraints, and load pattern
characteristics for each region would all be taken into account, and
would be appropriate for that region.\66\
---------------------------------------------------------------------------
\64\ EEI at 12.
\65\ PGC at 10-11.
\66\ Pepco at 7.
---------------------------------------------------------------------------
iii. Commission Proposal
56. The Commission proposes to obligate each RTO or ISO to accept
bids from demand response resources, on a basis comparable to any other
resources, for ancillary services that are acquired in a competitive
bidding process, if the demand response resources (1) are technically
capable of providing the ancillary service and meet the necessary
technical requirements, and (2) submit a bid under the generally-
applicable bidding rules at or below the market-clearing price, unless
the laws or regulations of the relevant electric retail regulatory
authority do not permit a retail customer to participate. This proposal
would apply to competitively-bid markets, if any, for energy imbalance,
spinning reserves, supplemental reserves, reactive supply and voltage
control, and regulation and frequency response as defined in the pro
forma OATT, or to the markets of their functional equivalents in an RTO
or ISO tariff. We propose that demand response resources that are
capable of reducing demand within the response time requirement for the
ancillary service and that meet reasonable requirements adopted by the
RTO or ISO as to size, telemetry, metering, and bidding be eligible to
supply energy imbalance, spinning reserves, supplemental reserves,
reactive and voltage control, and regulation and frequency response. In
the compliance filing to be submitted within six months of the final
rule, the RTO or ISO must adopt reasonable standards necessary for
system operators to call on demand response resources, and mechanisms
to measure, verify, and ensure compliance with any such standards. Such
standards would be subject to Commission approval.
57. We believe that this policy would increase the competitiveness
of ancillary services markets, help reduce the price of ancillary
services, and improve the reliability of the grid. Experience in the
PJM, CAISO, and ERCOT markets has demonstrated that certain demand
response resources can provide some ancillary services reliably.
Moreover, this proposal would require that, for ancillary services
acquired in a competitive process, RTOs and ISOs make any necessary
changes to their tariffs and market rules to allow for direct demand
response resource participation in the ancillary services markets.
58. We clarify, in response to NYISO's and National Grid's
requests, that this proposal would not require an RTO or ISO to
purchase certain ancillary services from demand response resources, but
rather to accept bids from them for ancillary services acquired in a
competitive bidding process, and if they meet minimum technical
requirements and clear the market, on a basis comparable to other
resources. The purpose of the proposal is to ensure that all RTOs and
ISOs treat demand response resources comparably with other resources in
the market rules for energy imbalance, spinning reserves, supplemental
reserves, reactive and voltage control, and regulation and frequency
response. This proposal does not require the adoption of a competitive
bidding process where one was previously not utilized.
59. The California PUC's argument that ancillary services market
rules for comparable and nondiscriminatory access for demand response
resources may be a barrier to participation of small demand response
resources has merit. Experiments and pilot programs suggest that
resources below minimum size thresholds in RTO and ISO markets have the
potential to respond quickly and reliably.\67\ Adjusting minimum size
thresholds and telemetry requirements to accommodate smaller demand
response resources may result in a significant increase in potential
sources of operating reserves. Without extensive experience with the
ability of smaller demand response resources to provide ancillary
services, however, it is premature to mandate specific conditions under
which RTOs and ISOs must accommodate smaller resources into the
spinning reserves, supplemental reserves, energy imbalance markets,
reactive and voltage control, and regulation and frequency response.
Instead, we propose to direct the RTOs and ISOs to perform an
assessment of the technical feasibility and value to the market of
smaller loads providing some ancillary services one year from the
effective date of the final rule, including whether (and how) smaller
resources can reliably and economically provide operating reserves
through pilot projects or other mechanisms.\68\
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\67\ See 2006 FERC Staff Demand Response Assessment at 114.
\68\ For example, ISO-NE is assessing whether small demand
response resources can provide operating reserves in its Demand
Response Reserves Pilot.
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60. In the ANOPR, the Commission made a preliminary proposal to
remove a disincentive for demand response to offer operating reserves.
The proposal was 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, explaining
that customers may be more likely to offer demand response as operating
reserves if they do not need to worry about disruptions to their
businesses by participating in the energy markets. We are sympathetic,
however, to concerns raised in ISO-NE's and NYISO's comments that the
ANOPR proposal could undo their recent success in resolving design
problems of disjointed markets by combining and co-optimizing their
energy and ancillary services markets. The Commission is mindful of
these concerns and does not intend to negatively affect the market
efficiencies created by co-optimized market designs.
61. NYISO suggests, however, that the development of new bidding
rules could limit the exposure of demand response resources selling
into the energy market--rules that would not require changes to its co-
optimized markets. Resource bids in RTO and ISO markets typically allow
bidders to specify various parameters of their bid (e.g., price,
quantity, startup and no-load
[[Page 12586]]
costs, and minimum downtime between starts). NYISO suggests new
parameters that would allow demand response bidders to specify
additional constraints on the dispatch of their resources. In its
comments, NYISO offers that a demand response bidder could specify the
maximum duration in hours that a bid can be dispatched, maximum number
of times that a bid can be dispatched during a day, and a maximum
amount of energy that a resource can produce either daily or weekly,
and that those parameters could be incorporated into the bidding rules.
We believe that NYISO's suggestion has merit.
62. We propose here to require RTOs and ISOs to allow demand
response resources to specify limits on the frequency and duration of
their service in their bids to provide ancillary services--or their
bids into the joint energy-ancillary services market in the co-
optimized RTO markets. These limits are comparable to the limits
generators may specify on price, quantity, startup and no-load costs,
and minimum downtime between starts--limits that may not be available
to demand response resources. The proposal is for RTOs and ISOs to
incorporate new parameters into their bidding rules that allow demand
response resources to specify a maximum duration in hours that the
demand response resource may be dispatched, a maximum number of times
that the demand response resource may be dispatched during a day, and a
maximum amount of electric energy that the demand response resource may
be required to provide either daily or weekly. We expect that this
requirement would encourage demand response in the spinning reserves,
supplemental reserves, and regulation and frequency response markets by
reducing the risk that demand response resources would be called on too
frequently or for too long a period. We ask for comment on whether
these new parameters should be available for all bids, not just demand
response resources. These new bidding parameters could benefit energy-
limited resources or runtime-limited resources, e.g., hydropower and
units with environmental restrictions. The new bidding parameters could
also benefit resources that cannot start and stop quickly. The proposal
should not require fundamental changes to existing market designs,\69\
or affect the efficiencies of co-optimized markets.
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\69\ Bidding rules at RTOs and ISOs such as Midwest ISO and PJM
already incorporate aspects of these proposed new bidding
parameters.
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63. An RTO or ISO must either propose amendments to its tariff to
comply with the proposed requirement or demonstrate that its existing
tariff and market design already satisfy the requirement. This filing
would be submitted within six months of the date the final rule is
published in the Federal Register. The Commission will assess whether
each filing satisfies the proposed requirement and will issue
additional orders as necessary.
64. We request comment on this proposed requirement for RTOs and
ISOs to allow demand response resources to specify a maximum duration
for dispatch, a maximum number of times per day that demand response
resources could be called, or a maximum amount of energy per day or
week, and on whether other bidding parameters should be considered. We
note that any parameters must accommodate the characteristics of demand
response resources but must not have the effect of creating an undue
preference for demand response resources vis-[agrave]-vis other
resources. Further, we intend that the bidding parameters would be
implemented at all RTOs and ISOs. Finally, we agree with commenters
that it would not be appropriate for the Commission to develop in a
rulemaking a standardized set of minimum requirements for minimum size
bids, measurement, telemetry, and other factors. Instead, we will allow
each RTO or ISO to develop its own minimum requirements, including
bidding parameters. We propose to require the RTOs and ISOs confer with
each other and to provide a technical and factual basis for any
necessary regional variations.
b. Deviation Charge
i. Preliminary Proposals in the ANOPR
65. In the ANOPR, the Commission stated that it was 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.\70\
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\70\ The Commission noted that it would refer to the charge that
it proposed to eliminate during an emergency as a ``deviation
charge.''
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66. The Commission requested comment on whether an RTO or ISO
should assess a deviation charge for a day-ahead to real-time load
reduction in the absence of a system emergency. The Commission noted
that eliminating the deviation charge might have unintended
consequences and asked whether it would result in an unfair
reallocation of these costs to others; whether it was important to
retain the deviation charge to discourage poor scheduling practices; or
whether eliminating the deviation charge would introduce opportunities
for gaming behavior.
ii. Comments on the ANOPR Proposals and Questions
67. The vast majority of commenters support the preliminary
proposal in the ANOPR to modify RTO and ISO tariffs to eliminate a
deviation charge during a system emergency.\71\ For instance, APPA
asserts that it does not make much sense to penalize entities that help
the RTO alleviate a system emergency.\72\ SMUD states that eliminating
penalties for load reductions during a system emergency is a sensible
approach to promoting further development of demand response as a
resource eligible to be bid into organized markets.\73\
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\71\ A number of commenters appear to misunderstand the
proposal. Several did not distinguish a voluntary reduction in power
purchase between day-ahead and real time (the intent here) from a
demand response bidder that fails to deliver its accepted demand
response.
\72\ APPA at 53.
\73\ SMUD at 4.
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68. Several supporters prefer allowing RTOs and ISOs the
flexibility to establish rules for settling deviations. For example,
SoCal Edison-SDG&E believe each RTO or ISO is different, and that
allowing each region to determine specific deviation charges based on
individual circumstances may make more sense than adopting uniform
standards. In their opinion, such an approach would help mitigate any
unintended consequences, such as gaming.\74\
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\74\ SoCal Edison-SDG&E at 2-3.
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69. Other commenters who disagree with the Commission's preliminary
proposal are concerned about the uplift costs resulting from the
elimination of deviation charges. DC Energy argues that eliminating the
deviation charge penalty for demand response participants would
negatively impact the market and result in unfair cost reallocation.
\75\ It maintains that such elimination would create two classes of
market participants and have a deleterious affect on the market by
inefficiently and unfairly reallocating costs to others.
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\75\ DC Energy at 4.
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70. Two commenters raise concerns about the applicability of the
proposal to virtual bidding.\76\ APPA and the
[[Page 12587]]
Connecticut and Massachusetts Municipals worry that virtual bidders may
engage in market manipulation. Connecticut and Massachusetts Municipals
argue that virtual bidders' virtual load in the day-ahead market may
create the appearance of a shortage even without corresponding real-
time load. Therefore, the Commission should tailor any deviation
exemption to apply to physical loads only.\77\ APPA agrees.\78\
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\76\ Virtual bidding, sometimes called ``convergence bidding,''
involves sales or purchases in the RTO or ISO day-ahead market that
do not go to physical delivery. For example, an entity that does not
serve load may make a purchase in the day-ahead market, which it
must pay for, and then take no power in real time. This lack of
consumption is treated as a sale of the power in the real-time spot
market. By making virtual energy sales or purchases in the day-ahead
market and settling these positions in the real-time market, any
market participant can arbitrage price differences between the two
markets.
\77\ Connecticut and Massachusetts Municipals at 40.
\78\ APPA at 53.
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71. Suppliers predominantly support the Commission's additional
ANOPR proposal to eliminate deviation charges absent system
emergencies. These commenters argue that any load reduction, during
either a system emergency or non-emergency, would benefit all loads in
RTOs and ISOs through greater market efficiency. Other commenters,
including the RTOs and ISOs, however, oppose this proposal. Arguments
against eliminating deviation charges for non-emergency periods include
concerns about potential gaming and inaccurate scheduling. APPA states
that in order to ensure accurate schedules and cost accountability,
deviation charges should remain in place absent a system emergency.\79\
EEI argues that the elimination of this charge during non-emergencies
``sends the wrong price signal to market participants, provides a
disincentive to minimize deviations, and leads to increased costs to
the market.'' \80\ PJM states that little reliability value is
associated with load reductions during non-emergencies, and therefore
waiving the deviation charges is not justified, particularly when costs
would have to be collected through a socialized uplift charge.\81\
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\79\ Id. at 54.
\80\ EEI at 17-19.
\81\ PJM at 7-8.
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iii. Commission Proposal
72. The Commission proposes to require that all RTO and ISO tariffs
be modified to eliminate a charge, which we refer to as a deviation
charge,\82\ to a buyer \83\ in the energy market for taking less
electric energy in the real-time market during a real-time market
period for which the RTO or ISO declares an operating reserve shortage
or makes a generic request to reduce load to avoid an operating reserve
shortage.
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\82\ Deviation charges recover certain costs including
importantly generators' costs (such as start-up costs) that exceed
their energy market revenues when real-time demand is less than
forecast. These ``uplift'' costs may include the cost of the extra
generators committed after the close of the day-ahead market that
are not recovered from sales of energy at real-time LMPs.
\83\ Examples of buyers in RTO and ISO energy markets include a
load serving entity that purchases electricity to meet the load
requirements of its retail customers or a retail customer that
purchases electricity directly from the wholesale market.
---------------------------------------------------------------------------
73. An RTO or ISO must either propose amendments to its tariff to
comply with the proposed requirement or demonstrate that its existing
tariff and market design already satisfy the requirement to eliminate
the deviation charge during a system emergency. This filing would be
submitted within six months of the date the final rule is published in
the Federal Register. The Commission will assess whether each filing
satisfies the proposed requirement and will issue additional orders as
necessary.
74. Commenters supporting this proposal make sound arguments for
it. We agree that removal of this deviation charge during a system
emergency would remove a disincentive for greater demand response in
the real-time market. A buyer may be deterred from reducing load during
periods when supplies are tight and the real-time price is high if that
buyer is subject to a charge for reducing its real-time consumption
from its day-ahead purchases. If that buyer takes the appropriate
action to reduce load and is accordingly penalized by a deviation
charge, this unintended disincentive may lead the buyer to maintain a
high load or discourage an LSE from calling on the demand response
capabilities of its retail customers. Removal of this disincentive is
important during a system emergency when load reduction is needed (and
valued) most.
75. RTO and ISO tariffs already contain provisions associated with
the dispatch of generators during real time, and specify payments and
deviation charges for uninstructed deviations. During system
emergencies, all available generation resources are instructed to
increase output if possible. Because these units are instructed to
increase output, RTO and ISO tariffs do not impose deviation charges on
generators that generate more power during system emergencies than
scheduled. Elimination of deviation charges for demand response by
buyers ensures comparability between demand and supply resources.
76. As noted above, although a majority of commenters express
support for this proposal, a significant number appear to misunderstand
it. For example, some commenters appear to believe that the Commission
proposed to remove any penalty for a day-ahead bidder of demand
response who fails to reduce demand in real time, and oppose this idea
as discriminating in favor of a demand response provider. Accordingly,
we provide two clarifications. First, this proposal applies to demand
response that is in addition to the demand response of participants in
RTO/ISO wholesale demand response programs. If demand response program
participants reduce demand as directed, RTOs and ISOs already do not
levy a deviation charge. We are not proposing to remove any penalty for
a day-ahead bidder of demand response who fails to follow directions to
reduce demand in real time. This proposal focuses on demand response
from LSEs and other buyers that consume less total energy in real time
during system emergencies than they had scheduled in the day-ahead
market.\84\ Second, deviation charges would be eliminated only when the
RTO or ISO announces an emergency situation after the close of the day-
ahead market. The RTO or ISO could inform buyers either by instituting
formal procedures that direct LSEs and electric utilities to activate
retail demand response programs during a system emergency or by
requesting voluntary load reductions, which may occur prior to or at
the same time that a system emergency is declared. This is intended to
ensure that buyers are not penalized when they voluntarily reduce load
to improve system reliability at the request of a system operator.
---------------------------------------------------------------------------
\84\ Note that under our proposal, if a demand response program
participant reduces demand at greater levels than instructed during
a system emergency, it will not be subjected to a deviation charge
for the higher than instructed demand response.
---------------------------------------------------------------------------
77. In response to concerns that eliminating the deviation charge
during a system emergency would result in an unfair allocation of the
uplift costs or the creation of an unfair subsidy to demand response,
we recognize that a deviation charge covers real costs to generators
and others. These costs include those associated with the extra
generation committed after the close of the day-ahead market that are
not recovered from sales of energy in real time. Since demand response
during system emergencies can be instrumental in maintaining system
reliability and reducing overall energy prices, the Commission proposes
that these costs be allocated to all loads of the RTO or ISO.
78. The Commission's proposal to eliminate deviation charges during
a system emergency applies to physical load reductions. With regard to
virtual
[[Page 12588]]
purchases, we believe that, during an emergency, these day-ahead
purchases may not cause unneeded generation to be committed to the
market because an emergency by its nature is a time when the system is
short of generation. As a result, we believe that virtual purchasers
may not cause significant additional costs during an emergency. Indeed,
virtual purchases may enhance reliability by increasing the amount of
generation resources available in real time during a system emergency.
Assessing a deviation charge on virtual purchasers during an emergency
may be unfair and may discourage helpful virtual bidding. Some
commenters contend that virtual purchases add to system costs but do
not address whether they add to costs during an emergency situation
when the system is short of generation. The Commission seeks comment on
whether to require RTO and ISO tariffs to be modified to eliminate
deviation charges for virtual purchasers during system emergencies.
79. We do not propose to modify RTO and ISO tariffs to eliminate
deviation charges absent a system emergency, in light of the comments
we received regarding this ANOPR proposal. We are concerned about the
resulting possibility of market manipulation and inefficiencies if
deviation charges are removed, as raised by several commenters. Given
the reliability value associated with demand response during system
emergencies, socialization of related uplift costs is supportable.
c. Aggregation of Retail Customers
i. Preliminary Proposals in the ANOPR
80. In the ANOPR the Commission sought comment on requiring RTOs
and ISOs to amend their market rules as necessary to permit an ARC to
bid demand response on behalf of retail customers directly into the
RTO's or ISO's organized markets. Under the preliminary proposal, the
amended market rules could not exclude a demand response bid from a
third-party ARC that is not an LSE, unless state laws or regulations do
not permit this. RTOs and ISOs would have the same rules for ARC
participation as for LSEs, except as needed to comply with state laws
and regulations, unless the RTO or ISO satisfactorily explained the
reason for any such difference. As part of the preliminary proposal,
the Commission suggested directing RTOs and ISOs to coordinate to
identify common issues, best practices, and market rules that are
consistent between regions, particularly in the areas of market
procedures, bidding protocols, communication protocols, and measurement
and verification, and having them report to the Commission on their
coordination efforts.
81. The Commission also requested comments on whether ARCs allow
for inappropriate compensation when a retail customer is paid for
wholesale demand response and also saves in its retail bill from the
same demand response. The Commission noted that some argue that the
payments to customers for demand response are a form of double payment
that provides an unjustified subsidy.
ii. Comments on the ANOPR Proposals and Questions
82. A large number of commenters address at great length the
proposal to require an RTO to accept a demand response bid into its
energy market from an ARC, if permitted by state law. A majority--
including such diverse entities as EPSA, CAISO, and Industrial
Consumers--appears to support the basic proposal although many raise
implementation concerns. Comments in opposition to the proposal also
vary widely and represent a diversity of interests, from SoCal Edison-
SDG&E to the Massachusetts Attorney General. They offer a variety of
reasons not to require market rule changes, with most concluding that
this topic is a subject better suited for detailed stakeholder
negotiations than a generic rulemaking. State regulators generally like
the state law exemption, but several worry that the program could have
unintended consequences and is inappropriate for non-retail access
states. Public power, cooperatives, and other retail service providers
not regulated by state commissions ask for clarification that an RTO or
ISO may not accept a bid from an ARC that aggregates their customers if
their own retail regulations would not permit this.\85\
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\85\ APPA at 56; NRECA at 13; EEI at 19; AEP at 4-5; California
Municipals at 8-9.
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83. Commenters identified multiple benefits associated with ARCs.
ARCs provide valuable services to retail customers by handling various
tasks such as developing demand response action plans, handling event
notifications from system operators, and managing payment.\86\ ARCs can
reduce the RTOs' and ISOs' administrative burden of managing individual
customers' demand response participation.\87\ ARCs with risk and
portfolio management expertise can manage a portfolio of diverse demand
response resources to achieve greater value and reliability with the
aggregated demand response resource.\88\
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\86\ See Public Interest Organizations at 10.
\87\ See EnerNOC at 6.
\88\ See, e.g., Energy Curtailment at 10-15; EnerNOC at 6;
Public Interest Organizations at 9-10.
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84. RTOs and ISOs indicate that standardization of several
technical issues may be beneficial. For example, PJM notes that a few
areas that can be standardized, including (1) the method for
determining baseline consumption, (2) the tools for establishing the
uniform baseline and measuring the demand response, (3) the interface
tools that allow demand response providers to use a common portal and
protocol for offering demand response into the organized markets, and
(4) the telemetry and metering requirements.\89\ Several commenters,
however, express concern that any rules for aggregation must be
tailored to the specific design of the particular market and regional
circumstances. They argue that these rules should not be developed in a
generic Commission rulemaking process. Instead, the Commission should
allow these rules to be developed by the RTO or ISO through a regional
stakeholder process.\90\
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\89\ PJM at 9-10.
\90\ E.g., NY TO at 8; LPPC at 5-6; Kansas CC at 2-4; SoCal
Edison-SDG&E at 3; Old Dominion at 9; Massachusetts AG at 2-3;
Northeast Utilities at 8.
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85. In response to ANOPR questions about how much to compensate a
demand response aggregator for reducing its consumption of electric
energy, voluminous comments were received ranging from strong arguments
for paying the full market price to strong arguments for avoiding
``double compensation.'' Many commenters oppose having a Commission
regulation setting a price to compensate for allegedly incorrect retail
prices. Several point out that if retail customers faced real-time
market prices, a retail aggregation program or any issue of
compensation would not be needed. The commenters that want to see a
transition to retail customers paying ``efficient'' market prices do
not want permanent Commission regulations that compensate for
``inefficient'' retail prices.
iii. Commission Proposal
86. The Commission proposes to require RTOs and ISOs to amend their
market rules as necessary to permit an ARC to bid demand response on
behalf of retail customers directly into the RTO's or ISO's organized
markets, unless the laws or regulations of the relevant electric retail
regulatory authority do not permit a retail customer to participate.
[[Page 12589]]
87. This proposal would reduce a barrier to demand response by
permitting an ARC to act as an intermediary for many small retail loads
that cannot individually participate in the organized market. We agree
with commenters that aggregating small retail customers into larger
pools of resources allows more customers to access demand response
programs, which increases the potential market and reliability benefits
realized from demand response in wholesale markets.\91\ Experience with
existing aggregation programs in PJM, NYISO, and ISO-NE has shown that
these programs increased demand responsiveness in these regions.
---------------------------------------------------------------------------
\91\ See, e.g., PJM at 8; EnerNOC at 5-7; Alcoa at 22; Public
Interest Organizations at 6-10.
---------------------------------------------------------------------------
88. In response to comments on the ANOPR's preliminary proposal, we
offer these clarifications of our proposal here. The ARC's demand
response bid must meet the same requirements as a demand response bid
from any other entity, such as an LSE. The bidder only has the
opportunity to be among the bids that clear the market; it does not
guarantee that the bid will clear the market and be selected. In
response to comments from public power entities, cooperatives, and
other such entities with retail customers that are sometimes not
subject to state public utility regulation, we clarify that, for the
purposes of the ARC part of this rule, the term ``relevant electric
retail regulatory authority'' means the entity that establishes the
retail electric prices and any retail competition policies for those
customers, such as the city council for a municipal utility or the
governing board of a cooperative utility.\92\ An ARC can bid demand
response either on behalf of only one retail customer or multiple
retail customers. Except for circumstances where the laws and
regulations of the relevant retail regulatory authority do not permit a
retail customer to participate, there is no prohibition on who may be
an ARC, and an individual customer may serve as an ARC on behalf of
itself and others. Finally, RTOs or ISOs may specify certain
requirements, such as registration with the RTO or ISO and
creditworthiness and other requirements, which qualify a resource
provider to make a bid and requests comments on whether there is any
reason not to subject ARC to the same requirements as any other bidder
in the energy market.
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\92\ We do not intend to require an RTO or ISO to accept a
demand response bid from an ARC that has aggregated the demand
responses of retail customers if this is not permitted by laws or
regulations of those regulatory entities covered by the term ``state
regulatory authority'' for those retail customers or if the retail
customers are served at retail by a ``nonregulated electric
utility,'' as these two terms are defined in sections 3(9) and 3(17)
of the Public Utility Regulatory Policies Act of 1978, 16 U.S.C.
2602(9), (17) (2000).
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89. As mentioned, we received voluminous comments on the issue of
compensation to a demand response aggregator, with comments on this
issue differing widely. A standard compensation approach may not be
feasible given the differences in market designs across the regions,
and we are persuaded that a rule that fixes a single pricing method in
regulations may not be appropriate. However, the appropriate valuation
of demand response in organized markets is addressed further below in
our proposal for pricing during a period of operating reserve shortage.
90. We agree with commenters who argue that each region's market
design is different and that it is important for the ARC provisions to
consider these regional differences. For this reason, we do not propose
to require detailed generic market rule amendments for ARCs. We propose
instead to require RTOs and ISOs to amend their tariffs and market
rules as necessary to allow an ARC to bid demand response directly into
the RTO's or ISO's organized market in accordance with the following
criteria:
[squ] The ARC's demand response bid must meet the same requirements
as a demand response bid from any other entity such as an LSE. For
example,
Its aggregate demand response must be as verifiable as
eligible LSE or large industrial customer demand response that are bid
directly into the market.
[squ] The requirements for measurement and verification of
aggregated demand response should be comparable to the requirements for
other providers of demand response resources, regarding such matters as
transparency, ability to be documented, and ensuring compliance.
[squ] Demand response bids from an ARC must not be treated
differently from the demand response bids of an LSE or a large
industrial customer.
The RTO or ISO may require the ARC to be an RTO member if
membership is a requirement for other bidders.
Single aggregated bids consisting of individual demand
response from a single area, reasonably defined, may be required by
RTOs and ISOs.
An RTO or ISO may place appropriate restrictions on demand
response participation by any customer to avoid counting the same
demand response resource more than once.
The market rules do not have to allow bids from an ARC
where this is not permitted under the laws or regulations of the
relevant electric retail regulatory authority. The RTO or ISO must
receive explicit notification from the relevant retail regulatory
authority in order to disqualify a bid from an ARC that includes the
demand response of that authority's retail customers.
91. We request comment about whether these criteria are appropriate
and whether there are additional appropriate criteria for allowing an
ARC to bid demand response.
92. An RTO or ISO must either propose amendments to its tariff to
comply with the proposed requirement or demonstrate that its existing
tariff and market design already satisfy the requirement to permit an
ARC to bid a demand response on behalf of retail customers.\93\ This
filing would be submitted within six months of the date the final rule
is published in the Federal Register. The Commission will assess
whether each filing satisfies the proposed requirement and will issue
additional orders as necessary.
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\93\ In particular, this proposal would not necessarily require
any change to an existing aggregation program that already functions
well if the existing program satisfies the proposed criteria. See
NEPOOL Participants at 12; TAPS at 19-21; Silicon Valley Power at 7-
8.
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93. We note, however, that cooperation and coordination among the
RTOs and ISOs in developing standard terms for demand response programs
would be beneficial. Accordingly, we encourage RTOs and ISOs to
coordinate their efforts through the ISO/RTO Council to identify common
issues, best practices, and market rules that are consistent between
regions (particularly in the areas of market procedures, bidding
protocols, communication protocols, and measurement and verification)
or act to develop common business practices and measurement and
verification protocols through the North American Energy Standards
Board (NAESB).
d. Potential Future Demand Response Reforms
94. The need for, and the focus on, demand response will continue
to increase. Although the Commission is proposing specific reforms to
eliminate barriers to demand response here, we believe that other
reforms may be necessary in the future. However, we do not wish to
delay the adoption of these specific reforms while the Commission and
industry continue to study and consider other advances in this area.
Rather, we believe that the reforms proposed here should proceed while
the
[[Page 12590]]
Commission and stakeholders study what additional efforts are needed
and develop a record to support further reforms.
95. In order to achieve this goal, we intend to direct staff to
hold a technical conference shortly after receiving the comments on
this NOPR to consider the following issues for demand response
participation in the wholesale markets: (1) If there are barriers to
comparable treatment of demand response that have not previously been
identified and what they are; (2) potential solutions to eliminate any
potential barriers to comparable treatment of demand response; (3)
appropriate compensation for demand response; and (4) the need for and
the ability to standardize terms, practices, rules and procedures
associated with demand response, among other things. The proposed
technical conference will provide a forum for RTOs/ISOs, demand
response providers, and other stakeholders to express their views
regarding these issues. It will also serve as guidance to the RTOs/ISOs
of the areas that they should include as part of the study we propose
to order as well as other issues identified in the course of the study.
We propose to require each RTO or ISO to assess and report on the
barriers to comparable treatment of demand response resources that are
within the Commission's jurisdiction, including those listed above, and
to submit its findings and any proposed solutions along with a timeline
for implementation to address barriers to the Commission within six
months of the Final Rule (RTO and ISO studies). To ensure that minority
views are adequately represented, we propose to require that the RTO or
ISO identify any significant minority views in its filing. We also will
require the Independent Market Monitor for each RTO or ISO to provide
its views on this issue to the Commission.
96. These RTO and ISO studies will have significant value. They
have the potential to provide independent critical analysis and a basis
for additional reform. In this regard, we note that section 529 of the
Energy Independence and Security Act of 2007 (EISA) requires the
Commission to complete a national assessment of demand response both to
estimate the potential for demand response and to determine how to
overcome the barriers to achieving that potential.\94\ We believe that
the RTO and ISO studies we are proposing to require will help us in
preparing the assessment and ultimately in developing a national action
plan on demand response as required by EISA. These studies will also
provide a sound platform and record for the Commission to consider
whether there should be additional reforms to remove barriers to demand
response in organized markets that ensure comparable and fair treatment
of demand response resources as required by the EISA.\95\ We seek
comment on the proposed approach to identify and assess remaining
barriers to comparable treatment of demand response as well as any
particular issues or areas that should be addressed in the RTO and ISO
reports.
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\94\ The Energy Independence and Security Act of 2007, Pub. L.
No. 110-140, 121 Stat. 1492 (2007).
\95\ 42 U.S.C. 8241 et seq. (2000), amended by EISA, Pub. L. No.
110-140, 529, 121 Stat. 1492 (2007).
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e. Market Rules Governing Price Formation During Periods of Operating
Reserve Shortage
i. Preliminary Proposals in the ANOPR
97. In the ANOPR, the Commission sought comment on modifying market
rules that limit the market-clearing price during an emergency, that
is, when the amount of available supply falls short of demand plus the
operating reserve requirement.\96\ When this happens, reliability is
threatened and market rules that limit the market price may have the
unintended effect of discouraging demand response. Limiting the price
also discourages existing generators needed mostly for emergencies from
continuing operation and discourages entry of new generation. The ANOPR
presented for comment four possible approaches to addressing this
problem.
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\96\ We note that in this section of the NOPR, we refer to this
emergency period as a period of operating reserve shortage.
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98. First, the Commission proposed requiring RTOs and ISOs to
increase the energy supply offer caps and demand bid caps above the
current levels during an emergency. This could also result in a market-
clearing price higher than the existing caps. Second, the Commission
proposed requiring RTOs and ISOs to allow only demand bid caps to be
raised above the current level, while keeping generation offer caps in
place. Such high demand bids would be allowed to set the market price
if they clear the market. As a third possible approach, the Commission
proposed requiring a demand curve for operating reserves in each RTO or
ISO market. Finally, as a fourth approach, the Commission proposed
requiring RTOs and ISOs to modify their market rules to set the market-
clearing price for all supply and demand response resources dispatched
during an emergency at the payment made to participants in an emergency
demand response program.\97\
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\97\ Based on comments on the ANOPR's preliminary proposals, we
note that there may be some confusion regarding the second and
fourth approaches. We clarify that a demand bid is different from a
demand response 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 its normal purchase by a
given amount in return for compensation.
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ii. Comments on the ANOPR Proposals and Questions
99. Many commenters advocate an RTO-by-RTO approach instead of a
rulemaking for addressing this issue.\98\ They call for the Commission
to identify the general features of a solution, allowing each RTO and
ISO and its regional stakeholders to develop the details. Others
request that the Commission act only in coordination with state
regulators because the ability of ultimate consumers to reduce demand
in an emergency depends on retail metering, pricing, and other
programs.
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\98\ E.g., Ameren at 31; CAISO at 19-20; EEI at 11; National
Grid at 10; NEPOOL Participants at 15-17; NYISO at 34-35; PJM MMU at
6-7; PG&E at 9.
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100. Many other commenters spoke for or against all four approaches
collectively. Those opposed to allowing buyers to see a higher price
during an emergency argue that the proposals are based on an incorrect
assumption that higher prices would reduce demand. They contend that
most of the buyers in an RTO's or ISO's market are LSEs with an
obligation to buy regardless of the price; thus, the ultimate consumers
(at retail) will not see the higher price or reduce demand.\99\ Some
opposing commenters argue that the proposals in varying degrees would
create new opportunities for generators to exercise market power.\100\
Further, they oppose some of the proposals because they would result in
an administratively determined price instead of a true market
price.\101\
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\99\ See, e.g., APPA at 59; Industrial Coalitions at 10-12; LPPC
at 7-8; OPSI at 38; PJM MMU at 7; Public Interest Organizations at
11; TAPS at 21.
\100\ See, e.g., Ameren at 29; Connecticut and Massachusetts
Municipals at 41-42; EEI at 25; Industrial Consumers at 22; PJM
Power Providers at 2-6; PPL Parties at 5-9.
\101\ See, e.g., EEI at 29; Reliant at 5; PJM Power Providers at
31.
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101. Those in support of allowing buyers to see a higher price
during an emergency argue that prices should be determined by an
unencumbered market where buyers and sellers are allowed to make bids
and offers with no restriction.\102\
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\102\ See, e.g., AEP at 5; The Alliance at 9; Constellation at
5-6; EPSA at 33; Reliant at 5-7; Strategic Energy at 9.
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[[Page 12591]]
102. In general, among those who favored one or more of the ANOPR's
four approaches, the first (raise all caps during an emergency) and
third (have a demand curve for operating reserves) approaches received
the strongest support. The second (raise only demand bid caps during an
emergency) and fourth (allow the payments for emergency demand response
to set the market-clearing price during an emergency) approaches had
the weakest support.
103. In comments on the first approach--lifting energy bid caps and
price caps above the current levels only during an emergency--
supporters say that this course of action allows buyers and sellers to
set a true market price for electricity during an emergency, reduces
demand by the appropriate amount, and allows investors in new
generation to assess the value to buyers of new generating resources.
This approach also has strong opposition, with particular concerns
about the potential for generators to exercise market power and the
inability of customers to respond to high prices.
104. The few commenters supporting the second approach--raising bid
caps above the current level only for demand bids--say that it
decreases generators' ability to manipulate the market compared to the
first option. They also make the general point that it is important to
let buyers express their true value for power. Those objecting to this
proposal raised many of the same concerns that were raised regarding
the first approach. For instance, they allege that even raising bid
caps only for demand bids would allow generators to physically withhold
some portion of their output from the market to obtain higher prices
for the remaining output. Commenters also argued that the proposal was
based on the false assumption that buyers that do not enter a bid to
purchase at a high price will not be served. These commenters maintain
that utilities shed load only as a last resort during an emergency, and
emergency curtailment programs dictate the allocation of power during a
shortage in a way that has nothing to do with the price bid into the
energy market.
105. Support for the third approach of establishing a demand curve
for operating reserves rests heavily on its track record, namely that
the Commission has approved these programs before and many regions have
experience with them.\103\ Arguments against this specific proposal are
largely objections to administratively determined demand curves where
prices may be set at levels that do not reflect competitive market
conditions.
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\103\ Duke Energy at 11; EPSA at 35; PJM MMU at 6-7; National
Grid at 10-11; NEPOOL Participants at 16; New England Power
Generators at 6-7; NYISO at 35; NY TO at 10.
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106. In commenting on the fourth approach--setting the market--
clearing price at the payment made to participants in an emergency
demand response program--a few commenters state that this approach is
preferable to allowing no higher price during an emergency at all and
could be supported as a transitional step in the process of removing
all bid and offer caps. Opposition to this approach is based on the
market price being administratively determined and a variety of other
reasons, for example, that it is inappropriate to set an energy price
based on a reliability payment.
iii. Commission Proposal
107. We have carefully considered the comments on this issue and
continue to believe that existing market rules appear to be unjust,
unreasonable and unduly discriminatory or preferential during times of
scarcity. In particular, they may not accurately reflect the true value
of energy and, by failing to do so, may harm reliability, inhibit
demand response, deter new entry of demand response and generation
resources and thwart innovation. However, we are cognizant of the fact
that this is a difficult issue and that any change in market rules must
consider the issue of market power, recognize regional differences in
market rules, and be based on a sound factual record. We first explain
the potential need for reform and then we describe our proposal to
address this issue.
108. In a competitive market, demand and supply respond to price.
If the price of energy is artificially capped during times of scarcity,
this will constitute a barrier to effectively attracting new generation
and demand resources into organized markets. When the system faces a
shortage of operating reserves, additional resources are needed for
operating reserves that help to maintain grid reliability. At such
times, market prices can elicit demand response from certain customers
who are equipped to respond and, thus, help balance the system. When
bid and offer caps are in place, however, it is not always possible to
elicit the optimal level of demand or generator response.
109. Some commenters argue that certain barriers to demand response
remain and that the Commission should not undertake any reform until
such barriers are removed. The Commission is taking several important,
concrete steps in this rulemaking to eliminate remaining barriers to
demand response that are indicated by the existing record to ensure
comparable and fair treatment of demand response resources. We
recognize, however, that some barriers may remain. That is why we are
requiring each RTO or ISO, as explained above, to undertake a further
study of this issue and report back to the Commission. However, even if
some barriers remain (certain of which may be subject to state
jurisdiction, not our jurisdiction), price remains an important factor
in encouraging demand response. Without prices that reflect the true
value of energy, we cannot expect the full integration of demand
response into organized markets. We therefore do not believe that
reforms in this area should be delayed until every barrier to demand
response, whether retail or wholesale, technological or regulatory, is
identified and addressed. We have, however, included as a primary
criterion for approving price reform during periods of operating
reserve shortage an adequate record demonstrating that provisions exist
for mitigating market power and deterring gaming behavior. These could
include, but are not limited to, use of demand resources to discipline
bidding behavior to competitive levels during periods of operating
reserve shortages.
110. We recognize that not all customers are at present equipped to
respond to scarcity pricing. Nevertheless, putting rules in place that
allow the fraction of the load currently able to respond can have a
very positive effect on the market and help reduce prices for all.\104\
Further, with the modifications that this proposal anticipates, more
buyers would find it worthwhile to invest in technologies that allow
them to respond to prices. This group could include not only large
manufacturers and others buying directly from the RTO or ISO market,
but also ARCs, and LSEs which can implement retail demand response
programs designed to reduce load during reserve shortages.
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\104\ See 2006 FERC Staff Demand Response Assessment at 7. As
reported in the 2006 FERC Staff Demand Response Assessment, as
little as five percent of load responding to price may discipline
market prices.
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111. The Commission's proposed reforms are also intended to
increase reliability. Our proposal is limited to periods of true
scarcity (i.e., when there is a shortage of operating reserves). We
have a duty to implement rules that ensure adequate supplies. If the
price of energy during these periods is
[[Page 12592]]
artificially constrained, demand cannot respond efficiently and
therefore the likelihood of involuntary curtailments is increased.
Thus, demand resources may be a low cost resource that can be used to
meet operating reserves requirements at the lowest total cost of
maintaining reliability. Furthermore, by artificially capping prices,
the price signals necessary to attract new entry by both generation and
demand resources are muted and long-term resource adequacy is harmed.
112. This is not merely a theoretical problem. In regions such as
PJM and New England, the Commission has found in prior orders that
existing energy and capacity markets did not encourage sufficient new
entry and that these regions therefore faced serious reliability
problems.\105\ The Commission adopted forward capacity markets in those
regions to avoid the threats to reliability and the real costs to our
economy of inadequate generation and demand resources. The reforms we
propose here can help to avoid these problems in other regions.
Moreover, as we explain below, in regions that already have such
capacity markets, the reforms proposed here can reduce the level of
revenues that must be recovered in such capacity markets.
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\105\ Devon Power, LLC, 115 FERC ] 61,340, order on reh'g, 117
FERC ] 61,133 (2006), appeal pending sub nom. Maine Pub. Utils.
Comm'n v. FERC, No. 06-1403 (DC Cir. 2007); PJM Interconnection,
LLC, 117 FERC ] 61,331 (2006).
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113. Some commenters appear to misunderstand our proposal and
suggest that we are proposing to lift the caps on generation in every
organized market. This is not correct. Only one of our proposals would
lift price caps on generators bidding energy into organized markets.
The other three would not do so, but rather would seek to better
reflect the value of energy during times of scarcity through other
means.
114. In regions that have already adopted forward capacity markets,
the lifting of such price caps on energy would primarily shift revenues
from capacity markets to energy markets. In New England and PJM, the
revenues collected by generators in the energy market are deducted from
the revenues that need to be recovered in the capacity markets.
Moreover, by shifting the price signals from capacity markets to energy
markets, the Commission is encouraging greater demand response, as
demand response may face fewer barriers to participating in energy
markets than forward capacity markets.
115. Finally, and most importantly, we are not proposing to change
the rules in each region without regard to the specific circumstances
facing that region. As we explain below, each region will be permitted
to demonstrate that its current rules do not need to be reformed
because they already adequately reflect the value of energy during
periods of scarcity.
116. Other commenters raise market power concerns. We agree that we
have a duty to guard the consumer against exploitation by sellers with
market power and we will fulfill that duty. As we explain below, we are
proposing that market power issues be adequately addressed before any
reforms in this area are adopted.
117. We now explain our proposal for reform in this area. We
propose to require each organized market to make a compliance filing,
within six months of a final rule in this proceeding, proposing any
necessary reforms to ensure that the market price for energy accurately
reflects the value of such energy during periods of scarcity (i.e., an
operating reserve shortage). Because there are regional differences in
market design, we will not mandate any one type of reform in this area.
Rather, each region may propose one of the four approaches described in
the ANOPR (and summarized further below) or it may propose a different
approach. Alternatively, a region may demonstrate that its existing
market rules already reflect the value of energy during periods of
scarcity and therefore do not need to be reformed.
118. In recognition of the concerns of many commenters, we also
propose to adopt further requirements to ensure that any reforms in
this area are supported by adequate factual support and show how they
are designed to protect consumers against the exercise of market power.
First, each RTO or ISO proposing to reform or demonstrate the adequacy
of its existing market rules in this area must provide an adequate
factual record for the Commission to evaluate its proposal.
Specifically, the RTO or ISO should provide historical evidence in its
region regarding the interaction of supply and demand during periods of
scarcity and the resulting effects on the market price for energy. To
the extent this evidence indicates that the region's market rules are
inadequate during these periods, the RTO or ISO must then explain and
support why its proposed reforms are tailored to address those
inadequacies. This factual record will allow the Commission to
discharge its duty to ensure that any reform is necessary and narrowly
tailored to address the circumstances in that region.
119. As a general matter, we will consider the factual record
compiled by the RTO or ISO to determine whether its proposal, or its
demonstration as to its existing market rules, would:
Improve reliability by reducing demand and increasing
generation during periods of operating reserve shortage;
Make it more worthwhile for customers to invest in demand
response technologies;
Encourage existing generation and demand resources needed
during an operating reserve shortage to remain in business;
Encourage entry of new generation and demand resources;
Provide comparable treatment and compensation to demand
resources during periods of operating reserve shortages; and
Have provisions for mitigating market power and deterring
gaming behavior, including, but not limited to, use of demand resources
to discipline bidding behavior to competitive levels during periods of
operating reserve shortages.
120. We request comment on whether these criteria are appropriate
and whether there are additional criteria that we should consider in
evaluating a proposal for pricing during a period of operating reserve
shortage by RTOs and ISOs.
121. Second, the Commission will require any RTO proposing reform
in this area to address the adequacy of any mitigation measures that
would be in place during periods of operating reserve shortage. We
recognize that many commenters have raised market power concerns and we
take those concerns seriously. However, we note that enhanced demand
responsiveness and increased entry by generators can help to mitigate
seller market power by lowering market prices.\106\ Moreover, we note
that generator bid and offer caps are not increased in three of the
four options proposed.\107\ These caps provide further protection
against the exercise of seller market power. Further, the Commission
notes that other market power mitigation measures remain in
[[Page 12593]]
place during times when operating reserves are insufficient. For
example, conduct and impact tests are applied in ISO-NE, NYISO, and
Midwest ISO. A pivotal supplier test is used in PJM. PJM and CAISO
mitigate bids by generators chosen out of merit order. Moreover, the
Commission intends to closely monitor market behavior during periods of
operating reserve shortage to ensure that market participants are
following market rules and to guard against the exercise of market
power.
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\106\ See B.F. Neenan et al., Neenan Associates, 2004 NYISO
Demand Response Program Evaluation, at E-5, (Feb. 2005); David B.
Patton, Potomac Economics, 2006 State of the Market Report--The
Midwest ISO, at 44 (May 2007).
\107\ In the first approach, bid and offer caps would increase
for both sellers and buyers. In the second approach, bid and offer
caps for buyers would be increased, but bid and offer caps for
sellers would remain in place. In the third approach, based on a
demand curve for operating reserves, bid and offer caps would remain
in place for both sellers and buyers. In the fourth approach (which
proposes that payments to participants in an emergency demand
response program could set the market-clearing price), bid and offer
caps would again remain in place for both sellers and buyers.
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122. In addition, to ensure that we have an adequate record on the
issue of market power mitigation, we propose to solicit the views of
the Independent Market Monitor for each RTO or ISO region on any
proposed reforms in this area.
123. We now briefly summarize the four approaches discussed in the
ANOPR and referred to above. As noted, however, these are not the only
approaches that may be considered. Under the first approach, RTOs and
ISOs would increase the energy supply offer caps and demand bid caps
above the current levels only during an emergency. For example, if
operating reserves drop below levels required in mandatory reliability
standards, then bid caps would be allowed to rise above existing caps.
As we described above, increasing energy supply offer and demand bid
caps would allow the market to clear at a price above the current (or
non-emergency) cap.\108\ Customers and LSEs could then decide whether
to purchase energy at the 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. Thus, this proposal would allow
supply and demand to operate more efficiently to allocate limited
supply to those who value it the most.
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\108\ Under this proposal, the price and bid caps would be
removed in the real-time market during an operating reserve
shortage, but not necessarily in the day-ahead market. Thus, the
price and bid caps would be removed normally for only a fraction of
the spot market. In a severe shortage when the system operator is
aware that the day-ahead market will produce insufficient generation
for day-ahead energy and operating reserves, the price and bid caps
would also be removed for the day-ahead market.
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124. Under the second approach, RTOs and ISOs would increase bid
caps above the current level only for demand bids (i.e., the buyers'
offers to purchase a certain amount of energy at a given price) 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. These demand bids would be
allowed to set the market price if they clear the market. As with the
other approaches, the higher market price under this approach would
create an incentive for all buyers to lower their demands during an
emergency. Demand that is price-sensitive would be reduced until
available supply can meet the demand plus the need for operating
reserves. This proposal does not change any rules that govern how
demand response resources operate in the market.\109\
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\109\ We clarify that this approach refers to demand, not demand
response. That is, this proposal allows a buyer to submit a bid to
purchase energy at a price that exceeds the current bid cap. This
proposal in no way affects demand response resources that
participate in a program where they are paid some amount of money to
reduce their consumption.
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125. The third approach is for an RTO or ISO to establish a demand
curve for operating reserves. The RTO or ISO would establish market
rules that set real-time prices at specific pre-determined values
(typically above the market-wide offer and bid caps) during an
operating reserve shortage. The price level would increase with the
severity of the shortage. This approach will ensure that market prices
reflect tight conditions on the grid without altering any of the market
power mitigation restrictions on either supply offers or demand bids.
The Commission has already approved this option in the NYISO and ISO-NE
markets.\110\ These existing programs for pricing during reserve
shortages have been implemented and activated during periods of
operating reserve shortage in these regions. Moreover, the exposure to
higher prices would increase the incentive for load to engage in
hedging activities, and higher prices during shortages should attract
new generation. As long as the prices that are implemented during
reserve shortages are based on costs relevant to the market (such as
the cost of new peak generation entry), and the particular
characteristics of RTO and ISO regions, demand curves for operating
reserves should induce sufficient supply and demand responses. A
properly designed demand curve for operating reserves should also
alleviate concerns about administratively determined prices. As noted
above, the demand curve is a reflection of the costs of entering the
energy market and indicates the prices suppliers would expect to be
paid to provide that energy to the market. Thus, while the demand curve
is administratively determined, it is based on market conditions.
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\110\ The Commission approved market rules for NYISO and ISO-NE
that include a demand curve for operating reserves that sets the
real-time market price when operating reserves are low. New York
Indep. Sys. Operator, Inc., 106 FERC ] 61,111 (2004); New England
Power Pool and ISO New England Inc., 115 FERC ] 61,175 (2006). See
David B. Patton & Pallas LeeVanSchaik, 2006 Assessment of the
Electricity Markets in New England (June 2007); David B. Patton &
Pallas LeeVanSchaik, 2006 State of the Market Report New York ISO
(July 2007).
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126. Under the fourth approach, an RTO or ISO would amend its
market rules to set the market-clearing price for all supply and demand
response resources dispatched equal to the payment made to participants
in an emergency demand response program.\111\ Since the emergency
demand response programs are only called during an emergency when
demand needs to be reduced quickly, they should be the marginal
resource and set the market-clearing price. Without such a rule, demand
response payments are made to those demand response resources that
respond to the RTO's or ISO's call to reduce load, yet prices are still
set by the generation resource with the highest running costs (or at
the price cap). This proposal would set the market-clearing price by
the actual marginal reliability resource, the demand response resource.
For example, if participants in emergency demand response programs were
paid $500/MWh to reduce their consumption when directed, then the $500/
MWh payment would set the market-clearing price in the zones where the
program was active.
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\111\ 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.
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127. This rulemaking approach to demand response is directed at all
RTOs and ISOs to ensure that all meet certain basic demand response
goals. However, we do not intend to alter current RTO and ISO shortage
pricing programs if the compliance filings satisfy us that the current
programs meet the intent of this requirement. Some RTOs and ISOs have
already dedicated considerable resources to develop various shortage-
pricing programs. These programs have been developed through
established stakeholder processes in the RTOs and ISOs and have been
approved by the Commission and determined to be just and reasonable.
Thus, the requirement proposed here may be satisfied by a filing
demonstrating that the RTO or ISO already has a Commission-approved
approach for pricing during periods of operating reserve shortage that
meets the requirements previously discussed (i.e., in P 117, 118 and
120).
128. Each RTO or ISO may also consider a ``phase-in'' of its
specific
[[Page 12594]]
emergency pricing method, over a period of years (e.g., three years).
This phase-in period can gradually introduce customers to price
increases during an emergency and allow them to develop ways to reduce
demand during an emergency to avoid high prices. We note that the
phase-in may be linked to key factors such as the deployment of the
advanced metering needed to implement their proposed method, provided
the phase-in period is not protracted. However, the full deployment of
advanced metering is not a requirement for the implementation of
emergency pricing as price and demand responsiveness can be achieved
without such a prerequisite.
B. Long-Term Power Contracting in Organized Markets
129. In the ANOPR, the Commission offered for comment three
proposals intended to facilitate long-term contracting in organized
markets, along with questions about whether to modify Electric
Quarterly Reports (EQR) data requirements to facilitate long-term
contracting. Following review of the comments, the Commission proposes
to require that ISOs and RTOs dedicate a portion of their Web sites for
market participants to post offers to buy or sell electric energy on a
long-term basis. The Commission will consider reasonable additional
steps in response to comments on this NOPR, and continues to encourage
ISOs and RTOs to work within their authorities with stakeholders to
facilitate long-term power contracting.
1. Background
130. Long-term power contracts are an important element in a
functioning electric power market. Forward power contracting allows
buyers and sellers to hedge against the risk that prices may fluctuate
in the future. Both buyers and sellers should be able to create
portfolios of short, intermediate, and long-term power supplies to
manage risk and meet customer demand. Long-term contracts also improve
price stability, mitigate the risk of the abuse of market power, and
provide a platform for investment in new generation and transmission.
131. As the Commission noted in the ANOPR, an organized market
region naturally should facilitate long-term contracting by eliminating
pancaked rates for long distance power sales, eliminating loop flow
problems within its footprint, and ensuring reliable transmission
operation over a large area. RTO and ISO transmission services also
expand the size of the markets available to buyers and sellers of long-
term power contracts, and provide independent and unified transmission
scheduling and operation services over a large area.
132. While most of the comments submitted in response to the ANOPR
and testimony from parties at the Commission's technical conference on
May 8, 2007 agree as to the importance of long-term contracts, opinions
vary as to the extent of a problem with long-term contracts in the
market and its causes. Many customers argue that issues of market
design and over-reliance on the spot market have driven up prices,
making long-term contracting difficult. On the other hand, many power
sellers believe that markets are operating well, but parties are unable
to reach long-term contracts due to differing price expectations and
differing assessments of long-term risk.
133. The Commission has already taken action in other areas to
facilitate long-term contracting. In Order No. 681, the Commission
adopted a Final Rule on long-term transmission rights for organized
market regions designed to assure availability of long-term
transmission at a predictable cost.\112\ The Commission then adopted
transmission planning reforms in Order No. 890 to provide an open and
transparent process for wholesale entities and transmission providers
to plan for the long-term needs of their customers. Interconnection
rules for large, small and wind generators in Order Nos. 2003, 2006 and
661 have improved the interconnection process and provide for
interconnection with network integration service to facilitate long-
term reliance on new generation.\113\ The Commission has also reformed
capacity markets in several regions to shift reliance from short-term
purchases to forward markets held sufficiently in advance of delivery
(e.g., three years) to be more consistent with the time necessary to
construct new generation.\114\
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\112\ Long-Term Firm Transmission Rights in Organized
Electricity Markets, Order No. 681, FERC Stats. & Regs. ] 31,226
(2006), order on reh'g, Order No. 681-A, 117 FERC ] 61,201 (2006).
\113\ Standardization of Generator Interconnection Agreements
and Procedures, Order No. 2003, FERC Stats. & Regs. ] 31,146 (2003),
order on reh'g, Order No. 2003-A, FERC Stats. & Regs. ] 31,160,
order on reh'g, Order No. 2003-B, FERC Stats. & Regs. ] 31,171
(2004), order on reh'g, Order No. 2003-C, FERC Stats. & Regs. ]
31,190 (2005), aff'd sub nom. Nat'l Ass'n of Regulatory Util.
Comm'rs v. FERC, 475 F.3d 1277 (DC Cir. 2007); Standardization of
Small Generator Interconnection Agreements and Procedures, Order No.
2006, FERC Stats. & Regs. ] 31,180, order on reh'g, Order No. 2006-
A, FERC Stats. & Regs. ] 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 Docket No. 06-1018, et al; Interconnection for
Wind Energy, Order No. 661, FERC Stats. & Regs. ] 31,186, order on
reh'g, Order No. 661-A, FERC Stats. & Regs. ] 31,198 (2005).
\114\ Devon Power, LLC, 115 FERC ] 61,340, order on reh'g, 117
FERC ] 61,133 (2006), appeal pending sub nom. Maine Pub. Utils.
Comm'n v. FERC, No. 06-1403 (DC Cir. 2007); PJM Interconnection,
LLC, 117 FERC ] 61,331 (2006).
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2. The Need for Commission Action
134. As noted above, long-term power contracts are an important
element of a working market. They enable buyers and sellers to manage
risks, they promote stability in pricing, and they provide a solid
foundation for the financing of new generation. Despite this
importance, both buyers and sellers perceive that it is increasingly
difficult to enter into long-term contracts, and that fewer long-term
contracts are being signed as a result.
135. The Commission believes that further transparency in long-term
electric energy markets would facilitate efforts by both sellers and
buyers to incorporate long-term contracts as an essential part of their
energy portfolios. This is especially true for new market participants
that may not be aware of the full range of contract options available
to them, including the full range of potential contract counterparties.
During the panel on long-term contracting at the second Commission
competition conference, a representative from PJM stated that he had
spoken to what he termed ``smaller players'' who indicated that they
were willing to contract for power but were unaware of who the
available counterparties were.\115\ These ``smaller players'' said that
they would be interested in a bulletin board on the PJM Web site that
would facilitate networking.\116\
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\115\ Transcript of Conference at 187, Conference on Competition
in Wholesale Power Markets, Docket No. AD07-7-000 (May 8, 2007).
\116\ Id.
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136. While the market has the most important role to play in
disseminating information, an RTO or ISO can play an important role in
promoting greater transparency and liquidity in long-term power
markets, and thus help reduce possible over-reliance on its spot
markets. The information systems it operates are well suited for making
such information available to the parties in its region.\117\ As
discussed below, several commenters support having RTOs and ISOs
provide a section of their Web sites for a long-term contract bulletin
board, which they believe would be a useful tool in assisting parties
in finding interested
[[Page 12595]]
counterparties and facilitating long-term contracts.
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\117\ See id. at 117.
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137. In light of these comments and our own observation, the
Commission will take action in this area. We do so because of the
importance of long-term contracts to a working market and because we
believe greater transparency in the market will facilitate such long-
term contracts. We therefore propose that regional organizations play a
supporting role in encouraging voluntary contracting by providing an
online forum in which potential buyers and sellers may exchange
information.
3. Preliminary Proposals in the ANOPR
138. Given the importance of long-term contracts, in the ANOPR the
Commission requested comment on any concrete steps it could take to
facilitate voluntary long-term power contracting in organized market
regions.\118\ Specifically, the Commission solicited comment on whether
it should encourage greater market transparency by requiring RTOs and
ISOs to post information that could facilitate long-term contracts,
such as aggregate information on long-term contract prices and
quantities, and if so, how the information could be reported so that it
protects the confidentiality of individual contracts. The Commission
also asked whether disseminating other information, such as estimates
of transmission constraints and long-term congestion costs, would be
helpful to long-term contracting.
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\118\ The Commission noted, however, that it was mindful of the
limits of its jurisdiction in seeking comment on this issue, as the
Commission cannot compel buyers and sellers to enter into long-term
contracts. The Commission also noted that the purchasing practices
of LSEs are often dictated by state policies, not those of this
Commission.
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139. The Commission also solicited comment on whether it should
require or encourage efforts to develop new standardized forward
products and whether standardized products would facilitate long-term
contracting. The Commission inquired about what role it should play,
whether the Commission should encourage RTOs or ISOs to play an active
role in this area (or whether that would place them in a position of
undertaking commercial functions), and whether this was a role better
played by NAESB or other industry groups.
140. Third, the Commission asked whether it should require ISOs and
RTOs to dedicate a portion of their Web sites for market participants
to post offers to buy or sell power long-term. The Commission asked
whether this proposal would prove helpful, or whether it was a service
that would be better provided by the market.
141. Finally, the Commission requested comments on whether it
should consider any modification of the data requirements of the 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.
4. Comments on the ANOPR Proposals and Questions
142. Commenters filed extensive comments agreeing with the
Commission on the importance of long-term contracts in a functioning
market. They differ, however, on the nature and extent of the problems
with long-term contracting, what measures would best address the
problems, and whether the Commission should attempt to deal with the
various problems by requiring RTO or ISO actions.
143. Most commenters recommend against most of the actions proposed
by the Commission in the ANOPR, which address the problems through
regulations applicable to RTOs or ISOs. Some of these commenters argue
that market participants and the private sector should address concerns
over long-term contracting opportunities, while others argue that the
Commission can improve long-term contracting opportunities by
addressing larger structural issues, identified below.
144. The preliminary proposal to require RTOs and ISOs to reserve a
section of their Web sites for parties to post offers to buy or sell
power under long-term contracts has the most support, although most
commenters do not necessarily support making this a regulatory
requirement. A minority of commenters support this proposal--some
strongly--including several RTOs and ISOs, state regulators, wholesale
sellers, many small wholesale buyers, and Joint Consumer Advocates.
Commenters indicate that such a Web site would be useful for many
market participants, particularly new market participants, and would
help facilitate long-term contracting. Midwest ISO and PJM indicate
that they have already begun working on posting such discussion boards
on their Web sites, and other RTOs and ISOs such as SPP indicate
support for providing space on their Web sites to post such offers.
145. Commenters opposed to this proposal indicate that the market
already adequately performs this function, and that the RTOs and ISOs
should be able to determine on their own whether to have a Web site
section for bulletin board postings. EEI and Duke Energy note that PJM
once had a bulletin board for similar purposes that fell into disuse,
likely due to a lack of interest from market participants. Many
commenters, such as EPSA, argue that RTOs and ISOs should be allowed to
determine, in consultation with stakeholders, what to post on their Web
sites. Some commenters state that legal issues may arise from having
RTOs or ISOs post information, including concerns over confidentiality
and potential liability for the posting of incorrect information, and
that these issues should be addressed before any action is taken. The
New England Conference said that it supports a regional, voluntary
solution, where regional working groups would be created to discuss
measures to increase information sharing.
146. Commenters offer little support for the ANOPR proposal to
require RTOs and ISOs to develop new standardized forward products.
Those few commenters supporting the proposal believe that new products
would assist customers in developing long-term contracts. Some
commenters, such as the New York PSC and NRG, offer qualified support
for the concept of improved forward products, but state that the
Commission should encourage RTO or ISO participation in developing such
products rather than require their development by the RTOs and ISOs
themselves.
147. A large majority of commenters oppose this proposed
requirement. They say that the market already supplies standardized
products, and that it is better equipped to do so than RTOs or ISOs.
EEI notes that it already has a process for developing standardized
products that involves working with market participants to adjust to
changes in the market. Many commenters also note that long-term
contracts vary considerably from transaction to transaction, making
standardized products difficult to develop unless they are quite
general and so less useful than they are for short-term transactions.
Finally, some commenters note that this proposed requirement would be
an undue burden to ISOs and RTOs.
148. Most commenters argue strongly against adopting the ANOPR's
preliminary proposal to require ISOs and RTOs to post information on
long-term contract prices and quantities. They argue that this proposed
requirement is unnecessary, is possibly counterproductive, and would
create additional expense for the ISO or RTO. A few, such as BlueStar
and DC Energy, support the proposal, arguing that it would increase
transparency in the market, which would lead to greater liquidity and
increased long-term
[[Page 12596]]
contracting. Some ISOs and RTOs also indicate that they would be
willing to post information if directed to do so, but that
confidentiality concerns would need to be addressed. Many commenters
think that the requirement would not be useful because of the wide
variation in long-term contract provisions and the time lag between
contracting and posting of the information.\119\ Others, such as the
OMS, argue that the data collection requirement would unduly burden
RTOs and ISOs. The burden would be unnecessary, according to PG&E,
PSEG, Allegheny, Ameren and others, because the market and trade press
already provide sufficient data. Finally, many commenters point to a
concern over the confidentiality of data and the possibility that
posted data could be used to game the market.
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\119\ See Pepco at 13; New England Power Generators at 8; Dynegy
at 3.
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149. Only a few commenters address the Commission's request for
comments on whether we should consider modifications to the information
collected on long-term contracts in the EQR. These commenters are
generally opposed to having the Commission modify the EQR data
reporting requirements. Although SUEZ Energy supports increased
reporting requirements, arguing that it would create increased
transparency for providers of retail service, most commenters believe
that the information in the EQR is already sufficient and that any new
information requirements could have negative effects on confidentiality
or markets. For instance, Old Dominion notes that modifying EQR data
could reveal competitive information and result in reduced forward
liquidity for physical transactions.
150. The Commission also requested comments on additional steps
that it could take to promote long-term contracting opportunities. Many
commenters point to the importance of contract certainty, long-term
stability of market rules and regulatory policies, and proper market
design in supporting long-term contracting, although comments vary on
how best to provide for these elements. For instance, Old Dominion
argues that the Commission should reaffirm its commitment to
incremental changes to market design to prevent instability. PSEG notes
that the Commission should resist changing tariffs and should not
revise contracts under FPA section 206, where either the buyer or
seller has miscalculated risks.
151. A majority of commenters indicate that structural impediments
to long-term contracting prevent market participants from fully
utilizing long-term contracts as part of their energy portfolios.
Impediments cited include differences between buyers and sellers in
assessing the appropriate long-term price and assessing long-term
risks, over-reliance on spot markets, market design, and regulatory
uncertainty. Many commenters, such as FirstEnergy, point to buyers' and
sellers' inability to agree on a long-term price as the real problem
with long-term contracts. Some commenters suggest that the Commission
should review over-reliance on the spot markets, which, they assert,
affects forward prices and creates a disincentive for parties to engage
in long-term deals.
152. Commenters also propose a variety of more fundamental
approaches for the Commission to consider for dealing with long-term
contracting. Some commenters argue that the Commission should take a
more sweeping look at the markets as a whole, noting that problems with
long-term contracting are merely a symptom of market inefficiency.
These include a request for an investigation of RTO markets and
mandating long-term contracting through dedicating portions of
transmission lines for long-term arrangements or requiring entities to
have a percentage of their portfolios as long-term contracts.
153. Two commenters, American Forest and Portland Cement
Association, et al., include fairly detailed proposals to address
problems with the incentives for long-term contracting. American
Forest's proposal, the Financial Performance Obligation (FPO), appears
to require every generating unit that receives a capacity payment to
financially guarantee the delivery of energy to the real-time market at
or below a specified strike price in any hour in which it is dispatched
by the RTO to provide service. American Forest maintains that the FPO
would connect capacity and energy markets and would provide a hedge to
load by shifting short-term risk of market volatility in energy markets
to suppliers. It argues that the linked real-time market clearing price
and capacity price that would result from the FPO would provide an
incentive for suppliers to take steps, such as long-term contracting,
to hedge short-term volatility, and prevent suppliers from double
recovering revenues from capacity and energy payments. Portland Cement
Association, et al.'s proposal offers an alternative market design
framework, Forward Capacity and Energy Market, suggesting that a
combination of competitive and administrative procedures could be used
to obtain the lowest-cost combination of fixed and variable costs while
preserving the locational economic signals of Locational Marginal
Pricing. It argues that the proposed framework also would establish
economic incentives for both buyers (e.g., LSEs and large customers)
and suppliers to negotiate long-term bilateral contracts.
154. A significant number of commenters state that the Commission
should take no action on the long-term contracting topic, but should
instead leave any long-term contracting solution to the market.
5. Proposed Reforms
155. The Commission proposes to require ISOs and RTOs to dedicate a
portion of their Web sites for market participants to post offers to
buy or sell power on a long-term basis. We are not proposing here the
other potential actions considered in the ANOPR and are not proposing
to address in this docket the other long-term contracting issues raised
by some commenters.
156. The proposal for an RTO/ISO Web site ``bulletin board'' for
posting long-term offers to sell or buy is designed to facilitate the
long-term contracting process by increasing the transparency of
available sellers and buyers for market participants. Providing a place
for buyers and sellers to offer long-term power transaction
opportunities should alleviate concerns about sellers and buyers being
unable to find one another and should encourage more long-term
contracting and improve efficiency in the market at little cost.
Improving information flow can only increase liquidity among buyers and
sellers. The Commission believes that this requirement will not be
burdensome for ISOs and RTOs to implement.
157. The Commission does not propose to mandate the specific type
of bulletin board that each ISO and RTO must post, but will require
each to work with its stakeholders in designing a solution that works
for its market participants. We have in mind, however, an RTO/ISO
bulletin board that would allow persons to post offers to sell or buy
without making the RTO or ISO responsible for the content of the
offers. We are encouraged that some ISOs and RTOs have already
undertaken this effort.
158. The Commission proposes to require ISOs and RTOs to make a
compliance filing within six months of the date of publication of the
final rule in the Federal Register. This filing should explain the
actions the ISO or RTO has taken to comply with the long-
[[Page 12597]]
term contracts bulletin board requirement and provide information on
the bulletin board the ISO or RTO has chosen to implement.
159. The Commission seeks public comment on its proposal not to set
by rule the specific type of bulletin board that each ISO and RTO must
post. This includes comment on whether any features are important
enough to specify generically, such as the structure for the webpage,
the extent to which the ISO or RTO must seek feedback on its web
design, or whether the ISO or RTO or the market participant must post
the information. Further, we seek comment on our assumption that the
costs involved with implementing the proposal are minimal and should be
recovered in the same manner as other Web site costs. In addition, the
Commission solicits comment on the proposal that the RTO or ISO should
not be responsible for the content of the offers on its bulletin board.
Is a Web site that includes a clear disclaimer adequate to protect RTOs
and ISOs from liability, or should the Commission take additional
action? Do market participants that post offers but fail to reach
agreement with counterparties on contract terms and conditions have any
liability issues?
160. As we noted earlier, PJM recently has conducted a series of
forums on long-term contracts to gather information and facilitate the
exchange of ideas.\120\ We encourage similar efforts by other RTOs or
ISOs, and the ISO/RTO Council. We encourage RTOs and ISOs already
working on solutions to these issues to take appropriate steps to
ensure timely implementation of reasonable solutions as soon as they
are ready. The Commission also directs Commission staff to perform an
analysis of the level of long-term contracting in organized market
regions.
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\120\ More information on the PJM forums is available at http://www.pjm.com/committees/stakeholders/drs/ltc.html.
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161. In addition, while we appreciate the proposals of American
Forest and Portland Cement Association, et al. to resolve disincentives
to conduct long-term contracting, we have concerns that various aspects
of the proposals, such as the impact of the proposal on capacity
markets, would require additional development, review and consideration
before it would be ripe for inclusion in a rulemaking. The shift of
revenues from the spot market to some form of forward obligation or
hedging option that could occur with the FPO may well have advantages,
but this shift may create new concerns among LSEs and others about
capacity market operations and price levels. To help develop a greater
level of understanding of the proposals we direct staff to conduct a
technical conference in a separate proceeding to examine the FPO and
Portland Cement Association, et al.'s alternative market designs and
related issues.
C. Market-Monitoring Policies
162. This section of the NOPR proposes regulations implementing
market monitoring policies.
1. Background
163. 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
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.\121\
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\121\ Regional Transmission Organizations, Order No. 2000, FERC
Stats. & Regs. ] 31,089 at 31,155 (1999), order on reh'g, Order No.
2000-A, FERC Stats. & Regs. ] 31,092, at 30,993 (2000), aff'd sub
nom. Pub. Util. Dist. No. 1 of Snohomish County, Washington v. FERC,
272 F.3d 607 (DC Cir. 2001).
---------------------------------------------------------------------------
164. The span of years over which market monitors have now 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. In this NOPR, we propose reforms for MMUs designed to
improve their abilities to monitor and report on the operation of
organized wholesale electric markets.
2. Prior Commission Actions Regarding Market Monitoring
165. The Commission undertook its first generic consideration of
market monitoring in Order No. 2000, which required an RTO to include
market monitoring as one of its minimum functions and to submit a
market monitoring plan as part of its RTO proposal.\122\ The Order did
not, however, impose a specific MMU structure on the RTOs. 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.\123\ The Commission ordered RTOs to incorporate in
their market monitoring plans certain standards to be met by the MMUs,
which included 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.\124\ 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.\125\
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\122\ Prior to this first generic consideration of market
monitoring, 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).
\123\ Order No. 2000, FERC Stats. & Regs. ] 31,089 at 31,156.
\124\ Id.
\125\ Id.
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166. The Commission next addressed the role of market monitors in
its 2003 Order Amending Market-Based Rate Tariffs and
Authorizations.\126\ The Commission clarified the duties of MMUs in
connection with enforcement matters, directing that MMUs refer
compliance issues to the Commission \127\ and limiting direct
enforcement action by the MMUs to objectively identifiable and
sanctioned behavior expressly set forth in the RTO/ISO tariffs.\128\ In
its subsequent Order on Rehearing, the Commission clarified that MMU
personnel were not a substitute for Commission enforcement staff.\129\
Instead, MMUs were to provide information to the Commission and its
staff, so that the Commission could take appropriate action under the
FPA.
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\126\ Investigation of Terms and Conditions of Public Utility
Market-Based Rate Authorizations, 105 FERC ] 61,218 (2003) (Market
Behavior Rules Order), order on reh'g, 107 FERC ] 61,175 (2004)
(Market Behavior Rules Rehearing Order).
\127\ Market Behavior Rules Order, 105 FERC ] 61,218 at P 184.
\128\ Id. P 182.
\129\ Market Behavior Rules Rehearing Order, 107 FERC ] 61,175
at P 165.
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167. In May of 2005, the Commission issued a Policy Statement on
Market Monitoring Units,\130\ identifying four tasks which MMUs perform
for which they need access to data and other
[[Page 12598]]
resources.\131\ 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.\132\
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\130\ Market Monitoring Units in Regional Transmission
Organizations and Independent System Operators, 111 FERC ] 61,267
(2005) (Policy Statement).
\131\ Id. P 2-3. These functions were: (1) 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; (2) to review
and report on the performance of wholesale markets in achieving
customer benefits; (3) 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; and (4) 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.
\132\ Id. at Appendix A. The Market Behavior Rules extant at the
time of the Policy Statement have since been in part rescinded, with
the remainder codified. See Conditions for Public Utility Market-
Based Rate Authorization Holders, Order No. 674, FERC Stats. & Regs.
] 31,208 (2006) (Order No. 674). Rescinded Market Behavior Rule 2
has been replaced by the Commission's Anti-Manipulation Rules. See
Prohibition of Energy Market Manipulation, Order No. 670, FERC
Stats. & Regs. ] 31,202 (Order No. 670), order denying reh'g, 114
FERC ] 61,300 (2006).
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168. In 2006, PJM Interconnection, LLC (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.\133\
Several parties filed comments, arguing 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 Commission's Order on Rehearing and Compliance Filing,
we noted that these concerns were of a generic nature and not
necessarily limited to PJM.\134\
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\133\ PJM Interconnection, LLC, 116 FERC ] 61,038 (2006) (PJM
Tariff Order).
\134\ PJM Interconnection, LLC, 117 FERC ] 61,263, at P 19
(2006) (PJM Tariff Rehearing Order).
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3. The Need for Commission Action
169. The concerns raised by intervenors in the PJM case impressed
upon the Commission the need to undertake a generic examination of
MMUs, to see if their roles could be enhanced so as to improve the
efficiency and transparency of organized wholesale electric markets. To
that end, the Commission announced that we would hold a technical
conference to explore the issues raised by the commenters.\135\
---------------------------------------------------------------------------
\135\ Id. P 20.
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170. The Commission held the technical conference on market
monitoring policies on April 5, 2007. At the conference, the
Commissioners heard from interested commenters on several general
subjects.\136\ 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. These issues are in accord with our own observations of areas
within the market monitoring function that need reform. For that
reason, we have included proposals in this NOPR designed to strengthen
market monitoring and thereby enhance the performance and transparency
of organized RTO/ISO markets.
---------------------------------------------------------------------------
\136\ These subjects included: 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. See
Second Notice of Technical Conference, Review of Market Monitoring
Policies, Docket No. AD07-8-000 (March 9, 2007).
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4. Proposed Reforms
171. The Commission advanced proposals in the ANOPR that responded
to the concerns expressed by commenters at the technical conference and
that reflected the Commission's own observations formed from working
within the framework of the existing market monitoring provisions.
These proposals were designed to strengthen market monitoring by
safeguarding MMU independence and fostering useful and transparent
market analysis. The Commission sought comment on the proposals, which
fell within the two general areas of (i) independence and function and
(ii) information sharing. In this NOPR, the Commission analyzes the
comments received and presents revised proposals.
a. Independence and Function
172. In the ANOPR, the Commission acknowledged the importance of
independence on the part of MMUs, and stated that there are several
means by which to balance independence and accountability. The
Commission proposed a balanced and flexible approach to the problem
which included oversight protection, tariff safeguards and tools, the
elimination of conflicts of interest, and certain changes in the
functions MMUs are expected to perform. The Commission solicited
comments on the proposed changes.
i. Structure and Tools
(a) Preliminary Proposals in the ANOPR
173. The Commission declined in the ANOPR to propose a ``one size
fits all'' approach to the structure of MMUs, noting that there was no
appreciable difference among the performance of the market monitors
that could be attributed to whether they were external (an independent
contractor who is hired by the RTO or ISO) or internal (one whose
personnel are employees of the RTO or ISO). Therefore, the Commission
proposed that it be left to the discretion of each RTO or ISO to decide
whether it should have an internal MMU, an external MMU, or a hybrid
MMU (consisting of both an internal market monitor and an external
market monitor).
174. To ensure that MMUs would have adequate tools with which to do
their job, the Commission proposed requiring each RTO or 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. We also
proposed that RTOs and ISOs include a tariff provision directing the
MMU to report to the Commission any concerns it has with inadequate
access to market data, resources, or personnel, and to describe the
steps it has taken with the RTO or ISO to resolve these concerns.
(b) Comments on the ANOPR Proposals and Questions
175. The overwhelming bulk of the commenters agreed with the
Commission's proposal and opposed imposition of a ``one size fits all''
approach. A few favored one or the other structure. Exelon, Strategic
Energy, and Suez favored an external model, on the grounds it could
best ensure independence.\137\ NJBPU favored an internal model, at
least with respect to PJM.\138\
---------------------------------------------------------------------------
\137\ Exelon at 25; Strategic Energy at 13; Suez at 9.
\138\ NJBPU at 1-2.
---------------------------------------------------------------------------
176. There was also limited support for an alternative reporting
structure. The Ohio PUC proposed that MMUs report to federal-state
boards,\139\ and the FTC suggested the Commission consider the costs
and benefits of alternative arrangements, which presumably would
involve a structure other than an employment or contractual
relationship between the MMU and the RTO or ISO.\140\
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\139\ Ohio PUC at 9-14.
\140\ FTC at 16-17. No particular alternative arrangement was
suggested.
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[[Page 12599]]
177. APPA stated that the real issue to be resolved is not
structure but assuring the independence of the MMU. It proposed ``rules
of the road'' to accomplish that objective, most of which have to do
with providing the MMU with adequate tools with which to do its
job.\141\ Joint Consumers Advocates also proposed specific MMU
principles, most involving oversight or tools.\142\
---------------------------------------------------------------------------
\141\ APPA at 72-73.
\142\ Joint Consumer Advocates at 16-19.
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178. Most commenters supported the Commission's proposal that RTOs
and ISOs include in their tariffs a requirement that they must provide
the MMU with adequate tools with which to do its job.\143\ Some stated
that access to resources must be full and unfettered.\144\ Others,
while generally supporting the proposal, called for budgetary and cost
containment provisions.\145\ The North Carolina Commission proposed
transparency of budget, with any disputes being made subject to
Commission review.\146\ Some commenters proposed that the MMU's offices
be located on the premises of the RTO or ISO.\147\ The PJM MMU argued
for control over its own data repository.\148\ EEI stated it did not
believe a tariff provision requiring the MMU to report to the
Commission any concerns it has with adequacy of resources was needed,
as MMUs are in regular contact with the Commission and can convey any
concerns they may have in this regard.\149\
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\143\ See, e.g., Ameren at 36-37; Duke Energy at 20; FirstEnergy
at 10; NYISO at 16; Ohio PUC at 12-14; Portland Cement at 17; Xcel
at 23.
\144\ American Forest at 45; APPA at 70; The Alliance at 17.
\145\ EEI at 42; EPSA at 4; Mirant at 11; North Carolina
Commission at 7; Pepco at 15; PJM Power Providers at 8; PSEG at 17;
Reliant at 16.
\146\ North Carolina Commission at 7.
\147\ See, e.g., NYISO at 20; North Carolina Commission at 6.
\148\ PJM MMU at 10.
\149\ 149 EEI at 43.
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(c) Commission Proposal
179. The Commission agrees with the bulk of the commenters that the
nature of the MMU structure is not determinative of either independence
or quality of performance, and proposes that each RTO and ISO decide
for itself, through its appropriate stakeholder process, whether it
will have an external, internal or hybrid MMU structure. The Commission
also declines to remove MMUs from overview by their RTOs and ISOs; the
MMU's principal duties involve monitoring RTO/ISO markets and advising
the RTO or ISO on market performance. The fact that MMUs also have
reporting obligations to outside parties does not change the
relationship they have with the RTOs and ISOs, which are, by Commission
policy, required to maintain a market monitoring function. It is also
doubtful that an alternative outside structural arrangement, such as
reporting to a federal-state board, could as effectively replicate the
existing close exchange of data between the RTO or ISO and the MMU,
which all acknowledge is vital if the MMU is to properly perform its
duties.
180. The Commission further proposes that each RTO or ISO 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. The RTO or ISO
should, in addition, also be mindful of these obligations in developing
its market monitoring budget. Furthermore, to ensure independence of
the MMU and its analyses, the RTO or ISO tariff should specifically
provide that the MMU shall have access to the RTO's or ISO's database
of market information. The tariff should also specify that any data
created by the MMUs, including reconfiguring of the RTO/ISO data, be
kept within the exclusive control of the MMU.
181. The Commission declines to micro-manage the RTO/ISO
relationships with their MMUs to the extent of requiring that MMU
offices be located on the RTO/ISO premises. We are of the view that
concerns of this type, as well as appropriate budgetary constraints,
are best worked out on an individual basis.
182. The Commission has reconsidered its ANOPR proposal regarding
inclusion of a tariff provision directing the MMU to report to the
Commission any concerns it has with inadequate access to market data,
resources, or personnel, or to describe the steps it has taken with the
RTO or ISO to resolve these concerns. The inclusion of such a
requirement may suggest that the Commission anticipates non-compliance
on the part of the RTOs and ISOs, whereas the opposite is true.
Furthermore, as EEI notes, adequate mechanisms are already in place for
the MMU to bring any concerns it may have to the Commission's
attention, including the complaint process, referrals to the
Commission's Office of Enforcement, and informal discussions with
Commission staff.
ii. Oversight
(a) Preliminary Proposals in the ANOPR
183. The Commission noted that an inherent tension exists 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. We stated that it could be difficult for
an MMU to discharge these oversight and reporting obligations
effectively unless it had some degree of independence from RTO/ISO
management. The Commission proposed that each RTO and ISO, in addition
to maintaining a market monitoring function, be required to have its
MMU, whether internal, external, or a hybrid combination of the two,
report either directly to the RTO's or ISO's board of directors or
directly to a committee of independent board directors.\150\ The ANOPR
sought comment on the Commission's authority to impose this type of
requirement on RTOs and ISOs, as well as on the proposal itself.
---------------------------------------------------------------------------
\150\ The ANOPR noted that this policy would mark a departure
from the holding in the PJM Tariff Order. PJM Tariff Order, 116 FERC
] 61,038 at P 38 (2006).
---------------------------------------------------------------------------
(b) Comments on the ANOPR Proposals and Questions
184. The great preponderance of commenters agreed with the
Commission's proposal, stating that reporting to the RTO or ISO board
would give the MMU more independence than if the MMU were to report to
management.\151\ However, CAISO and NYISO propose that in the case of a
hybrid structure such as theirs (i.e., one which has both an internal,
employee-staffed MMU and an external, non-employee-staffed MMU), the
internal MMU be permitted to report to management, with the external
MMU reporting to the board.\152\ CAISO states that this reporting
arrangement ensures that the chief executive officer is attuned to the
needs of the MMU and that other employees in the organization are
committed to supporting its functions, while NYISO states that the
arrangement enables its internal market monitor to work closely with
the rest of company staff and have greater opportunities to review
real-time market operations. Others suggested that the MMU report to
management for administrative purposes (such as human resources and
payroll).\153\
---------------------------------------------------------------------------
\151\ See, e.g., BP Energy at 29-30; BlueStar Energy at 6;
Dynegy at 4; EPSA at 45; FirstEnergy at 10; Industrial Consumers at
21; Joint Consumer Advocates at 19; Mirant at 11; NARUC at 10;
NEPOOL Participants at 28; Pepco at 15; Steel Producers at 18.
\152\ CAISO at 3; NYISO at 26.
\153\ EEI at 43; SoCal Edison-SDG&E at 10.
---------------------------------------------------------------------------
185. A few commenters opposed any RTO or ISO reporting requirement
at all, preferring that the MMU report to the
[[Page 12600]]
Commission or to a joint federal/state board.\154\ NRECA proposed that
the Commission periodically audit the quality of the MMU's reports and
investigations,\155\ and TAPS proposed that any change in the MMU's
status, such as contract termination or renewal, be reviewed and
approved by the Commission.\156\
---------------------------------------------------------------------------
\154\ See, e.g., OMS at 14-15; OPSI at 4-6; Ohio PUC at 9; North
Carolina Commission at 6.
\155\ NRECA at 26.
\156\ TAPS at 58.
---------------------------------------------------------------------------
186. Reliant proposed that the MMU must report to a full cross-
section of the board.\157\ Conversely, other commenters felt that
management representatives on the board should be excluded from MMU
oversight.\158\ PJM agreed with the ANOPR proposal, but expressed
concern that the board might be given an oversight responsibility
without the authority to actually oversee the MMU.\159\ PJM states that
any approach that does not place responsibility in the Commission for
the functioning and performance of MMUs, while limiting the RTO's
ability to supervise or oversee the MMU, would ``raise serious legal
questions about the Commission's ability to limit a public utility's
management of its business.'' \160\ This conditional objection was the
only comment that suggested the Commission may not have the authority
to order the proposed reporting relationship.\161\
---------------------------------------------------------------------------
\157\ Reliant at 16.
\158\ OPSI at 4-6; Old Dominion at 22.
\159\ PJM at 22-24.
\160\ PJM at 24. PJM argues that the Commission does not have
jurisdiction over utility employment relationships or contracts with
service providers, on the grounds these functions do not constitute
``a sale for resale or transmission of electric power in interstate
commerce.'' PJM at n. 41.
\161\ California PUC did not disagree that the Commission can
require MMUs to report to the RTO or ISO board, but requested the
Commission to set forth the basis for this authority and provide an
opportunity to comment. California PUC at 17.
---------------------------------------------------------------------------
(c) Commission Proposal
187. The Commission proposes that the MMU, for purposes of
supervision over its market monitoring functions, should report to the
RTO or ISO board rather than to management. The Commission further
proposes that management representatives on the board be excluded from
this oversight function. However, the RTOs and ISOs, should they deem
it appropriate, may have the MMU report to management for
administrative purposes, such as pension management, payroll and the
like. Furthermore, the Commission is sympathetic to the desires
expressed by CAISO and NYISO to retain the advantages they see in their
hybrid reporting structures. Thus, if an RTO or ISO has two market
monitoring bodies, an internal and an external one, the Commission
proposes that the RTO or ISO may have the internal MMU report to
management with respect to both its market monitoring and
administrative functions, and the external MMU report to the board.
188. The Commission, as noted above, finds little merit in the
suggestions that the MMU report to a body other than the RTO or ISO,
such as to the Commission or to a federal/state board. Commenters
afford no details as to how this structural arrangement could be
achieved, either from an economic, jurisdictional, or practical point
of view, or how such a potentially cumbersome structure as a joint
inter-governmental body could oversee MMUs in a timely and responsive
manner. The Commission itself will be adequately informed of the
results of MMU monitoring through the referral process and through the
various venues for the sharing of market information; this sharing of
market information applies as well to the states and other interested
bodies, who will thereby be adequately apprised of MMU performance and
can bring any concerns they may have in this regard to the RTO or ISO
or to the Commission.
189. The Commission declines to propose a formal auditing procedure
for MMUs, but expects that their work product will be of the highest
quality. The Commission remains free to undertake an audit in any given
instance, should that appear to be appropriate, and any concerns
regarding the quality of MMU work product can always be brought to the
Commission's attention. The Commission also declines to propose a
blanket requirement that all changes in MMU status, such as contract
termination or renewal, be subject to Commission review and approval.
Although requirements of this type are currently contained in the
contractual arrangements of certain RTOs and ISOs,\162\ the Commission
declines to propose extending this requirement to all RTOs and ISOs, in
accordance with our reluctance to impose a ``one size fits all''
approach in structural areas. We believe the issue should be dealt with
on a case-by-case basis.
---------------------------------------------------------------------------
\162\ E.g., Midwest ISO cannot terminate its agreement with its
market monitor (an independent contractor) without Commission
approval. Open Access Transmission and Energy Markets Tariff for the
Midwest Independent Transmission System Operator, Inc., Attachment
S-1, FERC Electric Tariff, Third Revised Volume No. 1, Second
Revised Sheet No. 1659 (2005). SPP cannot terminate its agreement
with its external market monitor without Commission approval.
Southwest Power Pool Open Access Transmission Tariff, FERC Electric
Tariff, Fourth Revised Volume No. 1, Attachment AJ, Sec. 11, Second
Revised Sheet No. 699 (2006). The same is true for ISO-NE.
Participants Agreement among ISO New England, Inc. and the New
England Power Pool, et al., Sec. 9.4.5.
---------------------------------------------------------------------------
190. With respect to PJM's concern that it may be burdened with
oversight responsibility over MMUs without possessing full authority to
carry out that responsibility, the Commission notes that its reporting
proposal does nothing to increase the limitations on an RTO's or ISO's
authority over its MMU. For MMUs that currently report to management,
the proposal merely shifts oversight from management to the board.\163\
Furthermore, the monitoring functions of MMUs affect sales for resale
and the transmission of electric power in interstate commerce, and as
such are properly subject to Commission regulation to ensure MMU
objectivity. As we noted in Order No. 2000,\164\ the Commission has a
responsibility to protect against anticompetitive effects in
electricity markets,\165\ and an independent MMU is an important
element upon which we rely to safeguard such competition. Our proposal
maintains oversight authority within the RTO or ISO, while fostering
MMU independence through the elimination of direct management control.
For these reasons, the Commission believes the proposal strikes the
appropriate balance between MMU independence and RTO/ISO oversight.
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\163\ PJM cites Cal. Indep. Sys. Operator Corp. v. FERC, 372
F.3d 395 (DC Cir. 2004), in support of its concern. However, that
case involved FERC's attempt to replace existing CAISO board members
with a slate proposed by an independent search firm. Obviously,
alteration of the very composition of an RTO or ISO board is an
entirely different matter from a requirement that MMUs report to the
board, instead of to management. The latter requirement in no way
interferes with the internal composition of the board. Furthermore,
the cited case noted that if FERC concluded that CAISO lacked the
independence or other necessary attributes to constitute an ISO, it
need not approve CAISO as an ISO. Id. at 404. Similarly, it is the
Commission's view that the MMU may lack sufficient independence if
it reports to management, rather than to the board; thus we may
require RTOs and ISOs, as a condition of their continued RTO/ISO
status, to incorporate the proposed requirement in their tariffs.
\164\ Order No. 2000, FERC Stats. & Regs. ] 31,089 at 31,155.
\165\ See Gulf States Utilities v. FPC, 411 U.S. 747, 758-59
(1973).
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iii. Functions
(a) Preliminary Proposals in the ANOPR
191. Noting that the issue of independence is integrally related to
that of the functions MMUs are expected to perform, the Commission
proposed continuing the following existing functions of MMUs: (1)
Identifying ineffective market rules and
[[Page 12601]]
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 also proposed requiring the MMUs to
advise the Commission and other interested entities, in addition to the
RTO or ISO, of recommendations for rule or tariff changes; retaining
the existing Protocols (with appropriate updates) governing referral of
potential market violations to the Commission, which are included as an
Appendix to the Policy Statement; \166\ and expanding the subject
matter of such referrals to include suspected rule or tariff violations
committed by an RTO or ISO as well as by market participants, as well
as suspected violations of other Commission-approved rules and
regulations, such as Affiliate Restrictions \167\ and Standards of
Conduct.
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\166\ The Commission clarified that 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. 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. See Order No. 674 and
Order No. 670.
\167\ The previous 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, Order No. 697, 72 FR 39,904 (July 20,
2007), FERC Stats. & Regs. ] 31,252 (2007).
---------------------------------------------------------------------------
(b) Comments on the ANOPR Proposals and Questions
192. There was general agreement from commenters concerning
continuation of the three functions identified in the ANOPR. Several
commenters stated that MMUs should not themselves participate in
effectuating market design, although they should advise the RTO or ISO
on proposed weaknesses in the existing market design and make
suggestions for improving it.\168\ A few commenters opposed reporting
suspected RTO or ISO violations, arguing that this would impair the
frank exchange of information between RTO or ISO employees and the
MMU.\169\ However, most comments on the subject supported such
reporting, and several commenters suggested that such reporting be
expanded to include instances of inappropriate dispatch (either too
conservative or too aggressive) which, although not constituting tariff
violations, might nonetheless impair optimal market performance.\170\
---------------------------------------------------------------------------
\168\ See, e.g., Old Dominion at 23; OMS at 18; OPSI at 9; NY TO
at 15.
\169\ NYISO at 25-26; CAISO at 7-8.
\170\ Strategic Energy at 13.
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193. Several commenters opposed a requirement that MMUs report
suspected violations of the Standards of Conduct or Affiliate
Restrictions, arguing that the MMUs do not have expertise in this area
and should not be diverted from their main task of monitoring the
markets.\171\ A number of the comments suggested that the MMUs should
not audit for such violations, but should report them if they come
across them in the ordinary course of business.\172\ Similarly, some
commenters suggested that MMUs should not audit for suspected rule or
tariff violations by the RTOs or ISOs, but should report them if they
came across them in the ordinary course of business.\173\
---------------------------------------------------------------------------
\171\ See, e.g., EEI at 45; EPSA at 47; Exelon at 26;
FirstEnergy at 10-11; Pepco at 17.
\172\ Duke Energy at 23; NYISO at 25-26; ISO-NE at 8-9.
\173\ ISO-NE at 8; Duke Energy at 22.
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194. The commenters generally supported reporting proposed tariff
or rule changes to other interested parties as well as to the RTO and
ISO, particularly mentioning market participants and stakeholders.\174\
NEPOOL Participants, however, cautioned that in certain instances this
might effectively broadcast the existence of a ``loophole'' that could
be exploited before a rule or tariff change could be accomplished.\175\
---------------------------------------------------------------------------
\174\ See, e.g., Old Dominion at 23; Pepco at 16; Ameren at 13;
APPA at 76-77.
\175\ NEPOOL Participants at 29-30.
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(c) Commission Proposal
195. The Commission notes that its proposals in the ANOPR did not
contemplate that the MMU make market design decisions itself, which are
within the purview of the RTO or ISO through stakeholder processes and
Commission approval, but rather that the MMU should advise the RTO or
ISO and the Commission in this area. It was also not the Commission's
intention that the MMU be required to seek out potential violations by
the RTO or ISO, or audit for Standards of Conduct or Affiliate
Restrictions violations. The Commission agrees that any proactive
investigations in these areas would divert the resources of the MMU
from its primary responsibilities and potentially embroil it in areas
not within its core expertise. Standards of Conduct and Affiliate
Restrictions violations in particular may be difficult to identify
without possession of specialized knowledge. Therefore, the Commission
agrees that any suspected violations in these areas need be referred
only if discovered in the ordinary course of the MMU's monitoring
duties. Any final determination as to whether a violation has occurred
would, of course, be the responsibility of the Commission.
196. However, the Commission finds little merit in the suggestion
that our proposal to require MMUs to report suspected misconduct by
RTOs and ISOs would impair the frank exchange of information between
RTO or ISO employees and the MMU. Such an argument could equally be
applied to scrutiny by any independent entity and, taken to its logical
conclusion, would effectively exempt RTOs and ISOs from investigation.
Permitting such an exemption might encourage a culture of lax adherence
to rule and tariff requirements.
197. The Commission agrees that an RTO or ISO could conduct
dispatch in such a way as to result in unnecessary market
inefficiencies, and therefore proposes that the MMU should advise
Commission staff of any substantial concerns it has along these
lines.\176\ With respect to broadening the reporting of proposed rule
and tariff changes to other interested parties as well as to the RTO or
ISO, the Commission finds merit in the concern that such broad
dissemination of information might make entities aware of a
``loophole'' that could be exploited before the necessary rule or
tariff change could be effected. For that reason, the Commission
proposes that an exception be made to the general rule of full
disclosure, which exception would provide that in the event the MMU
believes broad dissemination of such information in a given instance
could lead to exploitation, that it limit distribution of the
information to the RTO or ISO and to Commission staff, with an
explanation of why further dissemination should be avoided at that
time.
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\176\ If the MMU believes the dispatch practice rises to the
level of a tariff violation, the MMU should follow the procedures
outlined in the Protocols for referring market violations to the
Commission, which involve a written referral to the Office of
Enforcement with copies to the Office of Energy Market Regulation
and the Commission's Office of the General Counsel. Otherwise, its
concerns should be brought to the attention of the Division of
Energy Market Oversight in the Office of Enforcement.
---------------------------------------------------------------------------
198. The Commission therefore proposes that the functions an MMU is
to perform include the following: (1) Evaluating existing and proposed
market rules, tariff provisions and market design elements for their
effectiveness, and recommending
[[Page 12602]]
proposed rule and tariff changes not only to the RTO or ISO, but also
to the Commission's Office of Energy Market Regulation staff and to
other interested entities such as state commissions and market
participants, with the caveat that the MMU is not to effectuate its
proposed market design itself (a task belonging to the RTO or ISO), and
with the further caveat that the MMU should limit distribution of its
identifications and recommendations to the RTO or ISO and to Commission
staff in the event it believes broader dissemination could lead to
exploitation, with an explanation of why further dissemination should
be avoided at that time; (2) reviewing and reporting on the performance
of the wholesale markets to the RTO or ISO, the Commission, and other
interested entities such as state commissions and market participants;
and (3) identifying and notifying the Commission's Office of
Enforcement staff of instances in which a market participant's
behavior, or that of the RTO or ISO, may require investigation,
including suspected rule or tariff violations, market manipulation,
inappropriate dispatch, and suspected violations of Commission-approved
rules and regulations.
199. In furtherance of its goal of ensuring independent analysis on
the part of MMUs, the Commission also proposes that RTOs and ISOs
include a provision in their tariffs specifying that they may not alter
the reports generated by the MMUs nor dictate the conclusions reached
by the MMUs, although they may establish a reasonable mechanism for
review and comment on MMU reports while still in draft form. The
Commission believes this proposal will enable the MMU to receive
potentially helpful comment, while removing the ability of the RTO or
ISO to unreasonably influence or impede the MMU's analysis.
iv. Mitigation and Operations
(a) Preliminary Proposals in the ANOPR
200. The Commission expressed concern about whether it was possible
for MMUs to maintain independence in evaluating and reporting on market
performance while at the same time providing support to the RTO or ISO
in the administration of its tariff, which often takes the form of MMU-
conducted market power mitigation. The Commission noted that because
the operation and mitigation functions performed by MMUs directly
affect market outcomes and performance, an inherent conflict arises
when an MMU reports on market outcomes that the MMU itself has
influenced. For these reasons, the Commission proposed requiring that
MMUs refrain from assisting the RTO or ISO in tariff administration,
from participating in RTO/ISO market operations such as mitigation, and
from taking direct actions to influence the market, and instead
concentrate on their role of providing market evaluation, reports, and
advice.
(b) Comments on the ANOPR Proposals and Questions
201. As to the issue of tariff administration, there was
substantial, although not universal, agreement that this was a task
which properly falls within the purview of the RTO or ISO, not the MMU.
A few commenters took a middle position, suggesting that in a hybrid
structure, the internal MMU could be involved in tariff administration,
but not the external MMU.\177\ Some commenters requested clarification
as to what was envisioned in the concept of tariff administration.\178\
---------------------------------------------------------------------------
\177\ EEI at 46; New York PSC at 11-12; NY TO at 16-17.
\178\ See, e.g., OMS at 25-26; OPSI at 20-22; PSEG at 17-19.
---------------------------------------------------------------------------
202. There was no such agreement on the proposal to remove MMUs
from mitigation, and this issue proved to be the most contentious one
in the entire market monitoring section. A substantial minority of
commenters concurred in the ANOPR proposal, agreeing that it
constituted a conflict of interest for the MMUs to conduct mitigation,
and stating that it would compromise the MMU's independence for it to
both evaluate market performance and conduct mitigation.\179\ A number
of market participants, such as Dominion Resources, FirstEnergy, Duke
Energy, Dynegy and Pepco, support the proposal. NCEMC, AWEA, and
Silicon Valley Power also support the proposal.
203. EPSA stated that the MMU should not assist tariff
administration or market operations, including mitigation, on any
independent basis not clearly outlined in the tariff.\180\ EEI agreed
that there should be a functional separation between the MMUs and the
operational activities of the RTOs and ISOs, which EEI states can be
accomplished either by having the RTOs and ISOs perform operational
functions, or having the internal market monitor perform them.\181\
---------------------------------------------------------------------------
\179\ See, e.g., Ameren at 39; Xcel at 24; Dynegy at 5; Duke
Energy at 23; EPSA at 45-46; Mirant at 13.
\180\ EPSA at 45.
\181\ EEI at 46.
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204. A majority of commenters, representing a spectrum of market
participants, consumer groups, and RTOs and ISOs, opposed the proposal
to remove the MMU from mitigation, and advanced a variety of reasons
against it.\182\ Several commenters, including Portland Cement, the
Pennsylvania PUC, OPSI and OMS, maintained that it would create an even
greater conflict of interest, because the RTO or ISO would have a role
both in rule development and implementation.\183\ Commenters also
stated that the RTO or ISO would be more heavily influenced than would
an MMU by market participants, upon whom it depends for its existence,
and that its employees have close personal relationships with market
participants and are often former employees of market
participants.\184\ OMS suggested RTO or ISO management might be
hesitant to perform a needed mitigation measure if the measure were to
affect a market participant with a credible threat to leave the RTO or
ISO.\185\ Potomac Economics suggested the RTO or ISO can be insulated
from market participant influence by having the MMU administer
mitigation, whereas if the RTO or ISO had responsibility for the task
it would face the full brunt of market participant displeasure and
influence.\186\ Midwest ISO and OPSI opined that consumers would feel
less confidence in the fair application of mitigation were the function
to be transferred to the RTO or ISO.\187\
---------------------------------------------------------------------------
\182\ See, e.g., American Forest at 47-49; APPA at 74-77; BP
Energy at 31; California PUC at 21-23; Industrial Coalitions at 21-
23; Joint Consumer Advocates at 20-21; NARUC at 11; NEPOOL
Participants at 30-32; Northeast Utilities at 13-14; New England
Power Generators at 12-13; OMS at 23; OPSI at 13-19; Pennsylvania
PUC at 16-17.
\183\ Portland Cement at 19; Pennsylvania PUC at 16; OPSI at 17;
OMS at 23.
\184\ See, e.g., Portland Cement at 19.
\185\ OMS at 23.
\186\ Potomac Economics at 7-8.
\187\ Midwest ISO at 25-26; OPSI at 13.
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205. Another argument against the proposal was voiced by the
Pennsylvania PUC, which stated that RTO and ISO managers have acquired
their primary expertise in transmission or generation operations and
have little expertise in economics.\188\ ISO-NE and TAPS suggested that
administering mitigation gives the MMU better familiarity with the
working of the market and assists it in performing its analytical
functions.\189\ Other commenters stated that most mitigation is non-
discretionary, and therefore would not draw the MMU into a substantial
conflict of interest as far as its analytic tasks are concerned.\190\
One commenter suggested that a technical
[[Page 12603]]
conference be convened to examine the issue.\191\
---------------------------------------------------------------------------
\188\ Pennsylvania PUC at 16-17.
\189\ ISO-NE at 10-12; TAPS at 59.
\190\ See, e.g., Potomac Economics at 6.
\191\ New England Conference at 19.
---------------------------------------------------------------------------
206. The RTOs and ISOs, including ISO-NE, Midwest ISO, and NYISO,
were mainly opposed to removing the MMU from mitigation.\192\ CAISO
stated it had no opinion, but wanted clarification as to whether the
ISO or an independent entity would do the mitigation.\193\ SPP stated
it did not object, but indicated that it believed it would be in
compliance if its internal MMU administered the mitigation (which was
not the intent of the ANOPR proposal).\194\ PJM, whose market monitor
does not administer mitigation, supports the proposal.\195\
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\192\ ISO-NE at 9-12; Midwest ISO at 25; NYISO at 23-24.
\193\ CAISO at 8.
\194\ SPP at 10.
\195\ PJM at 25-27.
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(c) Commission Proposal
207. The ANOPR proposal to remove MMUs from tariff administration
was designed to strengthen their independence. The current practice of
allowing MMUs to support the RTOs and ISOs in tariff administration
necessarily makes their role subordinate to that of the RTOs and ISOs,
and thus weakens that independence. Furthermore, freeing MMUs from
tariff administration would allow them to objectively monitor the
markets, without the bias that might arise from their personal
involvement in tariff administration.
208. Some commenters argue that RTOs and ISOs do not currently have
individuals qualified to carry out mitigation. If true, this condition
is simply a reflection of the fact that the RTOs and ISOs have not
needed to hire such personnel, since the MMUs were already performing
the task for them. If necessary, RTOs and ISOs could acquire the staff
needed to carry out mitigation functions, and once this was
accomplished the MMUs would be able to concentrate on their core job of
monitoring the markets, without the potential conflict of interest that
arises from reviewing their own mitigation.
209. Several commenters contend that RTOs and ISOs are more
susceptible to influence from market participants than are MMUs, and
therefore would not be as diligent in performing mitigation. However,
mitigation is supposed to be nondiscretionary in nature. RTOs and ISOs,
as well as MMUs, are required to limit the administration of tariff
compliance to those provisions expressly set forth in the tariff,
involve objectively identifiable behavior, and do not subject the
seller to sanctions or consequences other than those expressly approved
by the Commission and set forth in the tariff, with the right of appeal
to the Commission.\196\ That being the case, any failure by the RTO or
ISO to carry out required mitigation would be readily apparent to the
MMU, whose job of monitoring the markets necessarily includes
determining whether mitigation has been properly performed. Any
persistent or substantial failure by the RTO or ISO in this regard
would constitute a tariff violation and, as such, should be referred to
the Commission's Office of Enforcement staff.
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\196\ Market Behavior Rules Order, 105 FERC ] 61,218 at P 182;
Policy Statement, 111 FERC ] 61,267 at P 5.
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210. The Commission therefore proposes that MMUs be removed from
tariff administration, including mitigation. Although we believe the
advantages of doing so outweigh the temporary transition pains that may
result, we are nonetheless sensitive to the many concerns raised by
those commenters who oppose the proposal. We therefore solicit comments
on the activities that would be needed to make the transition to RTO/
ISO-administered mitigation, on any difficulties the MMU might be
anticipated to experience in monitoring mitigation performed by the RTO
or ISO, and any additional sensitivities that commenters wish to raise
regarding the proposal.
v. Ethics
(a) Preliminary Proposals in the ANOPR
211. The Commission proposed imposing certain minimum ethics
standards upon market monitor personnel, in particular prohibiting such
personnel from owning financial interests in any market participants.
The Commission noted that all existing RTOs and ISOs have some type of
conflict of interest or other ethics provisions, although not always in
their tariffs, and proposed standardizing such provisions and requiring
their inclusion in the tariffs themselves.
(b) Comments on the ANOPR Proposals and Questions
212. Most commenters agreed that certain minimum ethical standards
should be imposed on MMU employees, citing in particular conflict of
interest provisions.\197\ Many argued that the RTOs and ISOs be allowed
the flexibility to develop their own provisions, in addition to the
core minimum set forth by the Commission.\198\ Some commenters thought
it unnecessary to include the standards in the tariffs, suggesting they
could be posted on the RTO or ISO Web site instead.\199\
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\197\ See, e.g., Duke Energy at 24; Old Dominion at 25; OMS at
27-28; OPSI at 22; Silicon Valley Power at 13; Steel Producers at
19.
\198\ See, e.g., APPA at 77; EEI at 49; Midwest ISO at 28; NYISO
at 17; Pepco at 18-19.
\199\ EPSA at 46; Exelon at 27.
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(c) Commission Proposal
213. The Commission agrees with the majority of the commenters that
ethical standards for MMU employees should be included in the RTO or
ISO tariff. Such inclusion would allow protest by intervenors and
permit Commission review and enforcement.
214. In light of the fact that RTOs and ISOs currently impose
ethical standards on their MMUs, although not always in their tariffs,
and which in some cases are the same standards they apply to their
other employees, the Commission proposes that development of the
particular ethical standards to be applied to MMUs be left in the first
instance to the discretion of the RTOs and ISOs. However, the
Commission believes these standards should include certain minimum
requirements to be imposed on MMU employees, as follows: (i) Employees
shall have no material affiliation (to be defined by the RTO or ISO)
with any market participant or affiliate; (ii) employees shall not
serve as an officer, employee, or partner of a market participant;
(iii) employees shall have no material financial interest in any market
participant or affiliate (allowing for such potential exceptions as
mutual funds and non-directed investments); (iv) employees shall not
engage in any market transactions other than the performance of their
duties under the tariff; (v) employees shall not be compensated, other
than by the RTO or ISO, for any expert witness testimony or other
commercial services to the RTO or ISO or to any other party in
connection with any legal or regulatory proceeding or commercial
transaction relating to the RTO or ISO or to the RTO or ISO markets;
(vi) employees may not accept anything of value from a market
participant in excess of a de minimis amount, to be decided on by the
RTO or ISO; and (vii) employees must advise their supervisor (or, in
the case of the MMU manager himself, advise the RTO or ISO board) in
the event they seek employment with a market participant and must
disqualify themselves from participating in any matter that would
[[Page 12604]]
have an effect on the financial interest of such market
participant.\200\
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\200\ Some external MMUs may currently have business
associations which would be prohibited under these proposed minimum
requirements, such as unrelated consulting work for participants in
its RTO's or ISO's markets. If that is the case, the RTO or ISO
should propose a suitable transition plan in its compliance filing.
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vi. Tariff Provisions
(a) Preliminary Proposals in the ANOPR
215. The Commission proposed that each RTO and ISO set forth all
its provisions involving market monitoring in one section of its
tariff, noting that in order for MMUs to achieve transparency of
function, the detailed obligations imposed upon them must be made clear
and accessible, and also be subject to approval and enforcement by the
Commission.
(b) Comments on the ANOPR Proposals and Questions
216. There was widespread support for this proposal, although some
commenters proposed that non-substantive MMU provisions be posted
instead on the RTO or ISO Web site.\201\ Duke Energy proposed that the
RTO or ISO be allowed to perform centralization of the tariff
provisions the next time it makes an amendment to its market monitoring
rules.\202\ The PJM MMU proposed that MMU provisions be included
elsewhere in the tariff as well as in the MMU section, if the context
so requires.\203\
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\201\ EPSA at 46; Pepco at 19.
\202\ Duke Energy at 24.
\203\ PJM MMU at 17.
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(c) Commission Proposal
217. In accordance with the bulk of the comments on this subject,
the Commission proposes that the RTOs and ISOs be required to include
in their tariffs, and centralize in one section, all their MMU
provisions. Including all MMU provisions in the tariff will ensure they
are subject to the compliance requirements that attach to tariff
provisions, and will give notice to interested parties, and thus an
opportunity to intervene, when a tariff filing is made. As noted in the
ANOPR, centralization of the MMU provisions has the obvious advantage
of clarity and ease of reference. The Commission also proposes that the
RTOs and ISOs include a mission statement for the MMU in the
introductory portions of the section. This statement should set forth
the goals to be achieved by the MMU, including the protection of both
consumers and market participants by the identification and reporting
of market design flaws and market power abuses.
218. The Commission disagrees with the comment requesting that the
RTOs or ISOs be permitted to delay centralization until such time as
they may choose, or otherwise be required, to make an amendment to
their MMU rules. Such amendments will in all likelihood be required
after issuance of a final rulemaking in this proceeding, and in any
event the requirement should not be unduly onerous. Therefore, the
Commission proposes that the RTOs and ISOs centralize their MMU tariff
provisions when they make their compliance filings in connection with
this proceeding. The Commission also sees no reason to forbid the RTOs
and ISOs from posting MMU provisions elsewhere in their tariffs as well
as in their MMU sections, should clarity and context so require, as
long as appropriate cross-referencing is made.
b. Information Sharing
219. The Commission advanced proposals in the ANOPR that responded
to requests of commenters at the technical conference for dissemination
of expanded market information, and to a broader group of recipients.
In particular, given the integral relationship between wholesale and
retail rates, the Commission acknowledged the need for information by
state commissions to assist them in performing their regulatory
functions. However, the Commission noted that since public disclosure
of certain information could harm market participants or could
facilitate collusion under some circumstances, it was necessary to
balance the need for information access with confidentiality concerns.
The Commission solicited comments on the proposed changes.
i. Enhanced Information Dissemination
(a) Preliminary Proposals in the ANOPR
220. The Commission proposed enhancing the dissemination of
information in several areas. Specifically, the Commission proposed
that MMUs be required to report comprehensively on aggregate market and
RTO/ISO performance on a regular basis, but no less frequently than
quarterly, to Commission staff, to staff of interested state
commissions, and to the management and board of directors of the RTOs
or ISOs. Further, the Commission proposed that MMUs should be required
to deliver materials supporting their conclusions; make one or more of
their staff members available for a conference call with
representatives from the Commission, state commissions, and RTO or ISO;
and work cooperatively to develop any further materials which might be
useful to the Commission, to the state commissions and to the RTOs or
ISOs.\204\ Finally, the Commission proposed that offer and bid data,
without identification of the market participants and with a lag of
three months, be posted on the RTO or ISO Web site.
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\204\ The Commission clarified that such reports and meetings
were not intended to restrict the MMU from meeting individually with
Commission staff, staff of state commissions, market participants,
or other stakeholders, or sharing information with these various
constituencies, subject to appropriate restrictions on
confidentiality.
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221. The Commission requested comment on whether the proposal met
the needs of the state commissions and whether there were other kinds
of information needed by state commissions to fulfill their regulatory
responsibilities. The Commission further solicited comment on whether
there was a generic standard or test that could be used to determine
what specific information should be provided to state commissions.
(b) Comments on the ANOPR Proposals and Questions
222. No comments were received proposing a generic standard or test
to determine the specific information that should be provided to state
commissions. There were relatively few comments identifying specific
types of data needed; \205\ rather, most commenters supporting greater
access argued that state agencies should receive all available market
information in order to assist them in their regulatory tasks.\206\
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\205\ The California PUC set forth a lengthy list of desired
market information, such as confidential and disaggregated data, bid
data, generator dispatch data, generator performance data, unit
commitment, scheduled and operational levels, and what units set
clearing prices. It cautioned, however, that California's needs are
specific to its market design and structure as a single state ISO,
and that data reporting protocols would vary from state to state.
California PUC at 27-30.
\206\ See, e.g., FirstEnergy at 11; NARUC at 6; Massachusetts AG
at 5; Joint Consumer Advocates at 22; New York PSC at 13.
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223. There was substantial support for the proposal to require
quarterly reports and conference calls.\207\ Some commenters, however,
thought comprehensive reports would be too costly and unduly time
consuming.\208\ Pepco suggested that these quarterly
[[Page 12605]]
reports not be as extensive as the current annual reports, in order to
avoid an excessive drain on the money and resources of the MMUs.\209\
There was also concern that confidentiality protections be
observed.\210\ At least one commenter suggested that state attorneys
general be included in the process as well as state commissions, since
not all energy providers and consumers are associated with entities
regulated by state commissions.\211\ Some commenters, although
recognizing that inclusion of market participants in conference calls
would be unwieldy, proposed that they be included in the dissemination
of the reports.\212\
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\207\ See, e.g., BlueStar Energy at 6-7; Duke Energy at 26;
Industrial Consumers at 37; NEPOOL Participants at 32; New England
Conference at 19; North Carolina Electric Membership at 11; NRECA at
24; Old Dominion at 26.
\208\ EEI at 50; EPSA at 48; Mirant at 15; Duke Energy at 26.
\209\ Pepco at 19-20.
\210\ Constellation at 19; J. Aron, Barclays, Morgan Stanley at
6; Old Dominion at 26.
\211\ APPA at 84. See also LPPC at 15.
\212\ See, e.g., Old Dominion at 26.
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224. There was substantial comment on the proposal to reduce the
lag period for offer and bid data to three months, with a majority
either favoring the Commission's proposal or not actively opposing
it.\213\ Some commenters stated that the lag period should be even
shorter than three months, arguing that such information is released in
Australia and the United Kingdom in close to real time, with no
apparent adverse effects.\214\ Others favored retention of the six-
month period.\215\ There was substantial support for something slightly
longer than three months, in order to avoid the problem of data release
within the same season; such release, it was argued, would provide
opportunities for collusion and market power abuse.\216\ EEI notes that
different RTOs and ISOs have reached differing conclusions as to the
appropriate lag time, and suggested that the Commission take into
account regional differences, with a lag time no greater than six
months and no less than three months.\217\
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\213\ See, e.g., Reliant at 22; PJM at 29; PSEG at 20; SMUD at
15; CAISO at 10; Connecticut and Massachusetts Municipals at 27; DC
Energy at 9; Massachusetts AG at 5; Midwest ISO at 29; NEPOOL
Participants at 33.
\214\ Industrial Consumers at 37-38; TAPS at 61.
\215\ See, e.g., Ameren at 42; Duke Energy at 26-27; Dynegy at
6; Industrial Coalitions at 24; NJBPU at 2; PJM MMU at 18.
\216\ See, e.g., Dynegy at 6; NJPBU at 2; OMS at 35; OPSI at 29;
Old Dominion at 26.
\217\ EEI at 52-53.
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225. Some commenters argued that masking the identity of the
participants harmed the smaller players, contending that the larger
players already have software programs which enable them to ascertain
the identities of the participants.\218\ OPSI supported maintaining
confidentiality by the aggregation of cost data,\219\ and Reliant
argued that bidding data should be masked to avoid matching offers with
the known output of the plant in question, thereby revealing the
identity of the participant.\220\
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\218\ Pennsylvania PUC at 18; TAPS at 62.
\219\ OPSI at 30. OPSI includes reference price or unit
estimated cost data within the term.
\220\ Reliant at 22. Reliant used the term ``bid data,'' which
the Commission assumes refers to offers, given the company's concern
over matching offers to unit output.
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(c) Commission Proposal
226. The Commission declines to propose a generic standard or test
to determine the type of information that may be disseminated to state
commissions. Inasmuch as there was no support for such a standard, the
Commission believes the type of information to be released may most
fruitfully continue to be developed on a case-by-case basis, so long as
it generally consists of market analyses of the type regularly gathered
by the MMUs in the course of business, and so long as it remains
subject to appropriate confidentiality restrictions.
227. The Commission proposes that market participants be included
in the dissemination of reports, which could be accomplished via
posting them on the RTO or ISO Web site. However, the Commission agrees
that including market participants on conference calls would be
unwieldy, and proposes limiting participation on such calls to
Commission staff, RTO and ISO staff, staff of interested state
commissions, and staff of state attorneys general should they express a
desire to attend.
228. The Commission agrees that quarterly reports should not be as
extensive as the annual state of the market reports. Preparing overly
extensive reports would divert the attention of the MMUs from their
tasks of daily monitoring and of providing recommendations to the RTO
or ISO and the Commission regarding desirable rule and tariff changes.
The Commission also believes that the annual state of the market
reports have proven to be useful documents, and proposes that the RTOs
and ISOs include in their tariffs a requirement for the MMUs to produce
them, with the same dissemination (or broader, if desired) as the
quarterly reports.
229. The Commission is persuaded by the comments that no harm
generally would result from shortening the current six-month lag
period.\221\ However, the Commission acknowledges that in some
instances release of such information in the same season could afford
opportunities for collusion.\222\ Therefore, the Commission proposes
that the time period for the release of offer and bid data be reduced
to three months, but that the RTO or ISO may propose a shorter period,
with accompanying justification. However, if the RTO or ISO
demonstrates a potential collusion concern, it may propose a four-month
lag period or, alternatively, some other mechanism to delay the release
of a report if the release were otherwise to occur in the same season
as reflected in the data.
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\221\ The Commission recently approved the request of ISO-NE and
NEPOOL to shorten the lag time for release of ISO-NE offer and bid
data from six months to roughly three months. ISO New England Inc.
and New England Power Pool, 121 FERC ] 61,035 (2007) (ISO-NE Bid/
Offer Order).
\222\ In the ISO-NE Bid/Offer Order, we found that the
combination of ISO-NE's ability to expeditiously file for a rule
change if negative impacts on the market were experienced, and the
existing tariff language that masks the bid/offer data, adequately
protected against the risk of collusion.
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230. The Commission proposes retaining the practice of masking the
identity of participants when releasing offer and bid data. The
possibility raised by a few commenters that some players may be able to
surmise the identity of participants argues, if anything, for further
protection, not for less. The Commission further proposes that the RTO
or ISO include in its compliance filing a justification of its policy
regarding the aggregation or lack thereof of offer data and of cost
data, discussing the manner in which it believes its policy avoids
participant harm and the possibility of collusion, while fostering
market transparency.
ii. Tailored Requests for Information
(a) Preliminary Proposals in the ANOPR
231. The Commission proposed that state commissions may make
reasonable requests for additional tailored information from the MMUs,
acknowledging that information such as general analyses of the market
and aggregated price data may assist state commissions in performing
their regulatory functions. The Commission stated that these requests
should be limited to information regarding general market trends and
performance, and not encompass information designed to aid state
enforcement or actions against individual companies. This restriction
was proposed in light of the limited resources of MMUs and the fact
that states have their own enforcement agencies which are more properly
employed for such tasks. However, the Commission proposed that a state
commission could, on a case-by-case basis, request that the Commission
authorize the release of otherwise proscribed data. The Commission
would then evaluate whether there was a
[[Page 12606]]
compelling need for the requested information, and decide whether
adequate protections could be fashioned for commercially sensitive
material.
(b) Comments on the ANOPR Proposals and Questions
232. There was substantial support for the Commission's proposal to
allow state commissions to make tailored requests for information, with
the caveat that such requests should not be permitted to place too
great a burden on the workload of the MMUs.\223\ Several commenters
suggested this problem could be solved by limiting the information
provided by the MMU to that generated in the ordinary course of
business.\224\ Other commenters objected to the restriction prohibiting
the release of information designed for enforcement purposes, arguing
that the states have little other means of access to the necessary
information.\225\ A number of commenters cautioned that requests for
information must be accompanied by assurances of confidentiality.\226\
At least some RTOs and ISOs currently have provisions in their tariffs
governing the release of confidential information; \227\ however, OMS
asserts that such tariff provisions (at least with respect to Midwest
ISO) are so restrictive as to effectively bar the release of needed
information.\228\ Several commenters proposed that before an MMU be
allowed to release information pertaining to a particular market
participant, that the participant be given the opportunity to object
and to correct any inaccurate information proposed to be released.\229\
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\223\ See, e.g., Reliant at 19; PJM Power Providers at 10.
\224\ See, e.g., PJM Power Providers at 10; Exelon at 28.
\225\ NARUC at 9; Ohio PUC at 19.
\226\ Constellation at 19; Joint Consumer Advocates at 22;
Midwest ISO at 30.
\227\ See, e.g., Midwest ISO at 30; SPP at 11.
\228\ OMS at 31.
\229\ See, e.g., EEI at 51; FirstEnergy at 11; DC Energy at 8.
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(c) Commission Proposal
233. The Commission notes that entertaining tailored requests for
information from state commissions subjects the MMU to the risk that it
will be diverted from its core functions of monitoring the market and
making rule and tariff recommendations to the RTO or ISO. Therefore,
the decision as to whether to respond to such requests, assuming they
otherwise fall within acceptable parameters, should be made by the MMU,
in light of its budgetary and time limitations.
234. The Commission continues to believe its proposed restriction
on information designed for enforcement purposes is a reasonable one.
Such requests would not only implicate serious confidentiality
concerns, they could overwhelm the MMU's workload, as they would likely
involve more detailed investigations than would be required for general
market information or for MMU referrals to the Commission. While states
may not have the tools and expertise to monitor the market as
effectively as can the MMUs, they do have access to resources to carry
out enforcement functions. Furthermore, the costs of state enforcement
should rightfully be borne by the states, not by the MMUs or RTOs and
ISOs. Therefore, the Commission proposes that MMUs may entertain
requests for information from state commissions, so long as such
information pertains to general market trends and performance, is not
designed to aid state enforcement or actions against individual
companies,\230\ and the MMU can accommodate such requests within its
budgetary and time constraints without jeopardizing its ability to
perform its core tariff-defined functions.
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\230\ 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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235. The Commission also believes that while confidentiality
provisions serve a useful purpose, they should not be drafted in such a
way as to impose unnecessary barriers to the dissemination of
information. Therefore, the Commission proposes that RTOs and ISOs
develop confidentiality provisions for their tariffs that will protect
commercially sensitive material, but which will not be so restrictive
as to permit the release of little if any information.
236. The Commission also agrees that if requested information
pertains to specific market participants, other than offer and bid
data, that as a matter of fairness the named market participant should
be given notice and the opportunity to contest the information.
Therefore, the Commission proposes that the RTOs and ISOs include such
a provision in their tariffs.
237. In the ANOPR, the Commission proposed permitting state
commissions to petition the Commission on a case-by-case basis for
information that does not fall within the proposed acceptable
parameters. This safety valve should alleviate state concerns that they
may be prevented from acquiring information for which they have a
compelling need, while also ensuring that the Commission will be able
to examine such requests in light both of state needs and the ability
to fashion adequate confidentiality protections. Therefore, the
Commission proposes that the RTOs and ISOs note the availability of
this exception in their tariffs.
iii. Commission Referrals
(a) Preliminary Proposals in the ANOPR
238. The Commission stated that MMUs should continue to respect the
confidentiality of their referrals of suspected wrongdoing to the
Commission, and not disclose such referrals to other entities,
including state commissions. The Commission also expressed its
intention not to disseminate information regarding its investigations,
noting that the Commission's rules require that such information be
kept nonpublic unless the Commission authorizes, in any given case,
that it be publicly disclosed.\231\ The Commission noted, however, that
it intended to continue the practice of Commission staff providing the
MMUs with generic feedback regarding enforcement issues.
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\231\ 18 CFR 1b.9 (2007). 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).
---------------------------------------------------------------------------
(b) Comments on the ANOPR Proposals and Questions
239. Comments were received on both sides of this issue, with state
representatives arguing for release of MMU referral information, for
the results of Commission investigations, and for disclosure of the
progress of Commission investigations.\232\ Other commenters
acknowledged the legal and policy considerations noted by the
Commission, and concurred in the need to maintain confidentiality.\233\
The California PUC, while stating that it understood the need for
confidentiality, proposed that in the event wrongdoing is discovered
that affects a state commission with appropriate jurisdiction, that
such commission should be notified of the wrongdoing.\234\ Some
commenters argued that state bodies have procedures in place to protect
confidentiality, and so should not be barred from receiving such
information from the MMUs and the Commission.\235\ Constellation,
however, cautions that these procedures may not protect disclosure from
Freedom of
[[Page 12607]]
Information Act (FOIA) requests or requests made under equivalent state
statutes.\236\
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\232\ See, e.g., California PUC at 32; Ohio PUC at 19; OMS at
37-38; OPSI at 31-32.
\233\ See, e.g., Reliant at 19; Exelon at 29.
\234\ California PUC at 32.
\235\ See, e.g., New York PSC at 15; North Carolina Commission
at 7; OPSI at 32.
\236\ Constellation at 19.
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(c) Commission Proposal
240. The Commission notes that the commenters that argued for the
release of referral and investigative information to such bodies as
state commissions did not generally address the substantial legal and
policy arguments against such release, other than to note that some
state bodies have confidentiality procedures (which may or may not
withstand FOIA-type requests). As the Commission observed in the ANOPR,
not only do Commission rules prohibit such release, but release could
impede the willingness of market participants to self-report and
otherwise cooperate in investigations, and could injure innocent
persons who might be erroneously implicated or adversely affected by
simply being associated with an investigation. Therefore, the
Commission proposes that the existing provisions regarding the
confidentiality of MMU referrals to the Commission, as well as the
confidentiality of the progress and results of its own investigations,
be retained.
c. Pro Forma Tariff
i. Preliminary Proposals in the ANOPR
241. Finally, the Commission in the ANOPR stated our intent to
include in this NOPR a proposed pro forma MMU section for RTO/ISO
tariffs, which would contain standardized core provisions but also
allow for regional variations. The Commission stated that it
anticipates including in the pro forma MMU section protocols for the
referral of tariff, rule 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 Market Regulation. The Commission solicited comments
on the structure and content of such a pro forma section.
ii. Comments on the ANOPR Proposals and Questions
242. There was substantial support for a pro forma tariff section
of core MMU provisions. However, a number of entities, such as the
Midwest ISO, cautioned that a pro forma tariff would ignore regional
variations, disregard stakeholder consensus and increase compliance
burdens. Those arguing for a pro forma tariff supported the ANOPR
proposal that each RTO or ISO be given the flexibility to propose
individual provisions, in order to reflect regional variations. NYISO
cautioned against the Commission attempting a pro forma mitigation
provision.
iii. Commission Proposal
243. The Commission had proposed in the ANOPR that a pro forma MMU
tariff section would be limited to essential core MMU provisions, such
as functions, oversight, tools and information sharing, thus freeing
the RTOs and ISOs to propose regional variations. In light of the fact
that in this NOPR we are proposing that many important aspects of the
market monitoring relationship with the RTOs and ISOs be left to the
discretion of the individual RTOs and ISOs, and in light of the fact
that there may well be other regional variations which the RTOs and
ISOs may wish to propose, the Commission believes a pro forma tariff
section, which would necessarily have a large number of blank
subsections, would be of limited value.
244. For that reason, the Commission proposes that instead of
requiring the RTOs and ISOs to follow the outlines of a pro forma MMU
tariff section, that they conform their tariff to the requirements that
will be ultimately set forth in the rulemaking to be issued in this
docket, including centralization of the MMU provisions in one section.
The Commission also proposes that each RTO and ISO include in its
tariff protocols for the referral of tariff, rule and market
manipulation violations to the Office of Enforcement, revised as
discussed above, and for the referral of perceived market design flaws
and recommended tariff changes to the Office of Energy Market
Regulation.
D. Responsiveness of RTOs and ISOs to Stakeholders and Customers
245. In this section of the NOPR, the Commission proposes to
establish new criteria intended to ensure that an RTO or ISO board is
responsive to the RTO's or ISO's customers and other stakeholders.
These criteria will include: (1) Inclusiveness; (2) fairness in
balancing diverse interests; (3) representation of minority positions;
and (4) ongoing responsiveness. The Commission proposes to require each
RTO or ISO to submit a compliance filing demonstrating that it has in
place or will adopt practices and procedures to ensure that it is
responsive to stakeholders and customers. In the compliance filing, the
Commission encourages each RTO or ISO to evaluate what practices and
procedures may best satisfy the responsiveness criteria.
246. In the ANOPR, the Commission made a preliminary proposal to
improve responsiveness of RTO and ISO boards of directors to customers
and other stakeholders. By responsiveness, we mean an RTO or ISO
board's willingness, as evidenced in its practices and procedures, to
directly receive concerns and recommendations from customers and other
stakeholders, and to fully consider and take actions in response to the
issues that are raised. We also sought comment on several issues
focusing on whether and how RTO and ISO responsiveness to stakeholders
can be improved, including management practices and stakeholder
participation in the budgeting process.
1. Background
247. In Order No. 888, the Commission encouraged but did not
require the formation of ISOs, delineating eleven principles defining
the operations and structure of a properly functioning ISO.\237\
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.\238\ Embodied
in Order Nos. 888 and 2000 is the requirement that the regional
transmission entity be independent from market participants.
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\237\ 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. ] 31,036, at 31,730-32 (1996),
order on reh'g, Order No. 888-A, FERC Stats. & Regs. ] 31,048, 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 sub
nom. Transmission Access Policy Study Group v. FERC, 225 F.3d 667
(DC Cir. 2000), aff'd sub nom. New York v. FERC, 535 U.S. 1 (2002).
\238\ Order No. 2000-A, FERC Stats. & Regs. ] 31,092 at 30,993.
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248. Although it required independence, Order No. 2000 did not
mandate detailed governance requirements for an RTO board of directors.
The Commission stated that, given the early stage of RTO formation, it
would be ``counterproductive'' to impose a one-size-fits-all approach
to governance when RTOs may have varying structures based on their
regional needs.\239\ Therefore, the Commission stated that it would
review governance proposals on a case-by-case basis.\240\ The
Commission also provided guidance based on existing governance
arrangements, emphasizing the
[[Page 12608]]
importance of stakeholder input regarding both RTO formation and
ongoing operations. The Commission stated that stakeholder committees
should have balanced representation on such committees so that no one
stakeholder class dominates the committee's recommendations. The
Commission added that, in the case of a non-stakeholder board, it is
important that this board not become isolated.\241\ For these reasons,
the Commission explained that both formal and informal mechanisms
should be used to ensure that stakeholders can convey their concerns to
the non-stakeholder board. This standard is no different for currently-
operating ISOs, as the ISO principle of independence requires fair
representation of all types of users of the system to ensure that the
ISO formulates policies, operates the system, and resolves disputes in
a fair and non-discriminatory manner.\242\
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\239\ Id. at 31,073. The Commission noted that existing ISOs
have varying forms of governance. Some used a two-tier form of
governance with a non-stakeholder board and advisory committees of
stakeholders while one ISO in particular, CAISO, employed a
decision-making board consisting of both stakeholders and non-
stakeholders. Id.
\240\ Id. at 31,073-74.
\241\ Id.
\242\ Order No. 888, FERC Stats. & Regs. ] 31,036 at 31,730-31.
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2. Preliminary Proposals in the ANOPR
249. In the ANOPR, the Commission made the preliminary conclusion
that representatives of RTO and ISO customers and other stakeholders
should have some form of effective direct access to the RTO or ISO
board of directors.\243\ The Commission asked whether each RTO and ISO
should be required to develop and implement a means to ensure that
customers and other stakeholders have such access.\244\ The Commission
made the preliminary proposal that either of two mechanisms, a hybrid
board or a board advisory committee, could accomplish the goal of
enhancing customer and other stakeholder access to the board.\245\
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\243\ ANOPR, FERC Stats. & Regs. ] 32,617 at P 148.
\244\ Id. P 149.
\245\ Id. P 151, 153.
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250. The Commission explained that a hybrid board would be composed
of both independent members and stakeholder members, with each member
holding a seat on the board and participating fully in board decisions
with an equal vote. The Commission stated that a hybrid board would
directly expose the board to stakeholders' concerns and that it
believed that it should be possible to structure a hybrid board without
sacrificing overall board independence.\246\
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\246\ The Commission also noted that certain restrictions may be
necessary for the hybrid board proposal to ensure that stakeholder
members do not inappropriately serve their own interests. Id. P 152.
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251. Alternatively, the Commission suggested that a board advisory
committee, comprised of senior executives of the various stakeholder
groups, could serve as an expert panel that would inform the board of
stakeholder views. The board advisory committee would have no voting
authority on board decisions, but could make recommendations directly
to the board on matters before the board and on matters it believes the
board should address. The Commission stated that it envisioned such a
committee to include members selected to represent a reasonable range
of diverse interests.\247\
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\247\ Id. P 153-54.
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252. Based on these two models of improving RTO and ISO
responsiveness, the Commission sought comments on the following
questions:
How should any hybrid board be structured? What is an
appropriate limit on the percentage of non-independent board members?
If a variety of customer views are to be represented, what implications
does this have for the size of the board?
What, if any, rules and restrictions should be placed on
the stakeholder board members of a hybrid board?
Can the reform proposed here be met through other means
such as increased direct board interaction with customers and other
stakeholders, e.g., through open board meetings or through required
attendance of board members at major stakeholder meetings of the RTO?
Are there measures--such as customer satisfaction
measures, cost oversight benchmarks, or stakeholder participation
measures--that RTOs and ISOs should use to assess the success of the
mechanism for improving responsiveness?
253. In the ANOPR, the Commission also requested comment on whether
any reforms are necessary to increase management responsiveness to
stakeholders. Among specific topics, the Commission requested comment
on whether it should encourage or require RTOs and ISOs to publish a
strategic plan that includes plans for ensuring responsiveness to
customers and stakeholders, set performance criteria for executive
managers based in part on responsiveness to stakeholders, and relate
executive compensation to a measure of responsiveness to stakeholders.
3. Comments on the ANOPR Proposals and Questions
254. The Commission received numerous responses from commenters
regarding the questions posed in the ANOPR. A majority agrees with the
Commission's conclusion that more effective direct access to RTO and
ISO boards is needed. They do not agree, however, on the mechanism to
achieve that goal. Some commenters favor the hybrid board, but many
express concern with this approach, preferring the board advisory
committee. Several commenters support using both a hybrid board and a
board advisory committee,\248\ noting that the two approaches are not
mutually exclusive.\249\ Several commenters discussed changes in RTO
and ISO management practices to improve the responsiveness.
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\248\ E.g., AEP at 7; Ameren at 44; APPA at 88. SMUD states that
the Commission should explore both approaches. SMUD at 20-22.
\249\ NYISO suggested a shared governance model as an
alternative to the hybrid board and the board advisory committee
models proposed in the ANOPR. NYISO at 6.
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a. Comments on the Hybrid Board Approach
255. Some commenters support the proposal for a hybrid board
approach, stating that a hybrid board would improve RTO responsiveness
and allow stakeholder access to an RTO and ISO board.\250\ While they
believe that such a board would be a good mechanism to achieve the
Commission's goal, they also state that some requirements on how such a
board should be structured are necessary. For example, California Munis
state that stakeholder board members should not form a majority of an
RTO's or ISO's board under a hybrid board form of governance.\251\ SMUD
states that a hybrid board should include diverse representation and
must be properly balanced so that no single interest is unduly
influential.\252\ TAPS recommends that within a hybrid board,
independent directors should hold a majority of board seats to prevent
capture by stakeholders.\253\ Further, before implementing the hybrid
board approach, the Connecticut and Massachusetts Municipals recommend
that the Commission provide clarity regarding any possible conflict of
interest concerns among stakeholder directors.\254\
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\250\ E.g., California Munis at 15; Silicon Valley Power at 15;
Connecticut and Massachusetts Municipals at 16; Wisconsin Industrial
at 11; TAPS at 34; Industrial Consumers at 40.
\251\ California Munis at 15.
\252\ SMUD at 21.
\253\ TAPS at 34.
\254\ Connecticut and Massachusetts Municipals at 17.
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256. Industrial Consumers recommend that the Commission require
each RTO or ISO to establish a hybrid board, but only if
representatives of loads (large and small customers) are assured equal
representation with
[[Page 12609]]
supply-side interests. They note that Electric Reliability Council of
Texas (ERCOT) already has a hybrid board.\255\ Industrial Consumers
propose that non-independent stakeholder members should represent less
than half of the total ISO and RTO board (unlike in ERCOT). They add
that an equal number of stakeholders should represent supply-side and
demand-side (consumer) interests.\256\ To that end, Industrial
Consumers state that it may be necessary to require some form of
rotation among stakeholder groups. Finally, they note that all existing
ISO and RTO boards already have a ``hybrid'' feature because some
members are retired utility executives, and they urge the Commission to
consider counting such members as stakeholders in hybrid boards.
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\255\ Industrial Consumers note that the ERCOT hybrid board is
composed of the following: (1) Five unaffiliated independent board
members (two serve as chair and vice chair); (2) independent power
marketers; (3) industrial consumers; (4) commercial consumers; (5)
independent retail electric providers; (6) electric cooperatives;
(7) residential consumers; (8) investor-owned utilities; (9)
independent generators; and (10) municipally-owned utilities.
Industrial Consumers at 41.
\256\ For example, a ten-member board would have four
stakeholder members: two representing suppliers and two representing
consumers. Id.
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257. Wisconsin Industrial also recommends a hybrid board structure,
with the condition that end-use customer and supplier representation be
equal. Wisconsin Industrial believes that a hybrid board has an
advantage in that a variety of stakeholder interests can be objectively
and directly represented without first being filtered through RTO and
ISO management.\257\
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\257\ Wisconsin Industrial at 11.
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258. Further, several of the commenters that support the hybrid
board oppose the advisory board committee, noting that such a committee
would not provide for direct discussion and information exchange, and
that its advice could be ignored by board members.\258\ Others note the
disadvantages of an advisory board committee.\259\
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\258\ E.g., TAPS at 40-42.
\259\ For example, Indianapolis P&L notes that, while the
Midwest ISO advisory committee provides some value, it faces
challenges in its communication with the board of directors because
management views are sometimes at odds with stakeholder views, the
time for the advisory committee to consult with the board on
technically complex issues is limited, and competing messages from
committee members dilute and muddle the message. Indianapolis P&L at
6-7.
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259. Many commenters, however, do not support the hybrid board
approach, emphasizing that a hybrid board can, among other things,
jeopardize the independence of an RTO or ISO board.\260\ They contend
that RTO and ISO independence must be preserved because it gives
participants in organized wholesale markets the confidence that: (1)
The markets are being administered fairly; (2) proprietary and critical
infrastructure information is being protected; and (3) customers will
ultimately receive the benefits of competition.
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\260\ E.g., California PUC at 34-35; DC Energy at 9; Comverge at
12; Dominion Resources at 10; Duke Energy at 29; Dynegy at 7;
FirstEnergy at 12; Industrial Coalitions at 27; ITC at 5-13; Joint
Consumer Advocates at 24; North Carolina Commission at 8; OMS at 42;
NARUC at 12; Old Dominion at 31; Pepco at 22; The Alliance at 19;
Xcel at 27.
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260. Many commenters argue that stakeholder representation on a
hybrid board would conflict with stakeholders' fiduciary responsibility
to their employers, making it difficult for the stakeholder member to
be impartial when the goal of that member's organization is to maximize
its company's profits. Therefore, they note that it is unrealistic to
expect stakeholder board members to refrain from acting in the best
interests of the entity with which they are affiliated.
261. Some commenters also question whether a hybrid board can
ensure fair representation, arguing that smaller companies are less
likely to have the resources necessary to participate in such a
board,\261\ thus not all sectors of the market would be fairly
represented, resulting in the potential for undue influence.
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\261\ E.g., Comverge at 12; Industrial Coalitions at 25-28; The
Alliance at 19-20.
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262. To address those concerns for undue influence, commenters have
suggested that the selection of non-independent board members should
require a supermajority vote. APPA recommends that RTO and ISO
stakeholder directors be elected by a supermajority of stakeholder
sectors, contending that stakeholder representatives should be balanced
between generation and load interests.\262\ APPA further expands on its
proposal by stating that using a supermajority election process will
``ensure that well-respected and knowledgeable members of the
stakeholder community serve in this capacity.'' \263\ TAPS suggests
that a supermajority vote requirement for selection of stakeholder
board members would go a long way to mitigate concerns that the
stakeholder board members would use their position inappropriately to
advance their parochial interests.\264\
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\262\ APPA at 13.
\263\ Id. at 93.
\264\ TAPS at 45. Both APPA and TAPS reference a similar
recommendation from a Wisconsin Public Power Inc. (WPPI) white
paper, contained as Attachment A to the TAPS comments. WPPI suggests
that ``selection of the interested [non-independent] board members
should require supermajority voting approval'' and that ``an
election of an interested board member should require an affirmative
vote of 67 [percent] of all sectors.'' Id. at 70.
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263. Further, some commenters contend that a hybrid board composed
of both independent and stakeholder members could complicate and impede
effective board decision-making because of the effort of non-
independent stakeholders to serve their own interests.\265\ They note
that a hybrid board is far more likely to be unwieldy and ineffective
because of the need to represent so many different market interests.
Several commenters also argue that the Commission does not have the
legal authority to dictate the composition of the board of a
Commission-regulated entity.\266\
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\265\ E.g., Alcoa at 28; DC Energy at 10; California PUC at 35.
\266\ See, e.g., California PUC at 35 (citing Cal. Indep. Sys.
Operator Corp. v. FERC, 372 F.3d 395 (DC Cir. 2004)).
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b. Comments on the Board Advisory Committee Approach
264. Many commenters indicate that having a board advisory
committee is the preferable approach to achieving the Commission's goal
of improving responsiveness of RTOs and ISOs.\267\ They state that a
board advisory committee with a wide range of stakeholder interests
that has direct access to the board of directors would increase RTO and
ISO responsiveness and be the most effective way to balance the
interests of stakeholders.
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\267\ E.g., California PUC at 36; Comverge at 12; Suez at 9; Old
Dominion at 31; OPSI at 42; Joint Consumer Advocates at 24; North
Carolina Commission at 9; NARUC at 12; Pepco at 22-23; Xcel at 27-
28.
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265. Several commenters state that a board advisory committee would
be a good starting point for improving communications between the board
and stakeholders. For example, North Carolina Electric Membership
believes that a board advisory committee would allow stakeholders to
provide and receive strategic insight to the boards.\268\ In addition
to such a committee, it notes the need for more opportunities for
communication between the board and the stakeholders. Such
communication can be achieved by board member attendance at major
stakeholder meetings and by board solicitation of stakeholder position
papers on relevant
[[Page 12610]]
issues.\269\ A few of the commenters also note that they support open
RTO and ISO board meetings.\270\
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\268\ North Carolina Electric Membership at 4.
\269\ For example, North Carolina Electric Membership suggests
``town hall'' sessions for members where board attendance is
required on topics derived by the liaison committee (i.e., board
advisory committee). It also notes that requiring the board to
explain the basis for its decision on particular issues in writing
could improve communication and add transparency to the process.
North Carolina Electric Membership at 5.
\270\ For example, the OMS believes that an open board meeting
would allow stakeholders to assess the nature and quality of the
information being provided to the board, whether the board has
adequately understood and considered stakeholder issues and
concerns, and whether the board has made a fair and balanced
decision. OMS at 43. In contrast, SMUD does not support open board
meetings, but suggests that a better alternative may be for boards
to hold technical sessions with stakeholders for information
gathering before board meetings take place. SMUD at 22.
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266. Some commenters suggest guidelines on how a board advisory
committee should be structured and how it should function. For example,
OPSI states that the board advisory committee: (1) Must have authority
to make recommendations directly to the board on matters before the
board and on matters it believes the board should address; (2) must be
required to allow for the communication of minority views to the board;
and (3) should have membership limited to a reasonable number of
individuals.\271\ OPSI and NARUC recommend that state commissions and
state consumer advocates be entitled to representation on the board
advisory committee.\272\ North Carolina Commission proposes that the
board advisory committee should be given the right to suggest nominees
to board positions and that the RTO and ISO board could be required to
respond in writing to proposals submitted by the advisory committee.
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\271\ OPSI at 43.
\272\ Id. See also NARUC at 12.
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267. Additionally, LPPC states that a board advisory committee must
be closely involved in RTO and ISO board discussions, must represent a
broader range of stakeholder interests, and should supplement, not
replace, existing stakeholder representation on operating technical
committees.\273\
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\273\ LPPC at 17. See also Industrial Consumers at 41
(suggesting that a board advisory committee should be balanced, be
charged with electing the board members, and be responsible for
approving any changes in the bylaws).
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c. Comments on the Need To Increase Management Responsiveness
268. APPA, TAPS, and the Connecticut and Massachusetts Municipals
recommend that RTO and ISO mission statements and/or charters clearly
define consumer-oriented goals. They recommend that these documents be
modified to require the RTO or ISO to provide ``reliable service at the
lowest possible reasonable rates,'' \274\ or similar wording to that
effect. APPA would include an explicit obligation that the RTO or ISO
work to reduce power costs to consumers.
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\274\ TAPS at 33.
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269. Several commenters also addressed the topic of performance
criteria for executive managers' responsiveness to stakeholder and
consumer interests. For example, DC Energy supports the Commission
requiring each RTO and ISO to take steps to ensure management
responsiveness, such as stakeholder input on public strategic plans,
periodic measurement of customer satisfaction, and RTO- or ISO-
developed performance criteria for executive managers with a focus on
reliability and market efficiency criteria.\275\ North Carolina
Commission suggests the Commission focus on measures of responsiveness
such as timely responses to customer or stakeholder requests.\276\ The
North Carolina Commission also suggests that the Commission should
focus on behavior-based measures to improve RTO and ISO effectiveness,
such as whether the RTO and ISO has clear staff assignments; whether it
has contact information easily available on its Web site; the length of
time for a stakeholder to secure an answer to a question; how long it
takes a market participant to receive a correction of a billing or
settlement error; and how often transmission service or interconnection
studies are delayed. LPPC suggests four areas that should be covered in
performance measures include accomplishment of the mission, ability to
meet budget projections, compliance with NERC standards, and measured
stakeholder satisfaction.\277\ CAISO supports Commission adoption of
performance criteria for executive managers, stating that it has
already implemented most of the ANOPR proposals, including an incentive
compensation program for all employees that contains specific goals for
improving stakeholder processes and timely response to stakeholder
inquiries.\278\
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\275\ DC Energy at 10.
\276\ North Carolina Commission at 9-10.
\277\ LPPC at 19.
\278\ CAISO at 14.
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d. Comments on Regional Differences
270. In addition to the two approaches described in the ANOPR,
several commenters suggest that the Commission should allow for
regional differences, and not administer a one-size-fits-all
approach.\279\ Instead, given the differences among RTOs and ISOs in
governance and stakeholder needs, the Commission should require RTOs
and ISOs to work with customers and other stakeholders to create
programs specific to each regional entity. For example, EEI notes that
it is important that each RTO and ISO have the flexibility to adopt the
means of direct stakeholder access that is most effective for that
particular RTO or ISO.\280\ NARUC also notes that stakeholder
representation in RTO and ISO processes is not uniform across all
sectors; therefore, it urges the Commission to review RTO and ISO
processes to ensure equivalent treatment of all stakeholders.\281\
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\279\ E.g., Allegheny at 7; ISO-NE at 31-33; EPSA at 50; Pepco
at 23; SPP at 12-13; National Grid at 17-20; EEI at 57-61.
\280\ EEI recommends that the Commission issue a policy
statement declaring that stakeholders should have effective direct
access to RTO and ISO boards and executive management. It also
argues that ``the Commission should not take any action that would
require the basic structure of RTOs and ISOs and their underlying
governing contracts, such as the transmission owners' agreement, to
be reopened without the consent of the parties involved.'' EEI at
59.
\281\ NARUC at 13.
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271. OPSI recommends that the Commission not impose particular
mandates, but should express its intention to hold RTO and ISO boards
accountable, and leave it to the boards to develop appropriate ways to
ensure such responsiveness. OPSI also urges the Commission to establish
an annual opportunity for interested parties to submit an assessment of
the RTO's or ISO's performance in the preceding year to the
Commission.\282\
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\282\ OPSI at 45.
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4. The Need for Commission Action
272. In Order No. 2000, the Commission determined that independence
is a required characteristic necessary for an RTO to prevent any undue
discrimination and to bring benefits to market participants. In that
respect, the Commission stated that an RTO's decision-making process
must be independent in both reality and perception.\283\ The Commission
did not believe that detailed guidance regarding governance structure
was necessary given the early stage of RTO formation and the varying
structures of governance among regional entities. Instead, the
Commission required RTOs to have an ``open architecture'' so that the
organization and its members would have the necessary flexibility to
improve the structure, geographic scope, market scope, and operations
of the
[[Page 12611]]
organization. Although the Commission required that proposed changes
continue to satisfy RTO minimum characteristics and functions,\284\
open architecture allowed the original RTO design to evolve to reflect
changes in member needs.
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\283\ Order No. 2000, FERC Stats. & Regs. ] 31,089 at 31,061.
\284\ Id. at 31,170.
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273. Since Order No. 2000 was issued, RTOs and ISOs have evolved.
Given the size and complexity of RTOs and ISOs today, it is not
surprising that tension has arisen between the goals of independent
decision-making and responsiveness to stakeholders, as an RTO or ISO
cannot satisfy every group on every issue. The RTO and ISO management
and boards of directors face increasing difficulty (as well as
increasing responsibility) in understanding the impact of their
decisions on the various stakeholder classes. Attempting to accommodate
stakeholders' needs on each issue has been a difficult task borne by
the boards and other employees of the RTOs and ISOs.
274. Creating a mechanism and process to enable the board to be
responsive to the needs of stakeholders is critical to an independent
governance structure. Moreover, it is necessary for customers and other
stakeholders to have confidence in the decisions that come out of RTO
and ISO processes. Similarly, management responsiveness to customers
and stakeholders plays an important role in implementing the RTO and
ISO policies and achieving its objectives in a manner that customers
and other stakeholders perceive to be fair, balanced, and effective.
The Commission proposes a set of criteria, discussed below, for
assessing the mechanism or process by which an RTO or ISO achieves
board responsiveness to its members and customers.
5. Proposed Reform
275. The Commission proposes to require each RTO and ISO to
demonstrate in a compliance filing that it is achieving RTO and ISO
responsiveness, and we propose to assess the filed practices or
procedures for achieving RTO and ISO board responsiveness using the
following criteria: (1) Inclusiveness; (2) fairness in balancing
diverse interests; (3) representation of minority positions; and (4)
ongoing responsiveness. We believe that access by customers and other
stakeholders to the board based on these criteria will provide them
with the opportunity to ensure that their concerns are considered. We
also believe that any RTO or ISO practices or procedures that satisfy
these criteria will ensure that RTO and ISO boards and management are
reasonably responsive to the needs of RTO and ISO members and
customers.
276. Accordingly, an RTO or ISO must comply with this proposed
requirement by submitting a filing that proposes changes to its
responsiveness practices and procedures to comply with the proposed
requirement or that demonstrates its practices and procedures already
satisfy the requirement for responsiveness. This filing would be
submitted within six months of the date the final rule is published in
the Federal Register. The Commission will assess whether each filing
satisfies the proposed requirement and issue additional orders as
necessary.
277. The Commission agrees with commenters that a one-size-fits-all
approach may not be beneficial given the varying structure and needs of
each regional entity. Therefore, instead of prescribing a specific
mechanism for all RTOs and ISOs, the Commission proposes to take a
flexible approach. Various mechanisms may satisfy the proposed
criteria. We encourage each RTO or ISO to develop a mechanism that best
suits its own governance structure and stakeholder needs. The
Commission presented two options for consideration, the board advisory
committee and the hybrid board.\285\ While we view the board advisory
committee as a particularly strong mechanism for enhancing
responsiveness, the Commission expects each RTO or ISO and its
stakeholders to develop the mechanism that best suits its needs.
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\285\ Any RTO or ISO that chooses to propose a hybrid board
structure must ensure that the non-independent board members
constitute less than a majority of the board and must limit the
eligibility to be a non-independent board member to market
participants in that RTO or ISO market.
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278. We seek comment, however, on whether RTOs and ISOs should be
encouraged, or required, to base their process for selecting non-
independent members of the board or of a board advisory committee on a
supermajority vote of eligible stakeholders.
279. We propose to require each RTO and ISO, in its compliance
filing, to demonstrate that it has satisfied the following criteria:
Inclusiveness--The practices and procedures must ensure
that any customer or other stakeholder affected by the operation of the
RTO or ISO, or its representative is permitted to communicate its views
to the RTO or ISO board.
Fairness in Balancing Diverse Interests--The practices and
procedures must ensure that the interests of customers or other
stakeholders are equitably considered and that deliberation and
consideration of RTO and ISO issues are not dominated by any single
stakeholder category.
Representation of Minority Positions--The practices and
procedures must ensure that, in instances where stakeholders are not in
total agreement on a particular issue, minority positions are
communicated to the board at the same time as majority positions.
Ongoing Responsiveness--The practices and procedures must
provide for stakeholder input into RTO or ISO decisions as well as
mechanisms to provide feedback to stakeholders to ensure that
information exchange and communication continue over time.
280. The Commission proposes to require that each RTO and ISO post
on its Web site a mission statement or charter for its organization.
The Commission encourages each RTO and ISO to set forth in these
documents the organization's purpose, guiding principles, and
commitment to responsiveness to customers and other stakeholders, and
ultimately to the consumers who benefit from and pay for electricity
services.
281. We also encourage each RTO and ISO to ensure that its
management programs, including, but not limited to, incentive
compensation plans for executive managers, give appropriate weight to
stakeholder responsiveness. Such plans should give appropriate
consideration to important service delivery goals such as reducing
congestion costs, timely response to transmission service requests,
prompt resolution of statements, billing, and disputes, and other
customer service measures of performance.\286\
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\286\ The Commission understands that RTO and ISO executive
management compensation plans may already be based on various
measures of performance. If these already adequately take account of
customer responsiveness, the RTO or ISO may report this in its
compliance filing.
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V. Applicability of the Proposed Rule and Compliance Procedures
282. The Commission has a responsibility under FPA sections 205 and
206 to ensure that the rates, charges, classifications, and service of
public utilities (and any rule, regulation, practice, or contract
affecting any of these) are just and reasonable and not unduly
discriminatory, and to remedy undue discrimination in the provision of
such services. Our action in this NOPR proposes to fulfill those
responsibilities by proposing reforms to improve the operation of
organized
[[Page 12612]]
wholesale markets. It is necessary to remedy any problems in wholesale
markets to ensure that rates and services in RTO and ISO markets remain
just and reasonable and not unduly discriminatory.
283. The Commission proposes to apply the final rule in this
proceeding to all RTOs and ISOs by requiring them to demonstrate
compliance with the proposed requirements discussed in each section of
the NOPR: (1) Demand response; (2) long-term power contracting; (3)
market monitoring; and (4) RTO and ISO responsiveness. The Commission
proposes to require each RTO and ISO to report to the Commission, on
the deadlines specified below or six months following its certification
as an RTO or commencement of operations as an ISO, that describes
whether the entity is already in compliance with the requirements of
the final rule, or describing its plans to attain compliance, including
a timeline with intermediate deadlines and appropriate proposed tariff
and market rule revisions. The Commission will assess whether each
filing satisfies the proposed requirements and issue further orders for
each RTO and ISO.
284. For the proposed requirements under demand response, the
filing addressing ancillary services and deviation charges, and the
filing for ARCs and shortage pricing must be submitted within six
months of the date the final rule is published in the Federal Register.
285. The filing to comply with the proposed requirements regarding
long-term contracts, MMU reforms and RTO responsiveness must be
submitted within six months of the date the final rule is published in
the Federal Register.
VI. Information Collection Statement
286. The Office of Management and Budget (OMB) regulations require
approval of certain information collection requirements imposed by
agency rules.\287\ Upon approval of a collection(s) of information, OMB
will assign an OMB control number and an expiration date. Respondents
subject to the filing requirements of this rule will not be penalized
for failing to respond to these collections of information unless the
collections of information display a valid OMB control number. This
NOPR amends the Commission's regulations to improve the operation of
organized wholesale electric power markets. The objective of this
proposed rule is to improve market design and competition in organized
markets. Through this rule the Commission hopes to provide remedies by
ensuring (1) that new criteria are established so RTOs and ISOs are
responsive to their customers and stakeholders; (2) improve market
monitoring within RTOs and ISOs by requiring them to provide their
Market Monitoring Units with access to market data and sufficient
resources to perform their duties; (3) transparency in the marketplace
by requiring RTOs and ISOs to dedicate portions of their Web sites so
market participants can avail themselves of information concerning
offers to buy or sell power on a long-term basis; and (4) require RTOs
and ISOs to institute certain reforms in the demand response programs
to remove several disincentives and barriers to provide for more
efficient operation of markets while at the same time encouraging new
technologies. Filings by RTOs and ISOs would be made under Part 35 of
the Commission's regulations. The information provided for under Part
35 is identified as FERC-516.
---------------------------------------------------------------------------
\287\ 5 CFR 1320.11 (2007).
---------------------------------------------------------------------------
287. The Commission is submitting these reporting requirements to
OMB for its review and approval under section 3507(d) of the Paperwork
Reduction Act.\288\ Comments are solicited on the Commission's need for
this information, whether the information will have practical utility,
the accuracy of provided burden estimates, ways to enhance the quality,
utility, and clarity of the information to be collected, and any
suggested methods for minimizing the respondent's burden, including the
use of automated information techniques.
---------------------------------------------------------------------------
\288\ 44 U.S.C. 3507(d) (2000).
---------------------------------------------------------------------------
Burden Estimate: The Public Reporting burden for the requirements
contained in the NOPR is as follows:
----------------------------------------------------------------------------------------------------------------
Number of Number of Hours per Total annual
Data collection respondents responses response hours
----------------------------------------------------------------------------------------------------------------
FERC-516 Task Allow demand response to provide 6 1 433 2,598
certain ancillary services.....................
Remove certain deviation charges................ 5 1 288 1,440
Permit aggregation of Retail Customers.......... 6 1 102.5 615
Allow pricing to ration demand during a shortage 6 1 649 3,894
Long-term contract postings..................... 6 1 30 180
MMUs............................................ 6 1 129 774
Require RTO board responsiveness to customers... 6 1 180 1080
Require RTO self-assessment..................... 6 1 650 3,900
---------------------------------------------------------------
Totals...................................... .............. .............. .............. 14,481
----------------------------------------------------------------------------------------------------------------
Total Annual Hours for Collection: (Reporting + recordkeeping, (if
appropriate)) = Total hours for performing tasks 1 through 8 as
identified above = 14,481 hours.
Information Collection Costs: The Commission seeks comments on the
costs to comply with these requirements. It has projected the average
annualized cost to be:
Legal expertise = $473,526 (2,368 hours @ $200 an hour)
Technical Expertise = $712,038 (4,747 hours @ $150 an hour) (RTO/ISO
Senior Staff, Stakeholder participants)
Administrative Support = $108,701 (2,718 hours @ $40 an hour)
IT Support = $236,448 (2,489 hours @ $95 an hour)
Participatory Expenditures = $2,160,000 (96 participants @ $1,000 per
day on average 4.5 days per activity for five of the eight activities
identified above)
Total = $3,690,713
* Differences in RTO/ISO staff hourly rates are to differentiate
between administrative support staff and senior staff.
Total cost estimates: $3,690,713.
Title: FERC-516 ``Electric Rate Schedule Filings''.
Action: Proposed Collections.
OMB Control No: 1902-0096.
Respondents: Business or other for profit, and/or not for profit
institutions.
Frequency of Responses: One time to initially comply with the rule,
and then
[[Page 12613]]
on occasion as needed to revise or modify.
Necessity of the Information: This proposed rule, if adopted, would
further the improvement of competitive wholesale electric markets and
the provision of transmission services in the RTO and ISO regions. The
Commission recognizes that significant differences exist among the
regions, industry structures, and sources of electric generation,
population demographics and even weather patterns. In fulfilling its
responsibilities under sections 205 and 206 of the Federal Power Act,
the Commission is required to address, and has the authority to remedy,
undue discrimination and anticompetitive effects.
Internal review: The Commission has reviewed the requirements
pertaining to transmission organizations with organized electricity
markets and determined the proposed requirements are necessary to meet
the provisions of the Federal Power Act.
288. These requirements conform to the Commission's plan for
efficient information collection, communication and management within
the energy industry. The Commission has assured itself, by means of
internal review, that there is specific, objective support for the
burden estimates associated with the information requirements.
289. Interested persons may obtain information on the reporting
requirements by contacting: Federal Energy Regulatory Commission, 888
First Street, NE., Washington, DC 20426, Attention: Michael Miller,
Office of the Executive Director, Phone: (202) 502-8415, fax: (202)
273-0873, e-mail: [email protected]. Comments on the requirements
of the proposed rule may also be sent to the Office of Information and
Regulatory Affairs, Office of Management and Budget, Washington, DC
20503, Attention: Desk Officer for the Federal Energy Regulatory
Commission, fax (202) 395-7285, e-mail: [email protected].
VII. Environmental Analysis
290. The Commission is required to prepare an Environmental
Assessment or an Environmental Impact Statement for any action that may
have a significant adverse effect on the human environment.\289\ The
Commission concludes that neither an Environmental Assessment nor an
Environmental Impact statement is required for this NOPR under section
380.4(a)(15) of the Commission's regulations, which provides a
categorical exemption for approval of actions under sections 205 and
206 of the FPA relating to the filing of schedules containing all rates
and charges for the transmission or sale subject to the Commission's
jurisdiction, plus the classification, practices, contracts, and
regulations that affect rates, charges, classifications, and
services.\290\
---------------------------------------------------------------------------
\289\ Regulations Implementing the National Environmental Policy
Act, Order No. 486, FERC Stats. & Regs. ] 30,783 (1987).
\290\ 18 CFR 380.4(a)(15) (2007).
---------------------------------------------------------------------------
VIII. Regulatory Flexibility Act Certification
291. The Regulatory Flexibility Act of 1980 (RFA) \291\ generally
requires a description and analysis of rules that will have significant
economic impact on a substantial number of small entities. Most, if not
all, of the transmission organizations to which the requirements of
this rule would apply do not fall within the definition of small
entities.\292\
---------------------------------------------------------------------------
\291\ 5 U.S.C. 601-12 (2000).
\292\ The RFA definition of ``small entity'' refers to the
definition provided in the Small Business Act, which defines a
``small business concern'' as a business that is independently owned
and operated and that is not dominant in its field of operation. See
5 U.S.C. 601(3), citing to Section 3 of the Small Business Act, 15
U.S.C. 632 (2000). The Small Business Size Standards component of
the North American Industry Classification system defines a small
utility as one that, including its affiliates is primarily engaged
in the generation, transmission, or distribution of electric energy
for sale, and whose total electric output for the preceding fiscal
years did not exceed 4 MWh. 13 CFR 121.202 (Sector 22, Utilities,
North American Industry Classification System, NAICS) (2004).
---------------------------------------------------------------------------
Those entities to be impacted directly by this rule include the
following:
California Independent Service Operator Corp. (CAISO) is a
nonprofit organization comprised of more than 90 electric transmission
companies and generators operating in its markets and serving more than
30 million customers.
New York Independent System Operator, Inc. (NYISO) is a
nonprofit organization that oversees wholesale electricity markets
serving 19.2 million customers. NYISO manages a 10,775-mile network of
high-voltage lines.
PJM Interconnection, LLC (PJM) is comprised of more than
450 members including power generators, transmission owners,
electricity distributors, power marketers and large industrial
customers and serving 13 states and the District of Columbia.
Southwest Power Pool, Inc. (SPP) is comprised of 50
members serving 4.5 million customers in 8 states and has 52,301 miles
of transmission lines.
Midwest Independent Transmission System Operator, Inc.
(Midwest ISO) is a nonprofit organization with over 131,000 megawatts
of installed generation. Midwest ISO has 93,600 miles of transmission
lines and serves 15 states and one Canadian province.
ISO New England Inc. (ISO-NE) is a regional transmission
organization serving 6 states in New England. The system is comprised
of more than 8,000 miles of high voltage transmission lines and several
hundred generating facilities of which more than 350 are under ISO-NE's
direct control.
Therefore, the Commission certifies that this rule will not have a
significant economic impact on a substantial number of small entities.
Accordingly, no regulatory flexibility analysis is required.
IX. Comment Procedures
292. The Commission invites interested persons to submit comments
on the matters and issues proposed in this notice to be adopted,
including any related matters or alternative proposals that commenters
may wish to discuss. Comments are due April 21, 2008. Comments must
refer to Docket Nos. AD07-7-000 and RM07-19-000, and must include the
commenter's name, the organization they represent, if applicable, and
their address in their comments.
293. The Commission encourages comments to be filed electronically
via the eFiling link on the Commission's Web site at http://www.ferc.gov. The Commission accepts most standard word processing
formats. Documents created electronically using word processing
software should be filed in native applications or print-to-PDF format
and not in a scanned format. Commenters filing electronically do not
need to make a paper filing.
294. Commenters that are not able to file comments electronically
must send an original and 14 copies of their comments to: Federal
Energy Regulatory Commission, Secretary of the Commission, 888 First
Street, NE., Washington, DC 20426.
295. 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 on this proposal are
not required to serve copies of their comments on other commenters.
X. Document Availability
296. In addition to publishing the full text of this document in
the Federal Register, the Commission provides all interested persons an
opportunity to view and/or print the contents of this document via the
Internet through FERC's Home Page (http://www.ferc.gov)
[[Page 12614]]
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.
297. From FERC's Home Page on the Internet, this information is
available on eLibrary. The full text of this document is available on
eLibrary in PDF and Microsoft Word format for viewing, printing, and/or
downloading. To access this document in eLibrary, type the docket
number excluding the last three digits of this document in the docket
number field.
298. User assistance is available for eLibrary and the FERC's Web
site during normal business hours from FERC Online Support at 202-502-
6652 (toll free at 1-866-208-3676) or e-mail at
[email protected], or the Public Reference Room at (202) 502-
8371, TTY (202) 502-8659. E-mail the Public Reference Room at
[email protected].
List of Subjects in 18 CFR Part 35
Electric power rates, Electric utilities, Reporting and
recordkeeping requirements.
By direction of the Commission. Commissioner Kelly concurring in
part and dissenting in part with a separate statement attached.
Commissioner Wellinghoff concurring with a separate statement attached.
Nathaniel J. Davis, Sr.,
Deputy Secretary.
In consideration of the foregoing, the Commission proposes to amend
part 35, Chapter I, Title 18, of the Code of Federal Regulations, as
follows:
PART 35--FILING OF RATE SCHEDULES AND TARIFFS
1. The authority citation for part 35 continues to read as follows:
Authority: 16 U.S.C. 791a-825r, 2601-2645; 31 U.S.C. 9701; 42
U.S.C. 7101-7352.
2. Amend Sec. 35.28 as follows:
a. Amend paragraph (b) to add paragraphs (b)(4), (b)(5), (b)(6),
and (b)(7).
b. Add a new paragraph (g).
Sec. 35.28 Non-discriminatory open access transmission tariff.
* * * * *
(b) * * *
(4) Demand response means a reduction in the consumption of
electric energy by customers from their expected consumption in
response to an increase in the price of electric energy or to incentive
payments designed to induce lower consumption of electric energy.
(5) Demand response resource means a resource capable of providing
demand response.
(6) An operating reserve shortage means a period when the amount of
available supply falls short of demand plus the operating reserve
requirement.
(7) Market Monitoring Unit (MMU) means the person or entity
responsible for carrying out the market monitoring functions which the
Commission has ordered Commission-approved ISOs and RTOs to perform.
* * * * *
(g) Tariffs and operations of Commission-approved ISOs and RTOs--
(1) Demand response and pricing. (i) Ancillary services provided by
demand response resources. (A) Every Commission-approved ISO and RTO
that operates organized markets based on competitive bidding for energy
imbalance, spinning reserves, supplemental reserves, reactive power and
voltage control, and regulation and frequency response ancillary
services (or its functional equivalent in the Commission-approved ISO's
or RTO's tariff) must accept bids from demand response resources in
these markets for that product on a basis comparable to any other
resources, if the demand response resource meets the necessary
technical requirements under the tariff and submits a bid under the
Commission-approved ISO's or RTO's bidding rules at or below the
market-clearing price, unless the laws or regulations of the relevant
retail regulatory authority do not permit a retail customer to
participate.
(B) The Commission-approved ISO or RTO must allow providers of a
demand response resource to specify the following in their bids:
(1) A maximum duration in hours that the demand response resource
may be dispatched;
(2) A maximum number of times that the demand response resource may
be dispatched during a day; and
(3) A maximum amount of electric energy that the demand response
resource may be required to provide either daily or weekly.
(ii) Removal of deviation charges. A Commission-approved ISO or RTO
with a tariff that contains a day-ahead and a real-time market may not
assess a charge to a purchaser of electric energy in its day-ahead
market for purchasing less power in the real-time market during a real-
time market period for which the Commission-approved ISO or RTO
declares an operating reserve shortage or makes a generic request to
reduce load to avoid an operating reserve shortage.
(iii) Aggregation of retail customers. Commission-approved ISOs or
RTOs must permit a qualified aggregator of retail customers to bid a
demand response on behalf of retail customers directly into the
Commission-approved ISO's or RTO's organized markets, unless the laws
and regulations of the relevant electric retail regulatory authority do
not permit a retail customer to participate.
(iv) Price formation during periods of operating reserve shortage.
(A) Commission-approved ISOs and RTOs must modify their market rules to
allow the market-clearing price during periods of operating reserve
shortage to reach a level that rebalances supply and demand so as to
maintain reliability while providing sufficient provisions for
mitigating market power.
(B) A Commission-approved ISO or RTO may phase in this modification
of its market rules.
(2) Long-term power contracting in organized markets. A Commission-
approved ISO or RTO must provide a portion of its Web site for market
participants to post offers to buy or sell power on a long-term basis.
(3) Market monitoring policies. (i) Commission-approved ISOs and
RTOs must modify their tariff provisions governing their Market
Monitoring Units to reflect the directives provided in Order No.
[insert order number], including the following:
(A) Commission-approved ISOs and RTOs must include in their tariffs
a provision to provide their Market Monitoring Units access to
Commission-approved ISO and RTO market data, resources and personnel to
enable the Market Monitoring Unit to carry out their functions.
(B) The tariff provision must provide the Market Monitoring Unit
complete access to the Commission-approved ISO's and RTO's database of
market information.
(C) The tariff provision must provide that any data created by the
Market Monitoring Unit, including, but not limited to, reconfiguring of
the Commission-approved ISO's and RTO's data, will be kept within the
exclusive control of the Market Monitoring Unit.
(D) The Market Monitoring Unit must report to the Commission-
approved ISO or RTO board of directors, with its management members
removed, or to an independent committee of the Commission-approved ISO
or RTO board of directors. A Commission-approved ISO and RTO that has
both an internal MMU and an external MMU may permit the internal MMU to
report to management and the external MMU to report to the Commission-
approved ISO or RTO board of directors with its management members
removed, or to an
[[Page 12615]]
independent committee of the Commission-approved ISO or RTO board of
directors.
(E) Commission-approved ISOs and RTOs may not alter the reports
generated by the Market Monitoring Unit, or dictate the conclusions
reached by the Market Monitoring Unit.
(F) Commission-approved ISOs and RTOs must consolidate the core
Market Monitoring Unit provisions into one section in their tariffs as
provided in paragraph (g)(6) of this section.
(ii) Functions of Market Monitoring Unit. The Market Monitoring
Unit must perform the following functions:
(A) Evaluate existing and proposed market rules, tariff provisions
and market design elements for their effectiveness and recommend
proposed rule and tariff changes to the Commission-approved ISO or RTO,
to the Commission's Office of Energy Market Regulation staff and to
other interested entities such as state commissions and market
participants.
(B) Review and report on the performance of the wholesale markets
to the Commission-approved ISO or RTO, the Commission, and other
interested entities such as state commissions and market participants
on at least a quarterly basis and submit a more comprehensive annual
state of the market report. The Market Monitoring Unit may issue
additional reports as necessary.
(C) Identify and notify the Commission's Office of Enforcement
staff of instances in which a market participant's or the Commission-
approved ISO's or RTO's behavior may require investigation, including,
but not limited to, suspected rule or tariff violations, market
manipulation, inappropriate dispatch, and suspected violations of
Commission-approved rules and regulations.
(D) The Market Monitoring Unit, whether internal or external, may
not participate in the administration of the Commission-approved ISO's
or RTO's tariff, including mitigation.
(iii) Market Monitoring Unit ethical standards. Commission-approved
ISOs and RTOs must include ethical standards for employees in their
Market Monitoring Units. At a minimum, the ethical standards must
include the following requirements:
(A) Market Monitoring Unit employees must have no material
affiliation with any market participant or affiliate.
(B) Market Monitoring Unit employees must not serve as an officer,
employee, or partner of a market participant.
(C) Market Monitoring Unit employees must have no material
financial interest in any market participant or affiliate with
potential exceptions for mutual funds and non-directed investments.
(D) Market Monitoring Unit employees must not engage in any market
transactions other than the performance of their duties under the
tariff.
(E) Market Monitoring Unit employees must not be compensated for
any expert witness testimony or other commercial services to the
Commission-approved ISO or RTO or to any other party in connection with
any legal or regulatory proceeding or commercial transaction relating
to the Commission-approved ISO or RTO or to the Commission-approved ISO
or RTO markets.
(F) Market Monitoring Unit employees may not accept anything of
value from a market participant in excess of a de minimis amount.
(G) Market Monitoring Unit employees must advise a supervisor in
the event they seek employment with a market participant, and must
disqualify themselves from participating in any matter that would have
an effect on the financial interest of the market participant.
(4) Offer and bid data. (i) Unless a Commission-approved ISO or RTO
obtains Commission approval for a different period, Commission-approved
ISOs and RTOs must release their offer and bid data within three
months.
(ii) Commission-approved ISOs and RTOs may mask the identity of
market participants when releasing offer and bid data.
(5) Responsiveness of Commission-approved ISOs and RTOs.
Commission-approved ISOs and RTOs must adopt business practices and
procedures that achieve Commission-approved ISO and RTO board of
directors' responsiveness to customers and other stakeholders and
satisfy the following criteria:
(i) Inclusiveness. The practices and procedures must ensure that
any customer or stakeholder affected by the operation of the
Commission-approved ISO or RTO, or its representative, is permitted to
communicate its views to the RTO or ISO board;
(ii) Fairness in balancing diverse interests. The practices and
procedures must ensure that the interests of customers or other
stakeholders are equitably considered and that deliberation and
consideration of Commission-approved ISO and RTO issues are not
dominated by any single stakeholder category;
(iii) Representation of minority positions. The practices and
procedures must ensure that, in instances where stakeholders are not in
total agreement on a particular issue, minority positions are
communicated to the board of directors at the same time as majority
positions; and
(iv) Ongoing responsiveness. The practices and procedures must
provide for stakeholder input into RTO or ISO decisions as well as
mechanisms to provide feedback to stakeholders to ensure that
information exchange and communication continue over time.
(6) Compliance filings. All Commission-approved ISOs and RTOs must
make a compliance filing with the Commission as described in Order No.
[insert order number] under the following schedule:
(i) The compliance filing addressing the accepting of bids from
demand response resources in markets for ancillary services on a basis
comparable to other resources, removal of deviation charges,
aggregation of retail customers, shortage pricing during periods of
operating reserve shortage, long-term power contracting in organized
markets, Market Monitoring Units, Commission-approved ISO and RTO board
of directors' responsiveness, and reporting on the study of the need
for further reforms to remove barriers to comparable treatment of
demand response resources must be submitted on or before [insert date
that is six months after date of publication of Final Rule in the
Federal Register].
(ii) A public utility that is approved as a Regional Transmission
Organization under Sec. 35.34 of this part, or that is not approved
but begins to operate regional markets for electric energy or ancillary
services after [insert effective date of Final Rule], must comply with
Order No. [insert order number] and the provisions of paragraphs (g)(1)
through (g)(5) of this section before beginning operations.
Note: The following appendices will not appear in the Code of
Federal Regulations.
Appendix A: Commenter Acronyms Commenters to the ANOPR in Docket Nos.
RM07-19-000 and AD07-7-000
AARP, et al.--AARP; American Antitrust Institute; American
Chemistry Council; American Forest & Paper Association; American
Iron and Steel Institute; American Municipal Power-Ohio; American
Public Power Association; Association of Businesses Advocating
Tariff Equity; Citizen Power; Citizens Utility Board of Illinois;
Coalition of Midwest Transmission Customers; Colorado Office of
Consumer Counsel; Consumer Federation of America; Council of
Industrial Boiler Owners; Democracy and Regulation;
[[Page 12616]]
Electricity Consumers Resource Council; Florida Industrial Power
Users Group; Illinois Industrial Energy Consumers; Illinois Public
Interest Research Group; Industrial Energy Consumers of America;
Industrial Energy Consumers of Pennsylvania; Industrial Energy
Users-Ohio; Louisiana Energy Users Group; Maryland Office of the
People's Counsel; Maryland Public Interest Research Group; Missouri
Industrial Energy Consumers; National Association of State Utility
Consumer Advocates; NEPOOL Industrial Customer Coalition; Office of
the People's Counsel of the District of Columbia; Ohio Hospital
Association, Ohio Manufacturers' Association; Ohio Partners for
Affordable Energy; PJM Industrial Customer Coalition, Portland
Cement Association; Power in the Public Interest, Public Citizen,
Inc.; Public Utility Law Project of New York, Inc.; Steel
Manufacturers Association; West Virginia Energy Users Group;
Wisconsin Industrial Energy Group, Inc.; and Wisconsin Paper
Council.
AEP--American Electric Power Service Corporation.
Alcoa--Alcoa, Inc.
Allegheny Energy--Allegheny Power and Allegheny Energy Supply
Company, LLC.
Ameren--Ameren Services Company.
American Forest--American Forest & Paper Association.
APPA--American Public Power Association.
ATC--American Transmission Company, LLC.
AWEA--American Wind Energy Association.
Blue Ridge--Blue Ridge Power Agency.
BlueStar Energy--BlueStar Energy Services, Inc.
BP Energy--BP Energy Company.
Cal DWR--California Department of Water Resources State Water
Project.
CAISO--California Independent System Operator Corporation.
California Munis--California Municipal Utilities Association.
California PUC--California Public Utilities Commission.
COMPETE Coalition--171 various entities.
COMPETE, et al.--7-Eleven, Inc.; Allegheny Energy, Alliance for
Real Energy Options; Alliance for Retail Choice, Alliance for Retail
Energy Markets; Alliance for Retail Markets; Ardmore Power
Logistics; Professor Ross Baldick, IEEE Fellow, Department of
Electrical and Computer Engineering, The University of Texas at
Austin; Big Lots Stores, Inc.; Nora Mead Brownell, BC Consulting,
former FERC Commissioner and former PaPUC Commissioner; H. Sterling
Burnett, PhD., Senior Fellow, National Center for Policy Analysis;
California Alliance for Competitive Energy Solutions; California
Grocers Association; California Retailers Association; Laura
Chappelle, Attorney, former Chairman, MI PSC; Colorado Independent
Energy Association; Constellation Energy; Comverge, Maryland; DC
Energy, LLC; David W. DeRamus, Partner, Bates White, LLC; Direct
Energy Services, LLC; Richard A. Drom, Partner, Powell Goldstein
LLP; Edison Mission Energy; Electric Power Supply Association;
Electric Power Generation Association; Energy Association of
Pennsylvania; Energy Curtailment Specialists, Inc.; Enermetrix;
Enerwise Global Technologies; Exelon Corporation; FirstEnergy Corp.;
William L. Flynn, Partner, Harris Beach PLLS, former Chairman, NY
PSC; John Hanger, former PaPUC Commissioner; Hess Corp.; William W.
Hogan, Raymond Plank Professor of Global Energy Policy, John F.
Kennedy School of Government, Harvard University; Illinois Energy
Association; Independent Power Producers of New York; JC Penny;
Kimball Resources, Inc.; Jerry J. Langdon, former FERC Commissioner;
LS Power Associates, LP; Luminant; Macy's Inc., Midwest Independent
Power Suppliers; Mirant Corporation; Elizabeth A. Moler, Exelon
Corp., former Chair of FERC; National Energy Marketers Association;
New England Energy Alliance; New England Power Generators
Association, Inc.; Northwest and Intermountain Power Producers
Coalition; NRG Energy, Inc.; Nuclear Energy Institute; PennFuture;
PetSmart, Inc.; Piney Creek LP; PJM Power Providers Group; PowerGrid
Systems, Inc.; PPL Corporation; Priority Power Management, Ltd.;
PSEG Companies; John M. Quain, Buchanan Ingersoll & Rooney PC,
former Chairman of PaPUC; Reliant Energy; Retail Energy Suppliers
Association; Safeway, Inc.; School Project for Utility Rate
Reduction; Sempra Energy; Shell Energy North America; Silicon Valley
Leadership Group; Vernon L. Smith, Nobel Laureate, Professor of
Economics and Law, Chapman University; David A. Svanda, Svanda
Consulting, former MI PSC Commissioner and former President of
NARUC; Glen Thomas, GT Power, former Chairman of PaPUC; Telga
Corporation; Texas Competitive Power Advocates; TXU Energy; Wal-Mart
Stores, Inc.; Western Power Trading Forum; and Pat Wood, III, former
Chairman of FERC and the PUCT.
Comverge--Comverge, Inc.
Connecticut and Massachusetts Municipals--Connecticut Municipal
Electric Energy Cooperative and Massachusetts Municipal Wholesale
Electric Company.
Constellation--Constellation Energy Commodities Group, Inc.;
Constellation NewEnergy, Inc.; and Constellation Generation Group,
LLC.
DC Energy--DC Energy, LLC.
Detroit Edison--Detroit Edison Company.
Dominion Resources--Dominion Resources Services, Inc.
Duke Energy--Duke Energy Corporation.
Dynegy--Dynegy Power Corporation.
EEI--Edison Electric Institute and Alliance of Energy Suppliers.
EnergyConnect--Energy Connect, Inc.
Energy Curtailment--Energy Curtailment Specialists, Inc.
EnerNOC--EnerNOC, Inc.
EPSA--The Electric Power Supply Association.
Exelon--Exelon Corporation.
FTC--Federal Trade Commission.
FirstEnergy--FirstEnergy Service Company, on behalf of
FirstEnergy Solutions Corp. and the transmission and distribution
owning utility subsidiaries of FirstEnergy Corp.: American
Transmission Systems, Inc.; The Cleveland Electric Illuminating
Company; Jersey Central Power and Light Company; Metropolitan Edison
Company; Ohio Edison Company; Pennsylvania Electric Company;
Pennsylvania Power Company; and The Toledo Edison Company.
Mr. Hogan--William W. Hogan and Susan L. Pope.
Indianapolis P&L--Indianapolis Power and Light Company.
Industrial Coalitions--Coalition of Midwest Transmission
Customers; NEPOOL Industrial Customer Coalition; and PJM Industrial
Customer Coalition.
Industrial Consumers--Electricity Consumers Resource Council;
American Iron and Steel Institute; and American Chemistry Council.
ISO-NE--ISO New England, Inc.
ISO/RTO Council--ISO/RTO Council: California Independent System
Operator Corporation; ISO New England, Inc.; the Midwest Independent
Transmission System Operator, Inc.; New York Independent System
Operator, Inc.; PJM Interconnection, LLC; Southwest Power Pool.
ITC--International Transmission Company and Michigan Electric
Transmission Company, LLC.
Integrys--Integrys Energy Services, Inc.
J.Aron, Barclays, Morgan Stanley--J.Aron & Company, Barclays
Capital, and Morgan Stanley Capital Group Inc.
Joint Consumer Advocates--Ohio Consumers Counsel; District of
Columbia Office of the People's Counsel; Pennsylvania Office of
Consumer Advocate; Illinois Citizens Utility Board; Maryland Office
of People's Counsel; and New Jersey Department of the Public
Advocate, Division of Rate Counsel.
Kansas CC--Kansas Corporation Commission.
LPPC--Large Public Power Council.
Massachusetts AG--Massachusetts Attorney General.
Mr. McCullough--Robert McCullough.
Midwest ISO--Midwest Independent Transmission System Operator,
Inc.
Midwest ISO TOs--Midwest ISO Transmission Owners.
Mirant--Mirant Corporation.
NARUC--National Association of Regulatory Utility Commissions.
National Energy Marketers--National Energy Marketers
Association.
National Grid--National Grid USA.
NEPOOL Participants--NEPOOL Participants Committee.
New England Conference--New England Conference of Public
Utilities Commissioners; Connecticut Department of Public Utility
Control; Massachusetts Department of Public Utilities; Massachusetts
Department of Energy Resources; New Hampshire Public Utilities
Commission; Rhode Island Public Utilities Commission; the Vermont
Department of Public Service; and Vermont Public Service Board.
New England Power Generators--New England Power Generators
Association.
New York PSC--New York State Public Service Commission.
NJBPU--New Jersey Board of Public Utilities.
NJ BPU Commissioner Bator--New Jersey Board of Public Utilities
Commissioner Christine V. Bator.
[[Page 12617]]
North Carolina Commission--North Carolina Utilities Commission;
Public Staff--North Carolina Utilities Commission; and the Attorney
General of the State of North Carolina.
North Carolina Electric Membership--North Carolina Electric
Membership Corporation.
Northeast Utilities--Northeast Utilities.
NRECA--National Rural Electric Cooperative Association.
NRG--NRG Energy, Inc.
NSTAR--NSTAR Electric Company.
NYISO--New York Independent System Operator Corp.
NY TOs--New York Transmission Owners.
Ohio PUC--Public Utilities Commission of Ohio.
Old Dominion--Old Dominion Electric Cooperative.
OMS--Organization of MISO States.
OPSI--Organization of PJM States, Inc.
Otter Tail--Otter Tail Power Company.
Pennsylvania PUC--Pennsylvania Public Utilities Commission.
Pepco--Pepco Holdings, Inc.; Delmarva Power & Light Company;
Atlantic City Electric Company; Conectiv Energy Supply Inc.; and
Pepco Energy Services, Inc.
PGC--PGC Electricity Committee.
PG&E--Pacific Gas and Electric Company.
PJM--PJM Interconnection, LLC.
PJM Power Providers--PJM Power Providers Group.
PJM MMU--Independent Market Monitoring Unit of PJM.
Portland Cement--Portland Cement Association.
Portland Cement Association, et al.--Multiple Intervenors; PJM
Industrial Customer Coalition; Connecticut Industrial Energy
Consumers; Industrial Energy Users-Ohio; Mittal Steel USA, Inc.
Potomac Economics--Potomac Economics, Inc.
Power in Public Interest--Power in the Public Interest.
PPL Parties--PPL Parties.
PSEG--PSEG Companies: Public Service Electric and Gas Company;
PSEG Power LLC and PSEG Energy Resources & Trade LLC.
Public Interest Organizations--Center for Energy Efficiency &
Renewable Technologies; Connecticut Office of Consumer Counsel;
Conservation Law Foundation; Delaware Division of the Public
Advocate; Environmental Law & Policy Center; Fresh Energy, Natural
Resources Defense Council; New Hampshire Office of Consumer
Advocate; Office of the Ohio Consumers' Counsel; Pace Energy
Project; Project for Sustainable FERC Energy Policy; Renewable
Northwest Project; Union of Concerned Scientists and West Wind
Wires.
Reliant--Reliant Energy, Inc.
Safeway--Safeway, Inc.
Silicon Valley Power--Silicon Valley Power.
SMUD--Sacramento Municipal Utility District.
SoCal Edison-SDG&E--Southern California Edison Company and San
Diego Gas & Electric.
SPP--Southwest Power Pool, Inc.
Steel Manufacturers--Steel Manufacturers Association.
Steel Producers--Steel Producers.
Strategic Energy--Strategic Energy, LLC.
SUEZ--SUEZ Energy North America, Inc.
TAPS--Transmission Access Policy Study Group.
The Alliance--The Alliance For Retail Energy Markets.
Utility Savings--Utility Savings & Refund, LLC.
Wal-Mart--Wal-Mart Stores, Inc.
Wisconsin Industrial--Wisconsin Industrial Energy Group.
WSPP--WSPP Inc.
Xcel--Xcel Energy Services, Inc., on behalf of Northern States
Power Company; Northern States Power Company; Wisconsin, Public
Service Company of Colorado; and Southwestern Public Service
Company.
United States of America Federal Energy Regulatory Commission
Wholesale Competition in Regions With Organized Electric Markets--
Docket Nos. RM07-19-000 AD07-7-000
Issued February 22, 2008.
KELLY, Commissioner, concurring in part and dissenting in part:
I support many of the efforts enumerated in the Notice of
Proposed Rulemaking (NOPR) which requests comment on proposals to
improve the operation of wholesale electric markets. I believe that
it is extremely important that we ensure that wholesale markets are
competitive thereby allowing the Commission to fulfill our statutory
mandate to ensure adequate and reliable non-discriminatory service
at just and reasonable rates. Unfortunately, I am concerned
regarding the potential impact of several of the proposals related
to demand response, market monitoring, and promoting regional
transmission organization (RTO)/independent system operator (ISO)
responsiveness.
I continue to be troubled by the NOPR's proposal in the Market
Rules Governing Price Formation During Periods of Operating Reserve
Shortage section. This section would attempt to stimulate demand
response by allowing RTOs/ISOs to implement scarcity pricing by
modifying market power mitigation rules in organized markets, such
as raising energy supply offer caps and demand bid caps. I
appreciate the efforts made in the NOPR to address market power
associated with scarcity pricing and to ensure that there is an
adequate record regarding any scarcity pricing proposal, including
soliciting the views of each RTO/ISO market monitor on any proposed
reform in this area. However, these positive changes in the NOPR
proposal have not alleviated my concerns regarding the very real
impacts on customers associated with raising energy supply offer
caps and demand bid caps in emergency situations.
I believe that absent appropriate resource adequacy requirements
and the necessary demand response infrastructure to give consumers
the ability to respond to higher prices, it is not responsible to
allow energy supply offer caps and demand bid caps to rise without
regard to the impacts on consumers. I do not per se oppose scarcity
pricing. However, I believe that there is a crucial timing issue
that we must consider regarding any scarcity pricing proposal. Prior
to implementing scarcity pricing in any market, we must have
resources in place to meet demand. One essential way to accomplish
this goal is through resource adequacy requirements. If a market is
resource adequate, then there will be fewer emergency situations
and, when those emergencies do occur, having demand response in
place will help reduce prices in times of scarcity. Therefore,
resource adequacy requirements and the ability of demand response to
participate in a market go hand in hand with protecting consumers
from market power and thereby making scarcity pricing proposals just
and reasonable.
Some may look at this as a chicken and egg debate where if we
allow energy supply offer caps and demand bid caps to increase
without restraint this will raise prices thereby encouraging
additional generation and demand response to enter the market. On
the other hand, what happens in the meantime to consumers as we
allow prices to rise without restraint and we are still waiting for
these theoretical incentives to building adequate generation and
demand response infrastructure to kick in? We must never lose sight
of the interests of consumers as we engage in this kind of
philosophical debate because they will be the ones who will lose out
if we miscalculate. The necessary generation and demand response
infrastructure must be in place prior to allowing energy supply
offer caps and demand bid caps to rise or be eliminated.
Unfortunately, this is not the case. As Commission staff noted in
the 2006 FERC Staff Demand Response Assessment, advanced metering
currently has low market penetration of less than six percent in the
United States.\293\ This means that consumers do not have the tools
they need in order to make choices regarding rising prices and
respond accordingly.
---------------------------------------------------------------------------
\293\ Assessment of Demand Response and Advanced Metering: Staff
Report, Docket No. AD06-2-000, at 26 (2006) (2006 FERC Staff Demand
Response Assessment).
---------------------------------------------------------------------------
On the issue of market monitoring, I disagree with the NOPR's
proposal to remove market monitors from tariff administration,
particularly market power mitigation. I believe that market
monitoring units (MMUs) should continue to perform mitigation. The
NOPR states that the issue of removing MMUs from mitigation ``proved
to be the most contentious one in the entire market monitoring
section.'' \294\ This is for good reason. As Portland Cement noted
in its comments, ``The MMU's are better positioned to make
determinations regarding the exercise of market power than are the
RTO/ISO staff members who frequently have long standing close
personal relationships with the very market participants whose
actions at times need to be mitigated.'' \295\ Further, I agree with
Portland Cement's statement that having RTO/ISO staff mitigate
creates a much greater conflict of interest than any incidental
[[Page 12618]]
conflict created by having the internal MMU both mitigate and report
on the functioning of the markets.\296\ The New York Independent
System Operator (NYISO) also agrees that the concerns expressed in
support of removing the MMU from mitigation are misplaced.\297\
NYISO further stated that ``[t]here is no reason to fear that a
market monitor would hesitate to report market power problems or
potential market abuses just because it was involved in implementing
mitigation measures in that market.'' \298\ BP Energy asserts that
``shifting the mitigation responsibility to RTO staff gives rise to
a much larger conflict of interest than exists with having
mitigation responsibility lie with the independent MMU
exclusively.'' \299\ Therefore, I disagree with the NOPR's proposal
to remove MMUs from mitigation.
---------------------------------------------------------------------------
\294\ Wholesale Competition in Regions with Organized Electric
Markets, Notice of Proposed Rulemaking, 122 FERC ] 61,617, at P 202
(2008).
\295\ Portland Cement Association Aug. 16, 2007 Comments, Docket
Nos. AD07-7, RM07-19, at 19.
\296\ Id.
\297\ NYISO Sept. 14, 2007 Comments, Docket Nos. AD07-7, RM07-
19, at 23.
\298\ Id. at 24 (citation omitted).
\299\ BP Energy Company Sept. 14, 2007 Comments, Docket Nos.
AD07-7, RM07-19, at 31.
---------------------------------------------------------------------------
Additionally, I would have strengthened the market monitoring
section. For example, the NOPR proposes to retain existing
provisions regarding the confidentiality of the progress and results
of the Commission's own investigations. I believe that, subject to
appropriate confidentiality limitations, the Commission should
provide MMUs with information on referrals that the MMU provides to
the Commission. I would also have supported requiring RTOs/ISOs to
file tariff provisions to allow them to take enforcement action with
respect to objectively identifiable behavior that does not subject
the seller to sanctions or consequence other than those expressly
approved by the Commission and set forth in the tariff and with the
right of appeal, consistent with the Policy Statement on Market
Monitoring Units.\300\
---------------------------------------------------------------------------
\300\ Policy Statement on Market Monitoring Units, 111 FERC ]
61,267, at P 5 (2005) (citation omitted).
---------------------------------------------------------------------------
Further, I disagree with the NOPR's proposal to promote
responsiveness of RTOs/ISOs by allowing them to adopt hybrid boards
with stakeholder members. Providing for stakeholder representatives
on an RTO/ISO board is inconsistent with an independent governing
structure. The Commission has already spoken clearly on the
importance of RTOs/ISOs being independent of market participants.
Having an independent board is the cornerstone of RTO/ISO policy.
Order Nos. 888 \301\ and 2000 \302\ require that an RTO/ISO be
independent from market participants in order to provide regional
transmission and energy market services on a non-discriminatory
basis. If an RTO or ISO adopted a hybrid board, I do not believe
they could be categorized as independent. Additionally, I believe
that an RTO or ISO with a hybrid board jeopardizes the ability of
the Commission to apply the independent entity variation standard
found in Order No. 2003 when considering modifications to such an
RTO or ISO's pro forma Large Generator Interconnection Procedures
(LGIP) and Large Generator Interconnection Agreement (LGIA).\303\
---------------------------------------------------------------------------
\301\ 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. ] 31,036 (1996), order on reh'g,
Order No. 888-A, FERC Stats. & Regs. ] 31,048, 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 sub nom.
Transmission Access Policy Study Group v. FERC, 225 F.3d 667 (DC
Cir. 2000), aff'd sub nom. New York v. FERC, 535 U.S. 1 (2002).
\302\ 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 (DC Cir.
2001).
\303\ Standardization of Generator Interconnection Agreements
and Procedures, Order No. 2003, FERC Stats. & Regs. ] 31,146, at P
26 (2003), order on reh'g, Order No. 2003-A, FERC Stats. & Regs. ]
31,160, order on reh'g, Order No. 2003-B, FERC Stats. & Regs. ]
31,171 (2004), order on reh'g, Order No. 2003-C, FERC Stats. & Regs.
] 31,190 (2005), aff'd sub nom. Nat'l Ass'n of Regulatory Util.
Comm'rs v. FERC, 475 F.3d 1277 (DC Cir. 2007).
---------------------------------------------------------------------------
I also fear that a board with independent and non-independent
members will suffer from a divisive atmosphere with suspicion as to
whether non-independent board members were acting in the best
interests of the RTO/ISO and its customers or in the best interest
of the particular market participant represented by that non-
independent board member. In contrast, I believe that the NOPR's
proposal to encourage RTOs and ISOs to establish a stakeholder
advisory committee would meet the NOPR's goal of improving RTO/ISO
responsiveness without jeopardizing the fundamental independence of
RTOs/ISOs. I also believe consideration should be given to the RTO/
ISO mission statement as a tool to respond to any continuing
stakeholder need for more RTO/ISO accountability.
Finally, I support the long-term power contracting in organized
markets section of the NOPR. I agree with the NOPR's suggestion that
RTOs/ISOs conduct forums on long-term contracts to gather
information and facilitate the exchange of ideas, similar to the one
recently held by PJM. I believe that such forums will allow for an
exchange of ideas on long-term contracting concerns and potentially
foster solutions to these issues. I also agree that Commission staff
should perform an analysis of the level of long-term contracting in
organized market regions.
Accordingly, for the reasons stated above, I concur in part and
dissent in part on this NOPR.
Suedeen G. Kelly.
United States of America Federal Energy Regulatory Commission
Wholesale Competition in Regions With Organized Electric Markets--
Docket Nos. RM07-19-000, AD07-7-000
Issued February 22, 2008.
WELLINGHOFF, Commissioner, concurring:
As the Commission states in this Notice of Proposed Rulemaking
(NOPR), from the commencement of our first technical conference in
this proceeding one year ago, our goal has been to identify specific
reforms that can be made to optimize the efficiency of organized
wholesale electric markets for the benefit of customers and,
ultimately, the consumers who pay for electricity services. This
NOPR marks an important step toward that goal, and I am pleased to
support its issuance.
I would like to draw attention to a few areas of this NOPR, on
which I particularly encourage interested persons to submit
comments.
In this NOPR, the Commission highlights the importance of demand
response to the organized markets. The Commission states that demand
response helps to reduce prices in competitive wholesale markets in
several ways, such as by reducing generator market power and
flattening an area's load profile. The Commission also recognizes
that the need for, and the focus on, demand response will continue
to increase.
The Commission makes several notable proposals in this NOPR
related to demand response. One issue on which I encourage comments
is the Commission's proposal to require each RTO and ISO to accept
bids from demand response resources, on a basis comparable to any
other resources, for ancillary services that are acquired in a
competitive bidding process. The Commission states that this policy
would increase the competitiveness of ancillary services markets,
help reduce the price of ancillary services, and improve the
reliability of the grid. I am interested in hearing from interested
parties whether our proposals in this area are adequate to achieve
those goals.
The Commission also states that we intend to direct our staff to
convene a technical conference shortly after we receive comments on
this NOPR to consider critical issues related to demand response,
such as appropriate compensation for demand response and potential
solutions to remaining barriers to comparable treatment of demand
response. We also propose to require each RTO and ISO to submit a
study on these critical issues within six months of the issuance of
a Final Rule in this proceeding. Those studies would include
proposed solutions along with a timeline for implementation. I
encourage interested parties to provide comments on this approach
and to identify particular issues or areas that should be addressed
in these RTO and ISO studies.
In addition, I strongly encourage interested parties to comment
on the Commission's proposal in this NOPR concerning market rules
that govern price formation during periods of operating reserve
shortage. It is important to note that these are infrequent periods
when more resources, both generation and demand resources, are
needed to maintain reliable electric service to consumers. I
appreciate the extensive comments that we received on this issue in
response to the ANOPR. I believe that this proposal in the NOPR is
an improvement in several respects over the discussion in the ANOPR.
Most notably, the Commission proposes to adopt requirements to
ensure that proposals for pricing during periods of operating
reserve shortage are designed to protect consumers against the
exercise of market power and are supported by an adequate factual
record. More specifically, we propose that a primary criterion for
[[Page 12619]]
approving such pricing proposals would be an adequate record
demonstrating that provisions exist for mitigating market power and
deterring gaming behavior, including, but not limited to, use of
demand resources to discipline bidding behavior to competitive
levels during periods of operating reserve shortage. I am
particularly interested in receiving comments as to whether this and
the other criteria proposed in this NOPR are appropriate, how the
Commission should apply these criteria if we adopt them in a Final
Rule, and whether there are additional criteria that we should
consider in evaluating an RTO's or ISO's proposal for pricing during
a period of operating reserve shortage.
Finally, I would like to note that the Commission in this NOPR
is directing each RTO or ISO to provide a forum for affected
consumers to voice specific concerns (and to propose regional
solutions) about market designs in its particular region, including
concerns as to the value to the market of significant changes to the
market rules. We are also directing our staff to convene a technical
conference on two proposals that were submitted in comments in this
proceeding. Through these and other steps taken in this NOPR, it is
my intention for the Commission to demonstrate how seriously we take
our statement that the proposals in this NOPR do not represent our
final effort to enhance the efficient functioning of competitive
organized markets for the benefit of consumers.
Jon Wellinghoff,
Commissioner.
[FR Doc. E8-3984 Filed 3-6-08; 8:45 am]
BILLING CODE 6717-01-P