[Federal Register: March 7, 2008 (Volume 73, Number 46)]
[Proposed Rules]
[Page 12575-12619]
[DOCID:fr07mr08-31]

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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

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

                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

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

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,

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

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

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

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

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

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

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

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

    \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).
---------------------------------------------------------------------------

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

    \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

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

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

    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.

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

    \55\ BlueStar Energy at 2.
    \56\ Industrial Coalitions at 13-14.
---------------------------------------------------------------------------

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

    \57\ APPA at 48.
    \58\ California PUC at 7.
---------------------------------------------------------------------------

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

    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

activation without undermining the co-optimized market design.
---------------------------------------------------------------------------

    \62\ ISO-NE at 19.
    \63\ NYISO at 32.
---------------------------------------------------------------------------

    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\
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    \64\ EEI at 12.
    \65\ PGC at 10-11.
    \66\ Pepco at 7.
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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.
---------------------------------------------------------------------------

    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

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

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

    \70\ The Commission noted that it would refer to the charge that
it proposed to eliminate during an emergency as a ``deviation
charge.''
---------------------------------------------------------------------------

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

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

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

    \75\ DC Energy at 4.
---------------------------------------------------------------------------

    70. Two commenters raise concerns about the applicability of the
proposal to virtual bidding.\76\ APPA and the

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

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

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

    \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

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

    \85\ APPA at 56; NRECA at 13; EEI at 19; AEP at 4-5; California
Municipals at 8-9.
---------------------------------------------------------------------------

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

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

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

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

    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.

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

    \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).
---------------------------------------------------------------------------

    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

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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    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