[Federal Register Volume 73, Number 46 (Friday, March 7, 2008)]
[Proposed Rules]
[Pages 12576-12619]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: E8-3984]



[[Page 12575]]

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Part IV





Department of Energy





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Federal Energy Regulatory Commission



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18 CFR Part 35



 Wholesale Competition in Regions With Organized Electric Markets; 
Proposed Rules

  Federal Register / Vol. 73, No. 46 / Friday, March 7, 2008 / Proposed 
Rules  

[[Page 12576]]


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DEPARTMENT OF ENERGY

Federal Energy Regulatory Commission

18 CFR Part 35

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


Wholesale Competition in Regions With Organized Electric Markets

Issued February 22, 2008.
AGENCY: Federal Energy Regulatory Commission, DOE.

ACTION: Notice of proposed rulemaking.

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SUMMARY: The Federal Energy Regulatory Commission (Commission) is 
proposing to amend its regulations under the Federal Power Act to 
improve the operation of organized wholesale electric markets in the 
areas of: Demand response and market pricing during a period of 
operating reserve shortage; long-term power contracting; market-
monitoring policies; and the responsiveness of regional transmission 
organizations (RTOs) and independent system operators (ISOs) to 
stakeholders and customers, and ultimately to the consumers who benefit 
from and pay for electricity services. The Commission proposes to 
require that each RTO and ISO make certain filings that propose 
amendments to its tariff, in order to comply with the proposed 
requirements in each area, or that demonstrate that its existing tariff 
and market design already satisfy the requirements. The Commission 
invites all interested persons to submit comments in response to the 
regulations proposed herein.

DATES: Comments are due April 21, 2008.

ADDRESSES: You may submit comments, identified by docket number by any 
of the following methods.
     Agency Web site: http://ferc.gov. Documents created 
electronically using word processing software should be filed in native 
applications or print-to-PDF format and not in a scanned format.
     Mail/Hand Delivery: Commenters unable to file comments 
electronically must mail or hand deliver an original and 14 copies of 
their comments to: Federal Energy Regulatory Commission, Secretary of 
the Commission, 888 First Street, NE., Washington, DC 20426.
    Instructions: For detailed instructions on submitting comments and 
additional information on the rulemaking process, see the Comment 
Procedures Section of this document.

FOR FURTHER INFORMATION CONTACT: David Kathan (Technical Information), 
Office of Energy Market Regulation, Federal Energy Regulatory 
Commission, 888 First Street, NE., Washington, DC 20426, 
[email protected], (202) 502-6404.
    Tina Ham (Legal Information), Office of the General Counsel, 
Federal Energy Regulatory Commission, 888 First Street, NE., 
Washington, DC 20426,[email protected], (202) 502-6224.

SUPPLEMENTARY INFORMATION:

Table of Contents

 
                                                               Paragraph
                                                                numbers
 
I. Introduction.............................................           1
II. Background..............................................          12
III. Proposals To Expand the Scope of the Proceeding........          16
IV. Discussion..............................................          26
    A. Demand Response and Pricing During Periods of                  26
     Operating Reserve Shortages in Organized Markets.......
        1. Background.......................................          27
            a. Importance of Demand Response to Competition           28
             in RTO/ISO Areas...............................
            b. Prior Commission Actions To Address Demand             32
             Response.......................................
        2. The Need for Commission Action...................          37
        3. Proposed Reforms.................................          46
            a. Ancillary Services Provided by Demand                  47
             Response Resources.............................
                i. Preliminary Proposals in the ANOPR.......          47
                ii. Comments on the ANOPR Proposals and               50
                 Questions..................................
                iii. Commission Proposal....................          56
            b. Deviation Charge.............................          65
                i. Preliminary Proposals in the ANOPR.......          65
                ii. Comments on the ANOPR Proposals and               67
                 Questions..................................
                iii. Commission Proposal....................          72
            c. Aggregation of Retail Customers..............          80
                i. Preliminary Proposals in the ANOPR.......          80
                ii. Comments on the ANOPR Proposals and               82
                 Questions..................................
                iii. Commission Proposal....................          86
            d. Potential Future Demand Response Reforms.....          94
            e. Market Rules Governing Price Formation During          97
             Periods of Operating Reserve Shortage..........
                i. Preliminary Proposals in the ANOPR.......          97
                ii. Comments on the ANOPR Proposals and               99
                 Questions..................................
                iii. Commission Proposal....................         107
    B. Long-Term Power Contracting in Organized Markets.....         129
        1. Background.......................................         130
        2. The Need for Commission Action...................         134
        3. Preliminary Proposals in the ANOPR...............         138
        4. Comments on the ANOPR Proposals and Questions....         142
        5. Proposed Reforms.................................         155
    C. Market-Monitoring Policies...........................         162
        1. Background.......................................         163
        2. Prior Commission Actions Regarding Market                 165
         Monitoring.........................................
        3. The Need for Commission Action...................         169
        4. Proposed Reforms.................................         171
            a. Independence and Function....................         172
                i. Structure and Tools......................         173
                ii. Oversight...............................         183

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                iii. Functions..............................         191
                iv. Mitigation and Operations...............         200
                v. Ethics...................................         211
                vi. Tariff Provisions.......................         215
            b. Information Sharing..........................         219
                i. Enhanced Information Dissemination.......         220
                ii. Tailored Requests for Information.......         231
                iii. Commission Referrals...................         238
            c. Pro Forma Tariff.............................         241
                i. Preliminary Proposals in the ANOPR.......         241
                ii. Comments on the ANOPR Proposals and              242
                 Questions..................................
                iii. Commission Proposal....................         243
    D. Responsiveness of RTOs and ISOs to Stakeholders and           245
     Customers..............................................
        1. Background.......................................         247
        2. Preliminary Proposals in the ANOPR...............         249
        3. Comments on the ANOPR Proposals and Questions....         254
            a. Comments on the Hybrid Board Approach........         255
            b. Comments on the Board Advisory Committee              264
             Approach.......................................
            c. Comments on the Need To Increase Management           268
             Responsiveness.................................
            d. Comments on Regional Differences.............         270
        4. The Need for Commission Action...................         272
        5. Proposed Reform..................................         275
V. Applicability of the Proposed Rule and Compliance                 282
 Procedures.................................................
VI. Information Collection Statement........................         286
VII. Environmental Analysis.................................         290
VIII. Regulatory Flexibility Act Certification..............         291
IX. Comment Procedures......................................         292
X. Document Availability....................................         296
 

APPENDIX A: Commenter Acronyms

I. Introduction

    1. The Federal Energy Regulatory Commission (Commission) is 
proposing reforms to improve the operation of organized wholesale 
electric power markets.\1\ Ensuring the competitiveness of organized 
wholesale markets is integral to the Commission fulfilling its 
statutory mandate to ensure adequate and reliable non-discriminatory 
service at just and reasonable rates. Effective competition protects 
consumers by providing greater supply options, encouraging new entry 
and innovation, and encouraging demand response and energy efficiency. 
In the past several years, the Commission has received both formal and 
informal comments from market participants, consumer and industry 
organizations, state regulators, and others recommending improvements 
to competitive wholesale markets.
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    \1\ Organized market regions are areas of the country in which a 
regional transmission organization (RTO) or independent system 
operator (ISO) operates day-ahead and/or real-time energy markets.
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    2. In response to these comments, the Commission held three public 
conferences in 2007 in order to gather more information on competition 
at the wholesale level and other related issues. At the first 
conference on competition issues, held on February 27, 2007, most 
speakers addressed issues affecting the RTO and ISO regions, including 
the levels of wholesale prices, the need for long-term power contracts, 
the effectiveness of market monitoring, and the lack of adequate demand 
response.\2\ On April 5, 2007, the Commission also held a technical 
conference on market monitoring policies and heard from interested 
commenters on issues such as the development of the concept and 
functions of market monitoring and the market monitoring units' (MMU) 
role with respect to the Commission, ISOs and RTOs, and various 
stakeholders.\3\ The Commission then held a second competition 
conference on May 8, 2007, to examine in more detail several specific 
concerns and challenges identified in the first conference. This second 
conference focused on regions with organized markets administered by 
RTOs and ISOs and dealt with: (1) Demand response, including the role 
of demand response during a period of operating reserve shortage; (2) 
fostering long-term power contracting; and (3) the responsiveness of 
RTOs and ISOs to customers and other stakeholders.\4\
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    \2\ See Second Supplemental Notice of Conference, Conference on 
Competition in Wholesale Power Markets, Docket No. AD07-7-000 (Feb. 
26, 2007).
    \3\ See Notice of Agenda for the Conference, Review of Market 
Monitoring Policies, Docket No. AD07-8-000 (Mar. 30, 2007).
    \4\ See Supplemental Notice of Conference, Conference on 
Competition in Wholesale Power Markets, Docket No. AD07-7-000 (Apr. 
19, 2007).
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    3. Based on the record compiled at these three conferences, the 
Commission issued an Advance Notice of Proposed Rulemaking (ANOPR) \5\ 
on June 22, 2007 to identify and implement improvements to specific 
aspects of organized wholesale markets. In the ANOPR, the Commission 
identified four issues in organized market regions that were not being 
adequately addressed or under consideration in other proceedings. These 
areas were: (1) The role of demand response in organized markets and 
greater use of market prices to elicit demand response during a period 
of operating reserve shortage; (2) increasing opportunities for long-
term power contracting; (3) strengthening market monitoring; and (4) 
enhancing the responsiveness of RTOs and ISOs to customers and other 
stakeholders, and ultimately to the consumers who benefit from and pay 
for electricity services.
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    \5\ Wholesale Competition in Regions with Organized Electric 
Markets, Advance Notice of Proposed Rulemaking, 72 FR 36,276 (July 
2, 2007), FERC Stats. & Regs. ] 32,617 (2007).
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    4. The Commission received several thousand pages of comments from 
over a hundred commenters in response to the ANOPR (a list of 
commenters and their abbreviated names the Commission will use for them 
in this document appears in Appendix A).\6\ After review of the 
comments, and pursuant to our responsibility under

[[Page 12578]]

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

[[Page 12579]]

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,

[[Page 12580]]

locational marginal pricing, and a market for financial transmission 
rights.
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    \13\ Cal. Indep. Sys. Operator Corp., 116 FERC ] 61,274 (2006), 
order on reh'g, 119 FERC ] 61,076 (2007).
    \14\ Midwest Indep. Transmission Sys. Operator, Inc., 108 FERC ] 
61,163, order on reh'g, 109 FERC ] 61,157 (2004), order on reh'g 111 
FERC ] 61,043, reh'g denied, 112 FERC ] 61,086 (2005), aff'd sub 
nom. Wisconsin Public Power, Inc. v. FERC, 493 F.3d 239 (DC Cir. 
2007).
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    20. The Commission has also acted on proposals developed by 
regional entities to ensure that adequate price signals exist in the 
market for both short-term and long-term electric power transactions, 
by addressing pricing issues during reserve shortages and by approving 
forward capacity markets. The Commission has approved a demand curve 
for capacity markets in the region operated by NYISO. The Commission 
approved PJM's Reliability Pricing Model to provide an auction process 
for forward capacity contracting. The Commission also approved a 
settlement agreement for ISO-NE to create a transitional forward 
capacity market to meet the needs of its stakeholders.\15\ These 
actions were designed to minimize the disruption during periods of 
operating reserve shortage and encourage new investment in generation, 
while accepting variation between regions and allowing for regional 
choice.
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    \15\ Devon Power, LLC, 115 FERC ] 61,340, order on reh'g, 117 
FERC ] 61,133 (2006), appeal pending sub nom. Maine Pub. Utils. 
Comm'n v. FERC, No. 06-1403 (DC Cir. 2007).
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    21. The Commission has also issued region-specific orders providing 
for cost allocation for new transmission investment, removing 
uncertainty over the cost responsibility for the development of new 
transmission. In Opinion No. 494,\16\ the Commission approved PJM's 
policy for determining recovery of transmission costs for existing and 
new facilities, providing for region-wide cost sharing for certain new 
extra high-voltage transmission facilities. The Commission also 
approved the Midwest ISO's transitional pricing scheme, which 
incorporates cost sharing for new transmission facilities.\17\
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    \16\ PJM Interconnection, LLC, 119 FERC ] 61,063 (2007) (Opinion 
No. 494), reh'g pending.
    \17\ Midwest Indep. Transmission Sys. Operator, Inc., 114 FERC ] 
61,106, order on reh'g and technical conference, 117 FERC ] 61,241 
(2006), order on reh'g, 118 FERC ] 61,208 (2007), appeal pending sub 
nom. Public Service Comm'n of Wisconsin v. FERC, No. 06-1408 (D.C. 
Cir., filed Dec. 13, 2006); Midwest Indep. Transmission Sys. 
Operator, Inc., 118 FERC ] 61,209, order on reh'g, 120 FERC ] 61,080 
(2007).
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    22. In addition to these region-specific actions, the Commission 
has addressed incentives for the building of new generation and 
transmission in all regions with organized markets. In Order No. 
679,\18\ the Commission allowed parties building transmission to apply 
for recovery of prudently incurred costs for construction work in 
progress, pre-operations, and abandoned facilities, and it provided for 
application for an incentive rate of return on equity for new 
transmission investment. As a further means of reducing uncertainty and 
spurring investment, the Commission finalized rules for interconnection 
for large, small and wind generators. These rules remove barriers to 
interconnection by streamlining the process of, and improving 
incentives for, building new generation. The Commission has also acted 
to improve certainty in the cost of transmission for electric customers 
by creating rules for long-term transmission rights in Order Nos. 681 
and 681-A.\19\
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    \18\ Promoting Transmission Investment through Pricing Reform, 
Order No. 679, FERC Stats. & Regs. ] 31,222, order on reh'g, Order 
No. 679-A, FERC Stats. & Regs. ] 31,236 (2006), order on reh'g, 119 
FERC ] 61,062 (2007).
    \19\ Long-Term Firm Transmission Rights in Organized Electricity 
Markets, Order No. 681, FERC Stats. & Regs. ] 31,226, order on 
reh'g, Order No. 681-A, 117 FERC ] 61,201 (2006).
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    23. In Order No. 890, the Commission reformed the open access 
transmission tariff (OATT) to ensure that it continues to provide 
nondiscriminatory access to transmission service. Among other things, 
Order No. 890 requires an open and transparent regional transmission 
planning process.\20\ The Commission is now focusing on the compliance 
phase of OATT reform to ensure that it is implemented properly.\21\ The 
Commission also has been pursuing a cooperative dialogue with the 
National Association of Regulatory Utility Commissioners (NARUC) to 
identify and analyze models for competitive power procurement. This 
effort is designed to enhance the ability of load-serving entities 
(LSEs) to acquire reliable power supplies at competitive prices. As 
noted in the ANOPR, the Commission has also acted to investigate demand 
response in organized markets, through a Commission report and a recent 
technical conference. This conference was designed to examine demand 
response resources in markets, grid operations and expansion, and best 
practices for the measurement and evaluation of demand response 
resources.\22\ The Commission also held a technical conference on 
December 11, 2007 to explore issues surrounding the management of 
interconnection queues.\23\
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    \20\ This addresses, in part, concerns raised by some commenters 
regarding posting of future transmission constraints and congestion 
costs.
    \21\ ANOPR, FERC Stats. & Regs. ] 32,617 at P 33 (citing 
Preventing Undue Discrimination and Preference in Transmission 
Service, Order No. 890, 72 FR 12,266 (Mar. 15, 2007), FERC Stats. & 
Regs. ] 31,241, order on reh'g, Order No. 890-A, FERC Stats. & Regs. 
] 31,261 (2007)).
    \22\ Supplemental Notice, Demand Response in Wholesale Markets, 
Docket No. AD07-11-000 (April 6, 2007).
    \23\ Notice of Technical Conference, Interconnection Queuing 
Practices, Docket No. AD08-2-000 (November 2, 2007).
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    24. In recognition of our continuing respect for regional 
differences in market design, we believe that, if there are specific 
concerns about the market designs in a particular region, they should 
be considered, in the first instance, at the regional level. We 
therefore direct each RTO or ISO to provide a forum for affected 
consumers to voice specific concerns (and to propose regional 
solutions) to the issues raised generically by APPA and AARP, et al. 
Although most existing stakeholder processes already allow for the 
submission of such proposals, we encourage RTOs and ISOs to give 
priority to any significant concerns that may be raised on these 
issues, including concerns as to the value to the market of significant 
changes to the market rules. For example, PJM recently has conducted a 
series of forums on long-term contracts to gather information and 
facilitate the exchange of ideas on this important issue. We encourage 
similar efforts on the concerns raised by APPA and AARP, et al. Any 
proposed solutions should be vetted through the stakeholder process and 
ultimately considered by the boards of the RTOs or ISOs. Ultimately, 
such matters may be brought to the Commission after consideration by 
the region. We encourage each region to commence the consideration of 
any such issues in the near future and not await the issuance of a 
final rule in this proceeding.
    25. However, those entities that have such concerns have a 
responsibility to propose solutions to address those concerns. For 
example, American Forest submitted comments that contained a mechanism, 
the Financial Performance Obligation (FPO), to address concerns that 
they raised regarding the structure of organized markets. Portland 
Cement Association, et al., also included a proposed solution in its 
comments to address their concerns regarding the organized markets. We 
are encouraged by entities that actually propose solutions rather than 
merely identify concerns without proposing any meaningful ways to 
address those concerns. While we do not adopt these proposals in this 
proceeding, we believe that they warrant additional consideration. 
Therefore, as explained below, we direct Staff to convene a technical 
conference regarding the American Forest and Portland Cement 
Association, et al., proposals so that the Commission and the industry 
can learn

[[Page 12581]]

more about the proposals and the merit of adopting such changes where 
appropriate.

IV. Discussion

A. Demand Response and Pricing During Periods of Operating Reserve 
Shortages in Organized Markets

    26. This section of the NOPR proposes several reforms to further 
eliminate barriers to demand response in organized energy markets. 
These reforms must ensure that demand response is treated comparably to 
other resources. The Commission proposes to require RTOs and ISOs to: 
(1) Accept bids from demand response resources in their markets for 
certain ancillary services, comparable to other resources; (2) 
eliminate, during a system emergency, certain charges to buyers in the 
energy market for voluntarily reducing demand; and (3) permit ARCs to 
bid demand response on behalf of retail customers directly into the 
RTO's or ISO's organized markets.\24\ We also propose that RTOs and 
ISOs modify their rules governing price formation during periods of 
operating reserve shortage. These proposals, if adopted, would require 
market rules to ensure that demand response can participate directly 
and is treated comparably to supply resources in the organized electric 
energy and ancillary services markets. We also propose to require that 
each RTO and ISO study further reforms to address any remaining 
barriers to ensure that demand response is treated comparably to other 
resources and to report to the Commission within six months of the date 
of the final rule in this proceeding. In addition, we propose that each 
RTO or ISO must adopt reasonable standards necessary for system 
operators to call on demand response resources, and mechanisms to 
measure, verify, and ensure compliance with any such standards.\25\ As 
discussed further below, we intend to direct staff to convene a 
technical conference to explore issues that the RTOs and ISOs should 
include as part of these studies. The specific reforms being proposed 
here are therefore the next step in removing barriers to demand 
response, but not the final step.
---------------------------------------------------------------------------

    \24\ We will use the phrase ``aggregation of retail customers'' 
to refer to parties that aggregate demand response bids (which are 
mostly from retail loads), or ARCs.
    \25\ We understand that some RTOs and ISOs may already be 
developing measurement and verification requirements, as well as 
appropriate mechanisms to ensure compliance. It is not our intention 
that these programs be delayed based on our proposals here.
---------------------------------------------------------------------------

1. Background
    27. The Commission has expressed the view on numerous occasions 
that the wholesale electric power market works best when demand can 
respond to the wholesale price.\26\ Based on the view that the value to 
customers of electric power varies,\27\ the Commission's policy is to 
eliminate barriers to the participation of demand response in the 
organized power markets, in part because demand response helps to hold 
down wholesale power prices; increases awareness of energy usage; 
provides for more efficient operation of markets; mitigates market 
power; enhances reliability; and encourages new technologies that 
support the use of renewable energy resources, distributed generation, 
and advanced metering. The reforms we propose today would further 
facilitate demand response by removing several barriers to demand 
response. This will benefit customers of electric energy because 
increased demand response will improve price signals and provide for 
greater flexibility. We provide background on the benefits of demand 
response and prior Commission actions addressing demand response below.
---------------------------------------------------------------------------

    \26\ New England Power Pool and ISO New England, Inc., 101 FERC 
] 61,344, at P 44-49 (2002), order on reh'g, 103 FERC ] 61,304, 
order on reh'g, 105 FERC ] 61,211 (2003); PJM Interconnection, LLC, 
95 FERC ] 61,306 (2001); PJM Interconnection, LLC, 99 FERC ] 61,227 
(2002); Southwest Power Pool, Inc., 116 FERC ] 61,289 (2006).
    \27\ That is, for two customers at the same time and place, one 
customer may prefer to reduce consumption if the price is high, and 
the other may be willing to pay a high price to avoid curtailment in 
an emergency.
---------------------------------------------------------------------------

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

[[Page 12582]]

system emergencies,\33\ to allow wholesale buyers and qualifying large 
retail buyers to bid demand response directly into the day-ahead and 
real-time energy markets and certain ancillary service markets, 
particularly as a provider of operating reserves, as well as programs 
to accept bids from ARCs.\34\ The Commission also has approved special 
demand response applications such as use of demand response for 
synchronized reserves and regulation service.\35\ The theme underlying 
the Commission's approval of these programs has been to allow demand 
response resources to participate in these markets on a basis that is 
comparable to other resources.
---------------------------------------------------------------------------

    \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

[[Page 12583]]

reserves, energy imbalance, and regulation and frequency response.\49\ 
Because demand is always connected and demand response, in principle, 
can always be available, some forms of demand response resources may be 
able to provide a rapid, near real-time response.\50\ Nevertheless, not 
all RTOs and ISOs allow demand response to participate in ancillary 
services markets. ISO-NE, NYISO, and CAISO allow demand response 
resources to provide supplemental (non-spinning) reserves. As of mid-
2007, only PJM allows demand response resources to provide synchronized 
reserves (PJM's term for spinning reserves) and regulation service.\51\
---------------------------------------------------------------------------

    \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.

[[Page 12584]]

As a result, the market-clearing price may decrease because demand is 
reduced when an emergency demand response resource is used, even though 
that resource is the highest-valued resource used at the time. The 
reduced price is contrary to the signal that should be sent in an 
emergency. Only NYISO has integrated its emergency demand response 
programs into the market-clearing process.\54\
---------------------------------------------------------------------------

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

3. Proposed Reforms
    46. In order to further eliminate barriers to demand response in 
organized markets, the Commission proposes reforms to obligate RTOs and 
ISOs to: (1) Accept bids from demand response resources in its markets 
for certain ancillary services, comparable to any other resources; (2) 
eliminate, during a system emergency, a charge to a buyer in the energy 
market for taking less electric energy in the real-time market than 
purchased in the day-ahead market; (3) permit an ARC to bid a demand 
response on behalf of retail customers directly into the RTO's or ISO's 
organized energy markets, unless the laws or regulations of the 
relevant electric retail regulatory authority do not permit a retail 
customer to participate; and (4) modify their market rules to allow the 
market-clearing price to accurately reflect the value of energy during 
periods of operating reserve shortage. The Commission also proposes to 
require RTOs and ISOs to study whether further reforms are necessary to 
eliminate barriers to demand response in organized markets. We believe 
that these proposals ensure comparable treatment of demand response 
resources. We discuss these proposals in greater detail below.
9. Ancillary Services Provided by Demand Response Resources
i. Preliminary Proposals in the ANOPR
    47. In the ANOPR, the Commission sought comment on obligating RTOs 
and ISOs to purchase demand response resources in their markets for 
certain ancillary services, similar to any other resources, if the 
resources meet the necessary technical requirements and submit a bid 
under the generally-applicable bidding rules at or below the market-
clearing price. The Commission contemplated granting an exception where 
the seller would not be permitted to do so by state retail laws or 
regulations. The Commission proposed to require modifications to RTO 
and ISO tariffs that would apply this requirement for energy imbalance, 
spinning reserves, and supplemental reserves, as defined in the pro 
forma OATT, or their functional equivalents in an RTO or ISO tariff. To 
be eligible to supply these ancillary services, the Commission stated 
that demand response resources must be capable of reducing demand 
within seconds or minutes and must meet the RTO's or ISO's reasonable 
size, telemetry, metering, and bidding requirements.
    48. The Commission also sought comment on requiring modifications 
to RTO and ISO tariffs to provide that demand response resources must 
be allowed to provide spinning and supplemental reserves without also 
being required to sell into the energy market.
    49. The Commission requested comment on, among other things, 
whether each RTO or ISO should propose its own minimum requirements 
(for example, as to minimum size bids, measurement, and telemetry) or 
whether the Commission should specify the appropriate minimum 
requirements in a Commission rule.
ii. Comments on the ANOPR Proposals and Questions
    50. Most of the commenters that address the Commission's proposal 
in the ANOPR support having an RTO or ISO accept bids from demand 
response resources for certain ancillary services on a comparable 
basis. For example, BlueStar Energy states that the Commission's 
proposal ``will lead to greater economic efficiency, and reduce costs 
and risks for retail customers.'' \55\ Industrial Coalitions states 
that the Commission's current proposal is the next logical step, after 
Order No. 890, in promoting the integration of demand response 
resources into all RTO- and ISO-coordinated markets and services.\56\
---------------------------------------------------------------------------

    \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

[[Page 12585]]

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

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

iii. Commission Proposal
    56. The Commission proposes to obligate each RTO or ISO to accept 
bids from demand response resources, on a basis comparable to any other 
resources, for ancillary services that are acquired in a competitive 
bidding process, if the demand response resources (1) are technically 
capable of providing the ancillary service and meet the necessary 
technical requirements, and (2) submit a bid under the generally-
applicable bidding rules at or below the market-clearing price, unless 
the laws or regulations of the relevant electric retail regulatory 
authority do not permit a retail customer to participate. This proposal 
would apply to competitively-bid markets, if any, for energy imbalance, 
spinning reserves, supplemental reserves, reactive supply and voltage 
control, and regulation and frequency response as defined in the pro 
forma OATT, or to the markets of their functional equivalents in an RTO 
or ISO tariff. We propose that demand response resources that are 
capable of reducing demand within the response time requirement for the 
ancillary service and that meet reasonable requirements adopted by the 
RTO or ISO as to size, telemetry, metering, and bidding be eligible to 
supply energy imbalance, spinning reserves, supplemental reserves, 
reactive and voltage control, and regulation and frequency response. In 
the compliance filing to be submitted within six months of the final 
rule, the RTO or ISO must adopt reasonable standards necessary for 
system operators to call on demand response resources, and mechanisms 
to measure, verify, and ensure compliance with any such standards. Such 
standards would be subject to Commission approval.
    57. We believe that this policy would increase the competitiveness 
of ancillary services markets, help reduce the price of ancillary 
services, and improve the reliability of the grid. Experience in the 
PJM, CAISO, and ERCOT markets has demonstrated that certain demand 
response resources can provide some ancillary services reliably. 
Moreover, this proposal would require that, for ancillary services 
acquired in a competitive process, RTOs and ISOs make any necessary 
changes to their tariffs and market rules to allow for direct demand 
response resource participation in the ancillary services markets.
    58. We clarify, in response to NYISO's and National Grid's 
requests, that this proposal would not require an RTO or ISO to 
purchase certain ancillary services from demand response resources, but 
rather to accept bids from them for ancillary services acquired in a 
competitive bidding process, and if they meet minimum technical 
requirements and clear the market, on a basis comparable to other 
resources. The purpose of the proposal is to ensure that all RTOs and 
ISOs treat demand response resources comparably with other resources in 
the market rules for energy imbalance, spinning reserves, supplemental 
reserves, reactive and voltage control, and regulation and frequency 
response. This proposal does not require the adoption of a competitive 
bidding process where one was previously not utilized.
    59. The California PUC's argument that ancillary services market 
rules for comparable and nondiscriminatory access for demand response 
resources may be a barrier to participation of small demand response 
resources has merit. Experiments and pilot programs suggest that 
resources below minimum size thresholds in RTO and ISO markets have the 
potential to respond quickly and reliably.\67\ Adjusting minimum size 
thresholds and telemetry requirements to accommodate smaller demand 
response resources may result in a significant increase in potential 
sources of operating reserves. Without extensive experience with the 
ability of smaller demand response resources to provide ancillary 
services, however, it is premature to mandate specific conditions under 
which RTOs and ISOs must accommodate smaller resources into the 
spinning reserves, supplemental reserves, energy imbalance markets, 
reactive and voltage control, and regulation and frequency response. 
Instead, we propose to direct the RTOs and ISOs to perform an 
assessment of the technical feasibility and value to the market of 
smaller loads providing some ancillary services one year from the 
effective date of the final rule, including whether (and how) smaller 
resources can reliably and economically provide operating reserves 
through pilot projects or other mechanisms.\68\
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    \67\ See 2006 FERC Staff Demand Response Assessment at 114.
    \68\ For example, ISO-NE is assessing whether small demand 
response resources can provide operating reserves in its Demand 
Response Reserves Pilot.
---------------------------------------------------------------------------

    60. In the ANOPR, the Commission made a preliminary proposal to 
remove a disincentive for demand response to offer operating reserves. 
The proposal was to modify RTO and ISO tariffs to provide that demand 
resources must be allowed to provide spinning and supplemental reserves 
without also being required to sell into the energy market, explaining 
that customers may be more likely to offer demand response as operating 
reserves if they do not need to worry about disruptions to their 
businesses by participating in the energy markets. We are sympathetic, 
however, to concerns raised in ISO-NE's and NYISO's comments that the 
ANOPR proposal could undo their recent success in resolving design 
problems of disjointed markets by combining and co-optimizing their 
energy and ancillary services markets. The Commission is mindful of 
these concerns and does not intend to negatively affect the market 
efficiencies created by co-optimized market designs.
    61. NYISO suggests, however, that the development of new bidding 
rules could limit the exposure of demand response resources selling 
into the energy market--rules that would not require changes to its co-
optimized markets. Resource bids in RTO and ISO markets typically allow 
bidders to specify various parameters of their bid (e.g., price, 
quantity, startup and no-load

[[Page 12586]]

costs, and minimum downtime between starts). NYISO suggests new 
parameters that would allow demand response bidders to specify 
additional constraints on the dispatch of their resources. In its 
comments, NYISO offers that a demand response bidder could specify the 
maximum duration in hours that a bid can be dispatched, maximum number 
of times that a bid can be dispatched during a day, and a maximum 
amount of energy that a resource can produce either daily or weekly, 
and that those parameters could be incorporated into the bidding rules. 
We believe that NYISO's suggestion has merit.
    62. We propose here to require RTOs and ISOs to allow demand 
response resources to specify limits on the frequency and duration of 
their service in their bids to provide ancillary services--or their 
bids into the joint energy-ancillary services market in the co-
optimized RTO markets. These limits are comparable to the limits 
generators may specify on price, quantity, startup and no-load costs, 
and minimum downtime between starts--limits that may not be available 
to demand response resources. The proposal is for RTOs and ISOs to 
incorporate new parameters into their bidding rules that allow demand 
response resources to specify a maximum duration in hours that the 
demand response resource may be dispatched, a maximum number of times 
that the demand response resource may be dispatched during a day, and a 
maximum amount of electric energy that the demand response resource may 
be required to provide either daily or weekly. We expect that this 
requirement would encourage demand response in the spinning reserves, 
supplemental reserves, and regulation and frequency response markets by 
reducing the risk that demand response resources would be called on too 
frequently or for too long a period. We ask for comment on whether 
these new parameters should be available for all bids, not just demand 
response resources. These new bidding parameters could benefit energy-
limited resources or runtime-limited resources, e.g., hydropower and 
units with environmental restrictions. The new bidding parameters could 
also benefit resources that cannot start and stop quickly. The proposal 
should not require fundamental changes to existing market designs,\69\ 
or affect the efficiencies of co-optimized markets.
---------------------------------------------------------------------------

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

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

    \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

[[Page 12587]]

Connecticut and Massachusetts Municipals worry that virtual bidders may 
engage in market manipulation. Connecticut and Massachusetts Municipals 
argue that virtual bidders' virtual load in the day-ahead market may 
create the appearance of a shortage even without corresponding real-
time load. Therefore, the Commission should tailor any deviation 
exemption to apply to physical loads only.\77\ APPA agrees.\78\
---------------------------------------------------------------------------

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

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

[[Page 12588]]

purchases, we believe that, during an emergency, these day-ahead 
purchases may not cause unneeded generation to be committed to the 
market because an emergency by its nature is a time when the system is 
short of generation. As a result, we believe that virtual purchasers 
may not cause significant additional costs during an emergency. Indeed, 
virtual purchases may enhance reliability by increasing the amount of 
generation resources available in real time during a system emergency. 
Assessing a deviation charge on virtual purchasers during an emergency 
may be unfair and may discourage helpful virtual bidding. Some 
commenters contend that virtual purchases add to system costs but do 
not address whether they add to costs during an emergency situation 
when the system is short of generation. The Commission seeks comment on 
whether to require RTO and ISO tariffs to be modified to eliminate 
deviation charges for virtual purchasers during system emergencies.
    79. We do not propose to modify RTO and ISO tariffs to eliminate 
deviation charges absent a system emergency, in light of the comments 
we received regarding this ANOPR proposal. We are concerned about the 
resulting possibility of market manipulation and inefficiencies if 
deviation charges are removed, as raised by several commenters. Given 
the reliability value associated with demand response during system 
emergencies, socialization of related uplift costs is supportable.
c. Aggregation of Retail Customers
i. Preliminary Proposals in the ANOPR
    80. In the ANOPR the Commission sought comment on requiring RTOs 
and ISOs to amend their market rules as necessary to permit an ARC to 
bid demand response on behalf of retail customers directly into the 
RTO's or ISO's organized markets. Under the preliminary proposal, the 
amended market rules could not exclude a demand response bid from a 
third-party ARC that is not an LSE, unless state laws or regulations do 
not permit this. RTOs and ISOs would have the same rules for ARC 
participation as for LSEs, except as needed to comply with state laws 
and regulations, unless the RTO or ISO satisfactorily explained the 
reason for any such difference. As part of the preliminary proposal, 
the Commission suggested directing RTOs and ISOs to coordinate to 
identify common issues, best practices, and market rules that are 
consistent between regions, particularly in the areas of market 
procedures, bidding protocols, communication protocols, and measurement 
and verification, and having them report to the Commission on their 
coordination efforts.
    81. The Commission also requested comments on whether ARCs allow 
for inappropriate compensation when a retail customer is paid for 
wholesale demand response and also saves in its retail bill from the 
same demand response. The Commission noted that some argue that the 
payments to customers for demand response are a form of double payment 
that provides an unjustified subsidy.
ii. Comments on the ANOPR Proposals and Questions
    82. A large number of commenters address at great length the 
proposal to require an RTO to accept a demand response bid into its 
energy market from an ARC, if permitted by state law. A majority--
including such diverse entities as EPSA, CAISO, and Industrial 
Consumers--appears to support the basic proposal although many raise 
implementation concerns. Comments in opposition to the proposal also 
vary widely and represent a diversity of interests, from SoCal Edison-
SDG&E to the Massachusetts Attorney General. They offer a variety of 
reasons not to require market rule changes, with most concluding that 
this topic is a subject better suited for detailed stakeholder 
negotiations than a generic rulemaking. State regulators generally like 
the state law exemption, but several worry that the program could have 
unintended consequences and is inappropriate for non-retail access 
states. Public power, cooperatives, and other retail service providers 
not regulated by state commissions ask for clarification that an RTO or 
ISO may not accept a bid from an ARC that aggregates their customers if 
their own retail regulations would not permit this.\85\
---------------------------------------------------------------------------

    \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.

[[Page 12589]]

    87. This proposal would reduce a barrier to demand response by 
permitting an ARC to act as an intermediary for many small retail loads 
that cannot individually participate in the organized market. We agree 
with commenters that aggregating small retail customers into larger 
pools of resources allows more customers to access demand response 
programs, which increases the potential market and reliability benefits 
realized from demand response in wholesale markets.\91\ Experience with 
existing aggregation programs in PJM, NYISO, and ISO-NE has shown that 
these programs increased demand responsiveness in these regions.
---------------------------------------------------------------------------

    \91\ See, e.g., PJM at 8; EnerNOC at 5-7; Alcoa at 22; Public 
Interest Organizations at 6-10.
---------------------------------------------------------------------------

    88. In response to comments on the ANOPR's preliminary proposal, we 
offer these clarifications of our proposal here. The ARC's demand 
response bid must meet the same requirements as a demand response bid 
from any other entity, such as an LSE. The bidder only has the 
opportunity to be among the bids that clear the market; it does not 
guarantee that the bid will clear the market and be selected. In 
response to comments from public power entities, cooperatives, and 
other such entities with retail customers that are sometimes not 
subject to state public utility regulation, we clarify that, for the 
purposes of the ARC part of this rule, the term ``relevant electric 
retail regulatory authority'' means the entity that establishes the 
retail electric prices and any retail competition policies for those 
customers, such as the city council for a municipal utility or the 
governing board of a cooperative utility.\92\ An ARC can bid demand 
response either on behalf of only one retail customer or multiple 
retail customers. Except for circumstances where the laws and 
regulations of the relevant retail regulatory authority do not permit a 
retail customer to participate, there is no prohibition on who may be 
an ARC, and an individual customer may serve as an ARC on behalf of 
itself and others. Finally, RTOs or ISOs may specify certain 
requirements, such as registration with the RTO or ISO and 
creditworthiness and other requirements, which qualify a resource 
provider to make a bid and requests comments on whether there is any 
reason not to subject ARC to the same requirements as any other bidder 
in the energy market.
---------------------------------------------------------------------------

    \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

[[Page 12590]]

Commission and stakeholders study what additional efforts are needed 
and develop a record to support further reforms.
    95. In order to achieve this goal, we intend to direct staff to 
hold a technical conference shortly after receiving the comments on 
this NOPR to consider the following issues for demand response 
participation in the wholesale markets: (1) If there are barriers to 
comparable treatment of demand response that have not previously been 
identified and what they are; (2) potential solutions to eliminate any 
potential barriers to comparable treatment of demand response; (3) 
appropriate compensation for demand response; and (4) the need for and 
the ability to standardize terms, practices, rules and procedures 
associated with demand response, among other things. The proposed 
technical conference will provide a forum for RTOs/ISOs, demand 
response providers, and other stakeholders to express their views 
regarding these issues. It will also serve as guidance to the RTOs/ISOs 
of the areas that they should include as part of the study we propose 
to order as well as other issues identified in the course of the study. 
We propose to require each RTO or ISO to assess and report on the 
barriers to comparable treatment of demand response resources that are 
within the Commission's jurisdiction, including those listed above, and 
to submit its findings and any proposed solutions along with a timeline 
for implementation to address barriers to the Commission within six 
months of the Final Rule (RTO and ISO studies). To ensure that minority 
views are adequately represented, we propose to require that the RTO or 
ISO identify any significant minority views in its filing. We also will 
require the Independent Market Monitor for each RTO or ISO to provide 
its views on this issue to the Commission.
    96. These RTO and ISO studies will have significant value. They 
have the potential to provide independent critical analysis and a basis 
for additional reform. In this regard, we note that section 529 of the 
Energy Independence and Security Act of 2007 (EISA) requires the 
Commission to complete a national assessment of demand response both to 
estimate the potential for demand response and to determine how to 
overcome the barriers to achieving that potential.\94\ We believe that 
the RTO and ISO studies we are proposing to require will help us in 
preparing the assessment and ultimately in developing a national action 
plan on demand response as required by EISA. These studies will also 
provide a sound platform and record for the Commission to consider 
whether there should be additional reforms to remove barriers to demand 
response in organized markets that ensure comparable and fair treatment 
of demand response resources as required by the EISA.\95\ We seek 
comment on the proposed approach to identify and assess remaining 
barriers to comparable treatment of demand response as well as any 
particular issues or areas that should be addressed in the RTO and ISO 
reports.
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    \94\ The Energy Independence and Security Act of 2007, Pub. L. 
No. 110-140, 121 Stat. 1492 (2007).
    \95\ 42 U.S.C. 8241 et seq. (2000), amended by EISA, Pub. L. No. 
110-140, 529, 121 Stat. 1492 (2007).
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e. Market Rules Governing Price Formation During Periods of Operating 
Reserve Shortage
i. Preliminary Proposals in the ANOPR
    97. In the ANOPR, the Commission sought comment on modifying market 
rules that limit the market-clearing price during an emergency, that 
is, when the amount of available supply falls short of demand plus the 
operating reserve requirement.\96\ When this happens, reliability is 
threatened and market rules that limit the market price may have the 
unintended effect of discouraging demand response. Limiting the price 
also discourages existing generators needed mostly for emergencies from 
continuing operation and discourages entry of new generation. The ANOPR 
presented for comment four possible approaches to addressing this 
problem.
---------------------------------------------------------------------------

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

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

    \102\ See, e.g., AEP at 5; The Alliance at 9; Constellation at 
5-6; EPSA at 33; Reliant at 5-7; Strategic Energy at 9.

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[[Page 12591]]

    102. In general, among those who favored one or more of the ANOPR's 
four approaches, the first (raise all caps during an emergency) and 
third (have a demand curve for operating reserves) approaches received 
the strongest support. The second (raise only demand bid caps during an 
emergency) and fourth (allow the payments for emergency demand response 
to set the market-clearing price during an emergency) approaches had 
the weakest support.
    103. In comments on the first approach--lifting energy bid caps and 
price caps above the current levels only during an emergency--
supporters say that this course of action allows buyers and sellers to 
set a true market price for electricity during an emergency, reduces 
demand by the appropriate amount, and allows investors in new 
generation to assess the value to buyers of new generating resources. 
This approach also has strong opposition, with particular concerns 
about the potential for generators to exercise market power and the 
inability of customers to respond to high prices.
    104. The few commenters supporting the second approach--raising bid 
caps above the current level only for demand bids--say that it 
decreases generators' ability to manipulate the market compared to the 
first option. They also make the general point that it is important to 
let buyers express their true value for power. Those objecting to this 
proposal raised many of the same concerns that were raised regarding 
the first approach. For instance, they allege that even raising bid 
caps only for demand bids would allow generators to physically withhold 
some portion of their output from the market to obtain higher prices 
for the remaining output. Commenters also argued that the proposal was 
based on the false assumption that buyers that do not enter a bid to 
purchase at a high price will not be served. These commenters maintain 
that utilities shed load only as a last resort during an emergency, and 
emergency curtailment programs dictate the allocation of power during a 
shortage in a way that has nothing to do with the price bid into the 
energy market.
    105. Support for the third approach of establishing a demand curve 
for operating reserves rests heavily on its track record, namely that 
the Commission has approved these programs before and many regions have 
experience with them.\103\ Arguments against this specific proposal are 
largely objections to administratively determined demand curves where 
prices may be set at levels that do not reflect competitive market 
conditions.
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    \103\ Duke Energy at 11; EPSA at 35; PJM MMU at 6-7; National 
Grid at 10-11; NEPOOL Participants at 16; New England Power 
Generators at 6-7; NYISO at 35; NY TO at 10.
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    106. In commenting on the fourth approach--setting the market--
clearing price at the payment made to participants in an emergency 
demand response program--a few commenters state that this approach is 
preferable to allowing no higher price during an emergency at all and 
could be supported as a transitional step in the process of removing 
all bid and offer caps. Opposition to this approach is based on the 
market price being administratively determined and a variety of other 
reasons, for example, that it is inappropriate to set an energy price 
based on a reliability payment.
iii. Commission Proposal
    107. We have carefully considered the comments on this issue and 
continue to believe that existing market rules appear to be unjust, 
unreasonable and unduly discriminatory or preferential during times of 
scarcity. In particular, they may not accurately reflect the true value 
of energy and, by failing to do so, may harm reliability, inhibit 
demand response, deter new entry of demand response and generation 
resources and thwart innovation. However, we are cognizant of the fact 
that this is a difficult issue and that any change in market rules must 
consider the issue of market power, recognize regional differences in 
market rules, and be based on a sound factual record. We first explain 
the potential need for reform and then we describe our proposal to 
address this issue.
    108. In a competitive market, demand and supply respond to price. 
If the price of energy is artificially capped during times of scarcity, 
this will constitute a barrier to effectively attracting new generation 
and demand resources into organized markets. When the system faces a 
shortage of operating reserves, additional resources are needed for 
operating reserves that help to maintain grid reliability. At such 
times, market prices can elicit demand response from certain customers 
who are equipped to respond and, thus, help balance the system. When 
bid and offer caps are in place, however, it is not always possible to 
elicit the optimal level of demand or generator response.
    109. Some commenters argue that certain barriers to demand response 
remain and that the Commission should not undertake any reform until 
such barriers are removed. The Commission is taking several important, 
concrete steps in this rulemaking to eliminate remaining barriers to 
demand response that are indicated by the existing record to ensure 
comparable and fair treatment of demand response resources. We 
recognize, however, that some barriers may remain. That is why we are 
requiring each RTO or ISO, as explained above, to undertake a further 
study of this issue and report back to the Commission. However, even if 
some barriers remain (certain of which may be subject to state 
jurisdiction, not our jurisdiction), price remains an important factor 
in encouraging demand response. Without prices that reflect the true 
value of energy, we cannot expect the full integration of demand 
response into organized markets. We therefore do not believe that 
reforms in this area should be delayed until every barrier to demand 
response, whether retail or wholesale, technological or regulatory, is 
identified and addressed. We have, however, included as a primary 
criterion for approving price reform during periods of operating 
reserve shortage an adequate record demonstrating that provisions exist 
for mitigating market power and deterring gaming behavior. These could 
include, but are not limited to, use of demand resources to discipline 
bidding behavior to competitive levels during periods of operating 
reserve shortages.
    110. We recognize that not all customers are at present equipped to 
respond to scarcity pricing. Nevertheless, putting rules in place that 
allow the fraction of the load currently able to respond can have a 
very positive effect on the market and help reduce prices for all.\104\ 
Further, with the modifications that this proposal anticipates, more 
buyers would find it worthwhile to invest in technologies that allow 
them to respond to prices. This group could include not only large 
manufacturers and others buying directly from the RTO or ISO market, 
but also ARCs, and LSEs which can implement retail demand response 
programs designed to reduce load during reserve shortages.
---------------------------------------------------------------------------

    \104\ See 2006 FERC Staff Demand Response Assessment at 7. As 
reported in the 2006 FERC Staff Demand Response Assessment, as 
little as five percent of load responding to price may discipline 
market prices.
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    111. The Commission's proposed reforms are also intended to 
increase reliability. Our proposal is limited to periods of true 
scarcity (i.e., when there is a shortage of operating reserves). We 
have a duty to implement rules that ensure adequate supplies. If the 
price of energy during these periods is

[[Page 12592]]

artificially constrained, demand cannot respond efficiently and 
therefore the likelihood of involuntary curtailments is increased. 
Thus, demand resources may be a low cost resource that can be used to 
meet operating reserves requirements at the lowest total cost of 
maintaining reliability. Furthermore, by artificially capping prices, 
the price signals necessary to attract new entry by both generation and 
demand resources are muted and long-term resource adequacy is harmed.
    112. This is not merely a theoretical problem. In regions such as 
PJM and New England, the Commission has found in prior orders that 
existing energy and capacity markets did not encourage sufficient new 
entry and that these regions therefore faced serious reliability 
problems.\105\ The Commission adopted forward capacity markets in those 
regions to avoid the threats to reliability and the real costs to our 
economy of inadequate generation and demand resources. The reforms we 
propose here can help to avoid these problems in other regions. 
Moreover, as we explain below, in regions that already have such 
capacity markets, the reforms proposed here can reduce the level of 
revenues that must be recovered in such capacity markets.
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    \105\ Devon Power, LLC, 115 FERC ] 61,340, order on reh'g, 117 
FERC ] 61,133 (2006), appeal pending sub nom. Maine Pub. Utils. 
Comm'n v. FERC, No. 06-1403 (DC Cir. 2007); PJM Interconnection, 
LLC, 117 FERC ] 61,331 (2006).
---------------------------------------------------------------------------

    113. Some commenters appear to misunderstand our proposal and 
suggest that we are proposing to lift the caps on generation in every 
organized market. This is not correct. Only one of our proposals would 
lift price caps on generators bidding energy into organized markets. 
The other three would not do so, but rather would seek to better 
reflect the value of energy during times of scarcity through other 
means.
    114. In regions that have already adopted forward capacity markets, 
the lifting of such price caps on energy would primarily shift revenues 
from capacity markets to energy markets. In New England and PJM, the 
revenues collected by generators in the energy market are deducted from 
the revenues that need to be recovered in the capacity markets. 
Moreover, by shifting the price signals from capacity markets to energy 
markets, the Commission is encouraging greater demand response, as 
demand response may face fewer barriers to participating in energy 
markets than forward capacity markets.
    115. Finally, and most importantly, we are not proposing to change 
the rules in each region without regard to the specific circumstances 
facing that region. As we explain below, each region will be permitted 
to demonstrate that its current rules do not need to be reformed 
because they already adequately reflect the value of energy during 
periods of scarcity.
    116. Other commenters raise market power concerns. We agree that we 
have a duty to guard the consumer against exploitation by sellers with 
market power and we will fulfill that duty. As we explain below, we are 
proposing that market power issues be adequately addressed before any 
reforms in this area are adopted.
    117. We now explain our proposal for reform in this area. We 
propose to require each organized market to make a compliance filing, 
within six months of a final rule in this proceeding, proposing any 
necessary reforms to ensure that the market price for energy accurately 
reflects the value of such energy during periods of scarcity (i.e., an 
operating reserve shortage). Because there are regional differences in 
market design, we will not mandate any one type of reform in this area. 
Rather, each region may propose one of the four approaches described in 
the ANOPR (and summarized further below) or it may propose a different 
approach. Alternatively, a region may demonstrate that its existing 
market rules already reflect the value of energy during periods of 
scarcity and therefore do not need to be reformed.
    118. In recognition of the concerns of many commenters, we also 
propose to adopt further requirements to ensure that any reforms in 
this area are supported by adequate factual support and show how they 
are designed to protect consumers against the exercise of market power. 
First, each RTO or ISO proposing to reform or demonstrate the adequacy 
of its existing market rules in this area must provide an adequate 
factual record for the Commission to evaluate its proposal. 
Specifically, the RTO or ISO should provide historical evidence in its 
region regarding the interaction of supply and demand during periods of 
scarcity and the resulting effects on the market price for energy. To 
the extent this evidence indicates that the region's market rules are 
inadequate during these periods, the RTO or ISO must then explain and 
support why its proposed reforms are tailored to address those 
inadequacies. This factual record will allow the Commission to 
discharge its duty to ensure that any reform is necessary and narrowly 
tailored to address the circumstances in that region.
    119. As a general matter, we will consider the factual record 
compiled by the RTO or ISO to determine whether its proposal, or its 
demonstration as to its existing market rules, would:
     Improve reliability by reducing demand and increasing 
generation during periods of operating reserve shortage;
     Make it more worthwhile for customers to invest in demand 
response technologies;
     Encourage existing generation and demand resources needed 
during an operating reserve shortage to remain in business;
     Encourage entry of new generation and demand resources;
     Provide comparable treatment and compensation to demand 
resources during periods of operating reserve shortages; and
     Have provisions for mitigating market power and deterring 
gaming behavior, including, but not limited to, use of demand resources 
to discipline bidding behavior to competitive levels during periods of 
operating reserve shortages.
    120. We request comment on whether these criteria are appropriate 
and whether there are additional criteria that we should consider in 
evaluating a proposal for pricing during a period of operating reserve 
shortage by RTOs and ISOs.
    121. Second, the Commission will require any RTO proposing reform 
in this area to address the adequacy of any mitigation measures that 
would be in place during periods of operating reserve shortage. We 
recognize that many commenters have raised market power concerns and we 
take those concerns seriously. However, we note that enhanced demand 
responsiveness and increased entry by generators can help to mitigate 
seller market power by lowering market prices.\106\ Moreover, we note 
that generator bid and offer caps are not increased in three of the 
four options proposed.\107\ These caps provide further protection 
against the exercise of seller market power. Further, the Commission 
notes that other market power mitigation measures remain in

[[Page 12593]]

place during times when operating reserves are insufficient. For 
example, conduct and impact tests are applied in ISO-NE, NYISO, and 
Midwest ISO. A pivotal supplier test is used in PJM. PJM and CAISO 
mitigate bids by generators chosen out of merit order. Moreover, the 
Commission intends to closely monitor market behavior during periods of 
operating reserve shortage to ensure that market participants are 
following market rules and to guard against the exercise of market 
power.
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    \106\ See B.F. Neenan et al., Neenan Associates, 2004 NYISO 
Demand Response Program Evaluation, at E-5, (Feb. 2005); David B. 
Patton, Potomac Economics, 2006 State of the Market Report--The 
Midwest ISO, at 44 (May 2007).
    \107\ In the first approach, bid and offer caps would increase 
for both sellers and buyers. In the second approach, bid and offer 
caps for buyers would be increased, but bid and offer caps for 
sellers would remain in place. In the third approach, based on a 
demand curve for operating reserves, bid and offer caps would remain 
in place for both sellers and buyers. In the fourth approach (which 
proposes that payments to participants in an emergency demand 
response program could set the market-clearing price), bid and offer 
caps would again remain in place for both sellers and buyers.
---------------------------------------------------------------------------

    122. In addition, to ensure that we have an adequate record on the 
issue of market power mitigation, we propose to solicit the views of 
the Independent Market Monitor for each RTO or ISO region on any 
proposed reforms in this area.
    123. We now briefly summarize the four approaches discussed in the 
ANOPR and referred to above. As noted, however, these are not the only 
approaches that may be considered. Under the first approach, RTOs and 
ISOs would increase the energy supply offer caps and demand bid caps 
above the current levels only during an emergency. For example, if 
operating reserves drop below levels required in mandatory reliability 
standards, then bid caps would be allowed to rise above existing caps. 
As we described above, increasing energy supply offer and demand bid 
caps would allow the market to clear at a price above the current (or 
non-emergency) cap.\108\ Customers and LSEs could then decide whether 
to purchase energy at the higher price, and those who place a higher 
value on energy could continue to buy it while those who do not value 
it as highly could reduce their demand. Thus, this proposal would allow 
supply and demand to operate more efficiently to allocate limited 
supply to those who value it the most.
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    \108\ Under this proposal, the price and bid caps would be 
removed in the real-time market during an operating reserve 
shortage, but not necessarily in the day-ahead market. Thus, the 
price and bid caps would be removed normally for only a fraction of 
the spot market. In a severe shortage when the system operator is 
aware that the day-ahead market will produce insufficient generation 
for day-ahead energy and operating reserves, the price and bid caps 
would also be removed for the day-ahead market.
---------------------------------------------------------------------------

    124. Under the second approach, RTOs and ISOs would increase bid 
caps above the current level only for demand bids (i.e., the buyers' 
offers to purchase a certain amount of energy at a given price) while 
keeping generation bid caps in place. That is, a buyer would be allowed 
to inform the RTO or ISO about how much energy it would purchase at 
various prices above the current bid caps. These demand bids would be 
allowed to set the market price if they clear the market. As with the 
other approaches, the higher market price under this approach would 
create an incentive for all buyers to lower their demands during an 
emergency. Demand that is price-sensitive would be reduced until 
available supply can meet the demand plus the need for operating 
reserves. This proposal does not change any rules that govern how 
demand response resources operate in the market.\109\
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    \109\ We clarify that this approach refers to demand, not demand 
response. That is, this proposal allows a buyer to submit a bid to 
purchase energy at a price that exceeds the current bid cap. This 
proposal in no way affects demand response resources that 
participate in a program where they are paid some amount of money to 
reduce their consumption.
---------------------------------------------------------------------------

    125. The third approach is for an RTO or ISO to establish a demand 
curve for operating reserves. The RTO or ISO would establish market 
rules that set real-time prices at specific pre-determined values 
(typically above the market-wide offer and bid caps) during an 
operating reserve shortage. The price level would increase with the 
severity of the shortage. This approach will ensure that market prices 
reflect tight conditions on the grid without altering any of the market 
power mitigation restrictions on either supply offers or demand bids. 
The Commission has already approved this option in the NYISO and ISO-NE 
markets.\110\ These existing programs for pricing during reserve 
shortages have been implemented and activated during periods of 
operating reserve shortage in these regions. Moreover, the exposure to 
higher prices would increase the incentive for load to engage in 
hedging activities, and higher prices during shortages should attract 
new generation. As long as the prices that are implemented during 
reserve shortages are based on costs relevant to the market (such as 
the cost of new peak generation entry), and the particular 
characteristics of RTO and ISO regions, demand curves for operating 
reserves should induce sufficient supply and demand responses. A 
properly designed demand curve for operating reserves should also 
alleviate concerns about administratively determined prices. As noted 
above, the demand curve is a reflection of the costs of entering the 
energy market and indicates the prices suppliers would expect to be 
paid to provide that energy to the market. Thus, while the demand curve 
is administratively determined, it is based on market conditions.
---------------------------------------------------------------------------

    \110\ The Commission approved market rules for NYISO and ISO-NE 
that include a demand curve for operating reserves that sets the 
real-time market price when operating reserves are low. New York 
Indep. Sys. Operator, Inc., 106 FERC ] 61,111 (2004); New England 
Power Pool and ISO New England Inc., 115 FERC ] 61,175 (2006). See 
David B. Patton & Pallas LeeVanSchaik, 2006 Assessment of the 
Electricity Markets in New England (June 2007); David B. Patton & 
Pallas LeeVanSchaik, 2006 State of the Market Report New York ISO 
(July 2007).
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    126. Under the fourth approach, an RTO or ISO would amend its 
market rules to set the market-clearing price for all supply and demand 
response resources dispatched equal to the payment made to participants 
in an emergency demand response program.\111\ Since the emergency 
demand response programs are only called during an emergency when 
demand needs to be reduced quickly, they should be the marginal 
resource and set the market-clearing price. Without such a rule, demand 
response payments are made to those demand response resources that 
respond to the RTO's or ISO's call to reduce load, yet prices are still 
set by the generation resource with the highest running costs (or at 
the price cap). This proposal would set the market-clearing price by 
the actual marginal reliability resource, the demand response resource. 
For example, if participants in emergency demand response programs were 
paid $500/MWh to reduce their consumption when directed, then the $500/
MWh payment would set the market-clearing price in the zones where the 
program was active.
---------------------------------------------------------------------------

    \111\ RTOs and ISOs would have to amend their market rules on 
unit commitment and settlement to adjust wholesale energy prices 
outside the normal clearing process.
---------------------------------------------------------------------------

    127. This rulemaking approach to demand response is directed at all 
RTOs and ISOs to ensure that all meet certain basic demand response 
goals. However, we do not intend to alter current RTO and ISO shortage 
pricing programs if the compliance filings satisfy us that the current 
programs meet the intent of this requirement. Some RTOs and ISOs have 
already dedicated considerable resources to develop various shortage-
pricing programs. These programs have been developed through 
established stakeholder processes in the RTOs and ISOs and have been 
approved by the Commission and determined to be just and reasonable. 
Thus, the requirement proposed here may be satisfied by a filing 
demonstrating that the RTO or ISO already has a Commission-approved 
approach for pricing during periods of operating reserve shortage that 
meets the requirements previously discussed (i.e., in P 117, 118 and 
120).
    128. Each RTO or ISO may also consider a ``phase-in'' of its 
specific

[[Page 12594]]

emergency pricing method, over a period of years (e.g., three years). 
This phase-in period can gradually introduce customers to price 
increases during an emergency and allow them to develop ways to reduce 
demand during an emergency to avoid high prices. We note that the 
phase-in may be linked to key factors such as the deployment of the 
advanced metering needed to implement their proposed method, provided 
the phase-in period is not protracted. However, the full deployment of 
advanced metering is not a requirement for the implementation of 
emergency pricing as price and demand responsiveness can be achieved 
without such a prerequisite.

B. Long-Term Power Contracting in Organized Markets

    129. In the ANOPR, the Commission offered for comment three 
proposals intended to facilitate long-term contracting in organized 
markets, along with questions about whether to modify Electric 
Quarterly Reports (EQR) data requirements to facilitate long-term 
contracting. Following review of the comments, the Commission proposes 
to require that ISOs and RTOs dedicate a portion of their Web sites for 
market participants to post offers to buy or sell electric energy on a 
long-term basis. The Commission will consider reasonable additional 
steps in response to comments on this NOPR, and continues to encourage 
ISOs and RTOs to work within their authorities with stakeholders to 
facilitate long-term power contracting.
1. Background
    130. Long-term power contracts are an important element in a 
functioning electric power market. Forward power contracting allows 
buyers and sellers to hedge against the risk that prices may fluctuate 
in the future. Both buyers and sellers should be able to create 
portfolios of short, intermediate, and long-term power supplies to 
manage risk and meet customer demand. Long-term contracts also improve 
price stability, mitigate the risk of the abuse of market power, and 
provide a platform for investment in new generation and transmission.
    131. As the Commission noted in the ANOPR, an organized market 
region naturally should facilitate long-term contracting by eliminating 
pancaked rates for long distance power sales, eliminating loop flow 
problems within its footprint, and ensuring reliable transmission 
operation over a large area. RTO and ISO transmission services also 
expand the size of the markets available to buyers and sellers of long-
term power contracts, and provide independent and unified transmission 
scheduling and operation services over a large area.
    132. While most of the comments submitted in response to the ANOPR 
and testimony from parties at the Commission's technical conference on 
May 8, 2007 agree as to the importance of long-term contracts, opinions 
vary as to the extent of a problem with long-term contracts in the 
market and its causes. Many customers argue that issues of market 
design and over-reliance on the spot market have driven up prices, 
making long-term contracting difficult. On the other hand, many power 
sellers believe that markets are operating well, but parties are unable 
to reach long-term contracts due to differing price expectations and 
differing assessments of long-term risk.
    133. The Commission has already taken action in other areas to 
facilitate long-term contracting. In Order No. 681, the Commission 
adopted a Final Rule on long-term transmission rights for organized 
market regions designed to assure availability of long-term 
transmission at a predictable cost.\112\ The Commission then adopted 
transmission planning reforms in Order No. 890 to provide an open and 
transparent process for wholesale entities and transmission providers 
to plan for the long-term needs of their customers. Interconnection 
rules for large, small and wind generators in Order Nos. 2003, 2006 and 
661 have improved the interconnection process and provide for 
interconnection with network integration service to facilitate long-
term reliance on new generation.\113\ The Commission has also reformed 
capacity markets in several regions to shift reliance from short-term 
purchases to forward markets held sufficiently in advance of delivery 
(e.g., three years) to be more consistent with the time necessary to 
construct new generation.\114\
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    \112\ Long-Term Firm Transmission Rights in Organized 
Electricity Markets, Order No. 681, FERC Stats. & Regs. ] 31,226 
(2006), order on reh'g, Order No. 681-A, 117 FERC ] 61,201 (2006).
    \113\ Standardization of Generator Interconnection Agreements 
and Procedures, Order No. 2003, FERC Stats. & Regs. ] 31,146 (2003), 
order on reh'g, Order No. 2003-A, FERC Stats. & Regs. ] 31,160, 
order on reh'g, Order No. 2003-B, FERC Stats. & Regs. ] 31,171 
(2004), order on reh'g, Order No. 2003-C, FERC Stats. & Regs. ] 
31,190 (2005), aff'd sub nom. Nat'l Ass'n of Regulatory Util. 
Comm'rs v. FERC, 475 F.3d 1277 (DC Cir. 2007); Standardization of 
Small Generator Interconnection Agreements and Procedures, Order No. 
2006, FERC Stats. & Regs. ] 31,180, order on reh'g, Order No. 2006-
A, FERC Stats. & Regs. ] 31,196 (2005), order granting 
clarification, Order No. 2006-B, FERC Stats. & Regs. ] 31,221 
(2006), appeal pending sub nom. Consolidated Edison Co. of New York, 
Inc., et al. v. FERC Docket No. 06-1018, et al; Interconnection for 
Wind Energy, Order No. 661, FERC Stats. & Regs. ] 31,186, order on 
reh'g, Order No. 661-A, FERC Stats. & Regs. ] 31,198 (2005).
    \114\ Devon Power, LLC, 115 FERC ] 61,340, order on reh'g, 117 
FERC ] 61,133 (2006), appeal pending sub nom. Maine Pub. Utils. 
Comm'n v. FERC, No. 06-1403 (DC Cir. 2007); PJM Interconnection, 
LLC, 117 FERC ] 61,331 (2006).
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2. The Need for Commission Action
    134. As noted above, long-term power contracts are an important 
element of a working market. They enable buyers and sellers to manage 
risks, they promote stability in pricing, and they provide a solid 
foundation for the financing of new generation. Despite this 
importance, both buyers and sellers perceive that it is increasingly 
difficult to enter into long-term contracts, and that fewer long-term 
contracts are being signed as a result.
    135. The Commission believes that further transparency in long-term 
electric energy markets would facilitate efforts by both sellers and 
buyers to incorporate long-term contracts as an essential part of their 
energy portfolios. This is especially true for new market participants 
that may not be aware of the full range of contract options available 
to them, including the full range of potential contract counterparties. 
During the panel on long-term contracting at the second Commission 
competition conference, a representative from PJM stated that he had 
spoken to what he termed ``smaller players'' who indicated that they 
were willing to contract for power but were unaware of who the 
available counterparties were.\115\ These ``smaller players'' said that 
they would be interested in a bulletin board on the PJM Web site that 
would facilitate networking.\116\
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    \115\ Transcript of Conference at 187, Conference on Competition 
in Wholesale Power Markets, Docket No. AD07-7-000 (May 8, 2007).
    \116\ Id.
---------------------------------------------------------------------------

    136. While the market has the most important role to play in 
disseminating information, an RTO or ISO can play an important role in 
promoting greater transparency and liquidity in long-term power 
markets, and thus help reduce possible over-reliance on its spot 
markets. The information systems it operates are well suited for making 
such information available to the parties in its region.\117\ As 
discussed below, several commenters support having RTOs and ISOs 
provide a section of their Web sites for a long-term contract bulletin 
board, which they believe would be a useful tool in assisting parties 
in finding interested

[[Page 12595]]

counterparties and facilitating long-term contracts.
---------------------------------------------------------------------------

    \117\ See id. at 117.
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    137. In light of these comments and our own observation, the 
Commission will take action in this area. We do so because of the 
importance of long-term contracts to a working market and because we 
believe greater transparency in the market will facilitate such long-
term contracts. We therefore propose that regional organizations play a 
supporting role in encouraging voluntary contracting by providing an 
online forum in which potential buyers and sellers may exchange 
information.
3. Preliminary Proposals in the ANOPR
    138. Given the importance of long-term contracts, in the ANOPR the 
Commission requested comment on any concrete steps it could take to 
facilitate voluntary long-term power contracting in organized market 
regions.\118\ Specifically, the Commission solicited comment on whether 
it should encourage greater market transparency by requiring RTOs and 
ISOs to post information that could facilitate long-term contracts, 
such as aggregate information on long-term contract prices and 
quantities, and if so, how the information could be reported so that it 
protects the confidentiality of individual contracts. The Commission 
also asked whether disseminating other information, such as estimates 
of transmission constraints and long-term congestion costs, would be 
helpful to long-term contracting.
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    \118\ The Commission noted, however, that it was mindful of the 
limits of its jurisdiction in seeking comment on this issue, as the 
Commission cannot compel buyers and sellers to enter into long-term 
contracts. The Commission also noted that the purchasing practices 
of LSEs are often dictated by state policies, not those of this 
Commission.
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    139. The Commission also solicited comment on whether it should 
require or encourage efforts to develop new standardized forward 
products and whether standardized products would facilitate long-term 
contracting. The Commission inquired about what role it should play, 
whether the Commission should encourage RTOs or ISOs to play an active 
role in this area (or whether that would place them in a position of 
undertaking commercial functions), and whether this was a role better 
played by NAESB or other industry groups.
    140. Third, the Commission asked whether it should require ISOs and 
RTOs to dedicate a portion of their Web sites for market participants 
to post offers to buy or sell power long-term. The Commission asked 
whether this proposal would prove helpful, or whether it was a service 
that would be better provided by the market.
    141. Finally, the Commission requested comments on whether it 
should consider any modification of the data requirements of the EQR-
for example, to report the start date, term, and end date of long-term 
power contracts-to provide information that would make transparent the 
average prices of long-term power contracts of various terms and 
vintages.
4. Comments on the ANOPR Proposals and Questions
    142. Commenters filed extensive comments agreeing with the 
Commission on the importance of long-term contracts in a functioning 
market. They differ, however, on the nature and extent of the problems 
with long-term contracting, what measures would best address the 
problems, and whether the Commission should attempt to deal with the 
various problems by requiring RTO or ISO actions.
    143. Most commenters recommend against most of the actions proposed 
by the Commission in the ANOPR, which address the problems through 
regulations applicable to RTOs or ISOs. Some of these commenters argue 
that market participants and the private sector should address concerns 
over long-term contracting opportunities, while others argue that the 
Commission can improve long-term contracting opportunities by 
addressing larger structural issues, identified below.
    144. The preliminary proposal to require RTOs and ISOs to reserve a 
section of their Web sites for parties to post offers to buy or sell 
power under long-term contracts has the most support, although most 
commenters do not necessarily support making this a regulatory 
requirement. A minority of commenters support this proposal--some 
strongly--including several RTOs and ISOs, state regulators, wholesale 
sellers, many small wholesale buyers, and Joint Consumer Advocates. 
Commenters indicate that such a Web site would be useful for many 
market participants, particularly new market participants, and would 
help facilitate long-term contracting. Midwest ISO and PJM indicate 
that they have already begun working on posting such discussion boards 
on their Web sites, and other RTOs and ISOs such as SPP indicate 
support for providing space on their Web sites to post such offers.
    145. Commenters opposed to this proposal indicate that the market 
already adequately performs this function, and that the RTOs and ISOs 
should be able to determine on their own whether to have a Web site 
section for bulletin board postings. EEI and Duke Energy note that PJM 
once had a bulletin board for similar purposes that fell into disuse, 
likely due to a lack of interest from market participants. Many 
commenters, such as EPSA, argue that RTOs and ISOs should be allowed to 
determine, in consultation with stakeholders, what to post on their Web 
sites. Some commenters state that legal issues may arise from having 
RTOs or ISOs post information, including concerns over confidentiality 
and potential liability for the posting of incorrect information, and 
that these issues should be addressed before any action is taken. The 
New England Conference said that it supports a regional, voluntary 
solution, where regional working groups would be created to discuss 
measures to increase information sharing.
    146. Commenters offer little support for the ANOPR proposal to 
require RTOs and ISOs to develop new standardized forward products. 
Those few commenters supporting the proposal believe that new products 
would assist customers in developing long-term contracts. Some 
commenters, such as the New York PSC and NRG, offer qualified support 
for the concept of improved forward products, but state that the 
Commission should encourage RTO or ISO participation in developing such 
products rather than require their development by the RTOs and ISOs 
themselves.
    147. A large majority of commenters oppose this proposed 
requirement. They say that the market already supplies standardized 
products, and that it is better equipped to do so than RTOs or ISOs. 
EEI notes that it already has a process for developing standardized 
products that involves working with market participants to adjust to 
changes in the market. Many commenters also note that long-term 
contracts vary considerably from transaction to transaction, making 
standardized products difficult to develop unless they are quite 
general and so less useful than they are for short-term transactions. 
Finally, some commenters note that this proposed requirement would be 
an undue burden to ISOs and RTOs.
    148. Most commenters argue strongly against adopting the ANOPR's 
preliminary proposal to require ISOs and RTOs to post information on 
long-term contract prices and quantities. They argue that this proposed 
requirement is unnecessary, is possibly counterproductive, and would 
create additional expense for the ISO or RTO. A few, such as BlueStar 
and DC Energy, support the proposal, arguing that it would increase 
transparency in the market, which would lead to greater liquidity and 
increased long-term

[[Page 12596]]

contracting. Some ISOs and RTOs also indicate that they would be 
willing to post information if directed to do so, but that 
confidentiality concerns would need to be addressed. Many commenters 
think that the requirement would not be useful because of the wide 
variation in long-term contract provisions and the time lag between 
contracting and posting of the information.\119\ Others, such as the 
OMS, argue that the data collection requirement would unduly burden 
RTOs and ISOs. The burden would be unnecessary, according to PG&E, 
PSEG, Allegheny, Ameren and others, because the market and trade press 
already provide sufficient data. Finally, many commenters point to a 
concern over the confidentiality of data and the possibility that 
posted data could be used to game the market.
---------------------------------------------------------------------------

    \119\ See Pepco at 13; New England Power Generators at 8; Dynegy 
at 3.
---------------------------------------------------------------------------

    149. Only a few commenters address the Commission's request for 
comments on whether we should consider modifications to the information 
collected on long-term contracts in the EQR. These commenters are 
generally opposed to having the Commission modify the EQR data 
reporting requirements. Although SUEZ Energy supports increased 
reporting requirements, arguing that it would create increased 
transparency for providers of retail service, most commenters believe 
that the information in the EQR is already sufficient and that any new 
information requirements could have negative effects on confidentiality 
or markets. For instance, Old Dominion notes that modifying EQR data 
could reveal competitive information and result in reduced forward 
liquidity for physical transactions.
    150. The Commission also requested comments on additional steps 
that it could take to promote long-term contracting opportunities. Many 
commenters point to the importance of contract certainty, long-term 
stability of market rules and regulatory policies, and proper market 
design in supporting long-term contracting, although comments vary on 
how best to provide for these elements. For instance, Old Dominion 
argues that the Commission should reaffirm its commitment to 
incremental changes to market design to prevent instability. PSEG notes 
that the Commission should resist changing tariffs and should not 
revise contracts under FPA section 206, where either the buyer or 
seller has miscalculated risks.
    151. A majority of commenters indicate that structural impediments 
to long-term contracting prevent market participants from fully 
utilizing long-term contracts as part of their energy portfolios. 
Impediments cited include differences between buyers and sellers in 
assessing the appropriate long-term price and assessing long-term 
risks, over-reliance on spot markets, market design, and regulatory 
uncertainty. Many commenters, such as FirstEnergy, point to buyers' and 
sellers' inability to agree on a long-term price as the real problem 
with long-term contracts. Some commenters suggest that the Commission 
should review over-reliance on the spot markets, which, they assert, 
affects forward prices and creates a disincentive for parties to engage 
in long-term deals.
    152. Commenters also propose a variety of more fundamental 
approaches for the Commission to consider for dealing with long-term 
contracting. Some commenters argue that the Commission should take a 
more sweeping look at the markets as a whole, noting that problems with 
long-term contracting are merely a symptom of market inefficiency. 
These include a request for an investigation of RTO markets and 
mandating long-term contracting through dedicating portions of 
transmission lines for long-term arrangements or requiring entities to 
have a percentage of their portfolios as long-term contracts.
    153. Two commenters, American Forest and Portland Cement 
Association, et al., include fairly detailed proposals to address 
problems with the incentives for long-term contracting. American 
Forest's proposal, the Financial Performance Obligation (FPO), appears 
to require every generating unit that receives a capacity payment to 
financially guarantee the delivery of energy to the real-time market at 
or below a specified strike price in any hour in which it is dispatched 
by the RTO to provide service. American Forest maintains that the FPO 
would connect capacity and energy markets and would provide a hedge to 
load by shifting short-term risk of market volatility in energy markets 
to suppliers. It argues that the linked real-time market clearing price 
and capacity price that would result from the FPO would provide an 
incentive for suppliers to take steps, such as long-term contracting, 
to hedge short-term volatility, and prevent suppliers from double 
recovering revenues from capacity and energy payments. Portland Cement 
Association, et al.'s proposal offers an alternative market design 
framework, Forward Capacity and Energy Market, suggesting that a 
combination of competitive and administrative procedures could be used 
to obtain the lowest-cost combination of fixed and variable costs while 
preserving the locational economic signals of Locational Marginal 
Pricing. It argues that the proposed framework also would establish 
economic incentives for both buyers (e.g., LSEs and large customers) 
and suppliers to negotiate long-term bilateral contracts.
    154. A significant number of commenters state that the Commission 
should take no action on the long-term contracting topic, but should 
instead leave any long-term contracting solution to the market.
5. Proposed Reforms
    155. The Commission proposes to require ISOs and RTOs to dedicate a 
portion of their Web sites for market participants to post offers to 
buy or sell power on a long-term basis. We are not proposing here the 
other potential actions considered in the ANOPR and are not proposing 
to address in this docket the other long-term contracting issues raised 
by some commenters.
    156. The proposal for an RTO/ISO Web site ``bulletin board'' for 
posting long-term offers to sell or buy is designed to facilitate the 
long-term contracting process by increasing the transparency of 
available sellers and buyers for market participants. Providing a place 
for buyers and sellers to offer long-term power transaction 
opportunities should alleviate concerns about sellers and buyers being 
unable to find one another and should encourage more long-term 
contracting and improve efficiency in the market at little cost. 
Improving information flow can only increase liquidity among buyers and 
sellers. The Commission believes that this requirement will not be 
burdensome for ISOs and RTOs to implement.
    157. The Commission does not propose to mandate the specific type 
of bulletin board that each ISO and RTO must post, but will require 
each to work with its stakeholders in designing a solution that works 
for its market participants. We have in mind, however, an RTO/ISO 
bulletin board that would allow persons to post offers to sell or buy 
without making the RTO or ISO responsible for the content of the 
offers. We are encouraged that some ISOs and RTOs have already 
undertaken this effort.
    158. The Commission proposes to require ISOs and RTOs to make a 
compliance filing within six months of the date of publication of the 
final rule in the Federal Register. This filing should explain the 
actions the ISO or RTO has taken to comply with the long-

[[Page 12597]]

term contracts bulletin board requirement and provide information on 
the bulletin board the ISO or RTO has chosen to implement.
    159. The Commission seeks public comment on its proposal not to set 
by rule the specific type of bulletin board that each ISO and RTO must 
post. This includes comment on whether any features are important 
enough to specify generically, such as the structure for the webpage, 
the extent to which the ISO or RTO must seek feedback on its web 
design, or whether the ISO or RTO or the market participant must post 
the information. Further, we seek comment on our assumption that the 
costs involved with implementing the proposal are minimal and should be 
recovered in the same manner as other Web site costs. In addition, the 
Commission solicits comment on the proposal that the RTO or ISO should 
not be responsible for the content of the offers on its bulletin board. 
Is a Web site that includes a clear disclaimer adequate to protect RTOs 
and ISOs from liability, or should the Commission take additional 
action? Do market participants that post offers but fail to reach 
agreement with counterparties on contract terms and conditions have any 
liability issues?
    160. As we noted earlier, PJM recently has conducted a series of 
forums on long-term contracts to gather information and facilitate the 
exchange of ideas.\120\ We encourage similar efforts by other RTOs or 
ISOs, and the ISO/RTO Council. We encourage RTOs and ISOs already 
working on solutions to these issues to take appropriate steps to 
ensure timely implementation of reasonable solutions as soon as they 
are ready. The Commission also directs Commission staff to perform an 
analysis of the level of long-term contracting in organized market 
regions.
---------------------------------------------------------------------------

    \120\ More information on the PJM forums is available at http://www.pjm.com/committees/stakeholders/drs/ltc.html.
---------------------------------------------------------------------------

    161. In addition, while we appreciate the proposals of American 
Forest and Portland Cement Association, et al. to resolve disincentives 
to conduct long-term contracting, we have concerns that various aspects 
of the proposals, such as the impact of the proposal on capacity 
markets, would require additional development, review and consideration 
before it would be ripe for inclusion in a rulemaking. The shift of 
revenues from the spot market to some form of forward obligation or 
hedging option that could occur with the FPO may well have advantages, 
but this shift may create new concerns among LSEs and others about 
capacity market operations and price levels. To help develop a greater 
level of understanding of the proposals we direct staff to conduct a 
technical conference in a separate proceeding to examine the FPO and 
Portland Cement Association, et al.'s alternative market designs and 
related issues.

C. Market-Monitoring Policies

    162. This section of the NOPR proposes regulations implementing 
market monitoring policies.
1. Background
    163. Market monitors have played an integral role in the organized 
electric markets since the latter's inception, providing valuable 
reporting and analysis services not only to the Commission, but also to 
RTOs and ISOs, to market participants, and to state commissions. In 
light of their importance, the Commission has required that all RTOs 
and ISOs incorporate a market monitoring function.\121\
---------------------------------------------------------------------------

    \121\ Regional Transmission Organizations, Order No. 2000, FERC 
Stats. & Regs. ] 31,089 at 31,155 (1999), order on reh'g, Order No. 
2000-A, FERC Stats. & Regs. ] 31,092, at 30,993 (2000), aff'd sub 
nom. Pub. Util. Dist. No. 1 of Snohomish County, Washington v. FERC, 
272 F.3d 607 (DC Cir. 2001).
---------------------------------------------------------------------------

    164. The span of years over which market monitors have now been in 
existence has given the Commission and others in the industry a track 
record upon which to evaluate the appropriate roles MMUs should play 
and the protections that might be adopted to assist them in performing 
those roles. In this NOPR, we propose reforms for MMUs designed to 
improve their abilities to monitor and report on the operation of 
organized wholesale electric markets.
2. Prior Commission Actions Regarding Market Monitoring
    165. The Commission undertook its first generic consideration of 
market monitoring in Order No. 2000, which required an RTO to include 
market monitoring as one of its minimum functions and to submit a 
market monitoring plan as part of its RTO proposal.\122\ The Order did 
not, however, impose a specific MMU structure on the RTOs. The 
Commission noted in Order No. 2000 that while MMUs were not intended to 
supplant Commission authority, they should be designed in such a way as 
to provide the Commission with an additional means of detecting market 
power abuses, market design flaws and opportunities for improvements in 
market efficiency.\123\ The Commission ordered RTOs to incorporate in 
their market monitoring plans certain standards to be met by the MMUs, 
which included ensuring objective information about the markets that 
the RTO operates or administers, proposing appropriate action regarding 
opportunities for efficiency improvement, identifying market design 
flaws or market power abuses, and evaluating whether market 
participants comply with market rules.\124\ The Commission observed 
that the information to be gleaned from market monitoring would be 
beneficial not only to the Commission, but also to state commissions 
and market participants.\125\
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    \122\ Prior to this first generic consideration of market 
monitoring, the Commission addressed market monitoring in connection 
with individual RTO/ISO proposals. See Pacific Gas and Electric Co., 
77 FERC ] 61,265 (1996), order on reh'g, 81 FERC ] 61,122 (1997), 
order on clarification, 83 FERC ] 61,033 (1998) (requiring the ISO 
to file a detailed monitoring plan and listing minimum elements for 
such a plan); Pennsylvania-New Jersey-Maryland Interconnection, 81 
FERC ] 61,257 (1997) (PJM Formation Order) (requiring PJM to develop 
a market monitoring program to evaluate market power and design 
flaws).
    \123\ Order No. 2000, FERC Stats. & Regs. ] 31,089 at 31,156.
    \124\ Id.
    \125\ Id.
---------------------------------------------------------------------------

    166. The Commission next addressed the role of market monitors in 
its 2003 Order Amending Market-Based Rate Tariffs and 
Authorizations.\126\ The Commission clarified the duties of MMUs in 
connection with enforcement matters, directing that MMUs refer 
compliance issues to the Commission \127\ and limiting direct 
enforcement action by the MMUs to objectively identifiable and 
sanctioned behavior expressly set forth in the RTO/ISO tariffs.\128\ In 
its subsequent Order on Rehearing, the Commission clarified that MMU 
personnel were not a substitute for Commission enforcement staff.\129\ 
Instead, MMUs were to provide information to the Commission and its 
staff, so that the Commission could take appropriate action under the 
FPA.
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    \126\ Investigation of Terms and Conditions of Public Utility 
Market-Based Rate Authorizations, 105 FERC ] 61,218 (2003) (Market 
Behavior Rules Order), order on reh'g, 107 FERC ] 61,175 (2004) 
(Market Behavior Rules Rehearing Order).
    \127\ Market Behavior Rules Order, 105 FERC ] 61,218 at P 184.
    \128\ Id. P 182.
    \129\ Market Behavior Rules Rehearing Order, 107 FERC ] 61,175 
at P 165.
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    167. In May of 2005, the Commission issued a Policy Statement on 
Market Monitoring Units,\130\ identifying four tasks which MMUs perform 
for which they need access to data and other

[[Page 12598]]

resources.\131\ In an Appendix to the Policy Statement, the Commission 
set forth detailed Protocols for the MMUs to follow in referring 
potential tariff or Market Behavior Rule violations to the 
Commission.\132\
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    \130\ Market Monitoring Units in Regional Transmission 
Organizations and Independent System Operators, 111 FERC ] 61,267 
(2005) (Policy Statement).
    \131\ Id. P 2-3. These functions were: (1) To identify 
ineffective market rules and tariff provisions and recommend 
proposed rule and tariff changes to the ISO or RTO that promote 
wholesale competition and efficient market behavior; (2) to review 
and report on the performance of wholesale markets in achieving 
customer benefits; (3) to provide support to the ISO or RTO in the 
administration of Commission-approved tariff provisions related to 
markets administered by the ISO or RTO; and (4) to identify 
instances in which a market participant's behavior may require 
investigation and evaluation to determine whether a tariff violation 
has occurred, or which may be a potential Market Behavior Rule 
violation, and immediately notify appropriate Commission staff for 
possible investigation.
    \132\ Id. at Appendix A. The Market Behavior Rules extant at the 
time of the Policy Statement have since been in part rescinded, with 
the remainder codified. See Conditions for Public Utility Market-
Based Rate Authorization Holders, Order No. 674, FERC Stats. & Regs. 
] 31,208 (2006) (Order No. 674). Rescinded Market Behavior Rule 2 
has been replaced by the Commission's Anti-Manipulation Rules. See 
Prohibition of Energy Market Manipulation, Order No. 670, FERC 
Stats. & Regs. ] 31,202 (Order No. 670), order denying reh'g, 114 
FERC ] 61,300 (2006).
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    168. In 2006, PJM Interconnection, LLC (PJM) filed proposed 
revisions to the MMU sections of its tariff, with the general aim of 
conforming its tariff to the provisions of the Policy Statement.\133\ 
Several parties filed comments, arguing that PJM's tariff should 
contain a clear statement of the MMU's independence and should set 
forth all the rules relevant to the responsibilities and functions of 
the MMU. In the Commission's Order on Rehearing and Compliance Filing, 
we noted that these concerns were of a generic nature and not 
necessarily limited to PJM.\134\
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    \133\ PJM Interconnection, LLC, 116 FERC ] 61,038 (2006) (PJM 
Tariff Order).
    \134\ PJM Interconnection, LLC, 117 FERC ] 61,263, at P 19 
(2006) (PJM Tariff Rehearing Order).
---------------------------------------------------------------------------

3. The Need for Commission Action
    169. The concerns raised by intervenors in the PJM case impressed 
upon the Commission the need to undertake a generic examination of 
MMUs, to see if their roles could be enhanced so as to improve the 
efficiency and transparency of organized wholesale electric markets. To 
that end, the Commission announced that we would hold a technical 
conference to explore the issues raised by the commenters.\135\
---------------------------------------------------------------------------

    \135\ Id. P 20.
---------------------------------------------------------------------------

    170. The Commission held the technical conference on market 
monitoring policies on April 5, 2007. At the conference, the 
Commissioners heard from interested commenters on several general 
subjects.\136\ Two principal issues received the bulk of attention from 
the commenters at the technical conference. Those were: (i) The need 
for, and suggested methods of achieving, independence on the part of 
MMUs so they can perform their assigned functions; and (ii) the content 
and proper recipients of the market data and analysis developed by the 
MMUs. These issues are in accord with our own observations of areas 
within the market monitoring function that need reform. For that 
reason, we have included proposals in this NOPR designed to strengthen 
market monitoring and thereby enhance the performance and transparency 
of organized RTO/ISO markets.
---------------------------------------------------------------------------

    \136\ These subjects included: the development of the concept 
and functions of market monitoring, the MMUs' role with respect to 
the Commission, the MMUs' role with respect to ISOs and RTOs, and 
the MMUs' role with respect to the various stakeholders such as 
states, generators, transmission providers, and customers. See 
Second Notice of Technical Conference, Review of Market Monitoring 
Policies, Docket No. AD07-8-000 (March 9, 2007).
---------------------------------------------------------------------------

4. Proposed Reforms
    171. The Commission advanced proposals in the ANOPR that responded 
to the concerns expressed by commenters at the technical conference and 
that reflected the Commission's own observations formed from working 
within the framework of the existing market monitoring provisions. 
These proposals were designed to strengthen market monitoring by 
safeguarding MMU independence and fostering useful and transparent 
market analysis. The Commission sought comment on the proposals, which 
fell within the two general areas of (i) independence and function and 
(ii) information sharing. In this NOPR, the Commission analyzes the 
comments received and presents revised proposals.
a. Independence and Function
    172. In the ANOPR, the Commission acknowledged the importance of 
independence on the part of MMUs, and stated that there are several 
means by which to balance independence and accountability. The 
Commission proposed a balanced and flexible approach to the problem 
which included oversight protection, tariff safeguards and tools, the 
elimination of conflicts of interest, and certain changes in the 
functions MMUs are expected to perform. The Commission solicited 
comments on the proposed changes.
i. Structure and Tools
(a) Preliminary Proposals in the ANOPR
    173. The Commission declined in the ANOPR to propose a ``one size 
fits all'' approach to the structure of MMUs, noting that there was no 
appreciable difference among the performance of the market monitors 
that could be attributed to whether they were external (an independent 
contractor who is hired by the RTO or ISO) or internal (one whose 
personnel are employees of the RTO or ISO). Therefore, the Commission 
proposed that it be left to the discretion of each RTO or ISO to decide 
whether it should have an internal MMU, an external MMU, or a hybrid 
MMU (consisting of both an internal market monitor and an external 
market monitor).
    174. To ensure that MMUs would have adequate tools with which to do 
their job, the Commission proposed requiring each RTO or ISO to include 
in its tariff a provision imposing upon itself the obligation to 
provide its MMU with access to market data, resources, and personnel 
sufficient to enable the MMU to carry out its functions. We also 
proposed that RTOs and ISOs include a tariff provision directing the 
MMU to report to the Commission any concerns it has with inadequate 
access to market data, resources, or personnel, and to describe the 
steps it has taken with the RTO or ISO to resolve these concerns.
(b) Comments on the ANOPR Proposals and Questions
    175. The overwhelming bulk of the commenters agreed with the 
Commission's proposal and opposed imposition of a ``one size fits all'' 
approach. A few favored one or the other structure. Exelon, Strategic 
Energy, and Suez favored an external model, on the grounds it could 
best ensure independence.\137\ NJBPU favored an internal model, at 
least with respect to PJM.\138\
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    \137\ Exelon at 25; Strategic Energy at 13; Suez at 9.
    \138\ NJBPU at 1-2.
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    176. There was also limited support for an alternative reporting 
structure. The Ohio PUC proposed that MMUs report to federal-state 
boards,\139\ and the FTC suggested the Commission consider the costs 
and benefits of alternative arrangements, which presumably would 
involve a structure other than an employment or contractual 
relationship between the MMU and the RTO or ISO.\140\
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    \139\ Ohio PUC at 9-14.
    \140\ FTC at 16-17. No particular alternative arrangement was 
suggested.

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[[Page 12599]]

    177. APPA stated that the real issue to be resolved is not 
structure but assuring the independence of the MMU. It proposed ``rules 
of the road'' to accomplish that objective, most of which have to do 
with providing the MMU with adequate tools with which to do its 
job.\141\ Joint Consumers Advocates also proposed specific MMU 
principles, most involving oversight or tools.\142\
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    \141\ APPA at 72-73.
    \142\ Joint Consumer Advocates at 16-19.
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    178. Most commenters supported the Commission's proposal that RTOs 
and ISOs include in their tariffs a requirement that they must provide 
the MMU with adequate tools with which to do its job.\143\ Some stated 
that access to resources must be full and unfettered.\144\ Others, 
while generally supporting the proposal, called for budgetary and cost 
containment provisions.\145\ The North Carolina Commission proposed 
transparency of budget, with any disputes being made subject to 
Commission review.\146\ Some commenters proposed that the MMU's offices 
be located on the premises of the RTO or ISO.\147\ The PJM MMU argued 
for control over its own data repository.\148\ EEI stated it did not 
believe a tariff provision requiring the MMU to report to the 
Commission any concerns it has with adequacy of resources was needed, 
as MMUs are in regular contact with the Commission and can convey any 
concerns they may have in this regard.\149\
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    \143\ See, e.g., Ameren at 36-37; Duke Energy at 20; FirstEnergy 
at 10; NYISO at 16; Ohio PUC at 12-14; Portland Cement at 17; Xcel 
at 23.
    \144\ American Forest at 45; APPA at 70; The Alliance at 17.
    \145\ EEI at 42; EPSA at 4; Mirant at 11; North Carolina 
Commission at 7; Pepco at 15; PJM Power Providers at 8; PSEG at 17; 
Reliant at 16.
    \146\ North Carolina Commission at 7.
    \147\ See, e.g., NYISO at 20; North Carolina Commission at 6.
    \148\ PJM MMU at 10.
    \149\ 149 EEI at 43.
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(c) Commission Proposal
    179. The Commission agrees with the bulk of the commenters that the 
nature of the MMU structure is not determinative of either independence 
or quality of performance, and proposes that each RTO and ISO decide 
for itself, through its appropriate stakeholder process, whether it 
will have an external, internal or hybrid MMU structure. The Commission 
also declines to remove MMUs from overview by their RTOs and ISOs; the 
MMU's principal duties involve monitoring RTO/ISO markets and advising 
the RTO or ISO on market performance. The fact that MMUs also have 
reporting obligations to outside parties does not change the 
relationship they have with the RTOs and ISOs, which are, by Commission 
policy, required to maintain a market monitoring function. It is also 
doubtful that an alternative outside structural arrangement, such as 
reporting to a federal-state board, could as effectively replicate the 
existing close exchange of data between the RTO or ISO and the MMU, 
which all acknowledge is vital if the MMU is to properly perform its 
duties.
    180. The Commission further proposes that each RTO or ISO include 
in its tariff a provision imposing upon itself the obligation to 
provide its MMU with access to market data, resources, and personnel 
sufficient to enable the MMU to carry out its functions. The RTO or ISO 
should, in addition, also be mindful of these obligations in developing 
its market monitoring budget. Furthermore, to ensure independence of 
the MMU and its analyses, the RTO or ISO tariff should specifically 
provide that the MMU shall have access to the RTO's or ISO's database 
of market information. The tariff should also specify that any data 
created by the MMUs, including reconfiguring of the RTO/ISO data, be 
kept within the exclusive control of the MMU.
    181. The Commission declines to micro-manage the RTO/ISO 
relationships with their MMUs to the extent of requiring that MMU 
offices be located on the RTO/ISO premises. We are of the view that 
concerns of this type, as well as appropriate budgetary constraints, 
are best worked out on an individual basis.
    182. The Commission has reconsidered its ANOPR proposal regarding 
inclusion of a tariff provision directing the MMU to report to the 
Commission any concerns it has with inadequate access to market data, 
resources, or personnel, or to describe the steps it has taken with the 
RTO or ISO to resolve these concerns. The inclusion of such a 
requirement may suggest that the Commission anticipates non-compliance 
on the part of the RTOs and ISOs, whereas the opposite is true. 
Furthermore, as EEI notes, adequate mechanisms are already in place for 
the MMU to bring any concerns it may have to the Commission's 
attention, including the complaint process, referrals to the 
Commission's Office of Enforcement, and informal discussions with 
Commission staff.
ii. Oversight
(a) Preliminary Proposals in the ANOPR
    183. The Commission noted that an inherent tension exists in a 
structure that requires MMUs to report to RTO/ISO management yet, at 
the same time, perform evaluations and issue reports that may be 
critical of that management. We stated that it could be difficult for 
an MMU to discharge these oversight and reporting obligations 
effectively unless it had some degree of independence from RTO/ISO 
management. The Commission proposed that each RTO and ISO, in addition 
to maintaining a market monitoring function, be required to have its 
MMU, whether internal, external, or a hybrid combination of the two, 
report either directly to the RTO's or ISO's board of directors or 
directly to a committee of independent board directors.\150\ The ANOPR 
sought comment on the Commission's authority to impose this type of 
requirement on RTOs and ISOs, as well as on the proposal itself.
---------------------------------------------------------------------------

    \150\ The ANOPR noted that this policy would mark a departure 
from the holding in the PJM Tariff Order. PJM Tariff Order, 116 FERC 
] 61,038 at P 38 (2006).
---------------------------------------------------------------------------

(b) Comments on the ANOPR Proposals and Questions
    184. The great preponderance of commenters agreed with the 
Commission's proposal, stating that reporting to the RTO or ISO board 
would give the MMU more independence than if the MMU were to report to 
management.\151\ However, CAISO and NYISO propose that in the case of a 
hybrid structure such as theirs (i.e., one which has both an internal, 
employee-staffed MMU and an external, non-employee-staffed MMU), the 
internal MMU be permitted to report to management, with the external 
MMU reporting to the board.\152\ CAISO states that this reporting 
arrangement ensures that the chief executive officer is attuned to the 
needs of the MMU and that other employees in the organization are 
committed to supporting its functions, while NYISO states that the 
arrangement enables its internal market monitor to work closely with 
the rest of company staff and have greater opportunities to review 
real-time market operations. Others suggested that the MMU report to 
management for administrative purposes (such as human resources and 
payroll).\153\
---------------------------------------------------------------------------

    \151\ See, e.g., BP Energy at 29-30; BlueStar Energy at 6; 
Dynegy at 4; EPSA at 45; FirstEnergy at 10; Industrial Consumers at 
21; Joint Consumer Advocates at 19; Mirant at 11; NARUC at 10; 
NEPOOL Participants at 28; Pepco at 15; Steel Producers at 18.
    \152\ CAISO at 3; NYISO at 26.
    \153\ EEI at 43; SoCal Edison-SDG&E at 10.
---------------------------------------------------------------------------

    185. A few commenters opposed any RTO or ISO reporting requirement 
at all, preferring that the MMU report to the

[[Page 12600]]

Commission or to a joint federal/state board.\154\ NRECA proposed that 
the Commission periodically audit the quality of the MMU's reports and 
investigations,\155\ and TAPS proposed that any change in the MMU's 
status, such as contract termination or renewal, be reviewed and 
approved by the Commission.\156\
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    \154\ See, e.g., OMS at 14-15; OPSI at 4-6; Ohio PUC at 9; North 
Carolina Commission at 6.
    \155\ NRECA at 26.
    \156\ TAPS at 58.
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    186. Reliant proposed that the MMU must report to a full cross-
section of the board.\157\ Conversely, other commenters felt that 
management representatives on the board should be excluded from MMU 
oversight.\158\ PJM agreed with the ANOPR proposal, but expressed 
concern that the board might be given an oversight responsibility 
without the authority to actually oversee the MMU.\159\ PJM states that 
any approach that does not place responsibility in the Commission for 
the functioning and performance of MMUs, while limiting the RTO's 
ability to supervise or oversee the MMU, would ``raise serious legal 
questions about the Commission's ability to limit a public utility's 
management of its business.'' \160\ This conditional objection was the 
only comment that suggested the Commission may not have the authority 
to order the proposed reporting relationship.\161\
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    \157\ Reliant at 16.
    \158\ OPSI at 4-6; Old Dominion at 22.
    \159\ PJM at 22-24.
    \160\ PJM at 24. PJM argues that the Commission does not have 
jurisdiction over utility employment relationships or contracts with 
service providers, on the grounds these functions do not constitute 
``a sale for resale or transmission of electric power in interstate 
commerce.'' PJM at n. 41.
    \161\ California PUC did not disagree that the Commission can 
require MMUs to report to the RTO or ISO board, but requested the 
Commission to set forth the basis for this authority and provide an 
opportunity to comment. California PUC at 17.
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(c) Commission Proposal
    187. The Commission proposes that the MMU, for purposes of 
supervision over its market monitoring functions, should report to the 
RTO or ISO board rather than to management. The Commission further 
proposes that management representatives on the board be excluded from 
this oversight function. However, the RTOs and ISOs, should they deem 
it appropriate, may have the MMU report to management for 
administrative purposes, such as pension management, payroll and the 
like. Furthermore, the Commission is sympathetic to the desires 
expressed by CAISO and NYISO to retain the advantages they see in their 
hybrid reporting structures. Thus, if an RTO or ISO has two market 
monitoring bodies, an internal and an external one, the Commission 
proposes that the RTO or ISO may have the internal MMU report to 
management with respect to both its market monitoring and 
administrative functions, and the external MMU report to the board.
    188. The Commission, as noted above, finds little merit in the 
suggestions that the MMU report to a body other than the RTO or ISO, 
such as to the Commission or to a federal/state board. Commenters 
afford no details as to how this structural arrangement could be 
achieved, either from an economic, jurisdictional, or practical point 
of view, or how such a potentially cumbersome structure as a joint 
inter-governmental body could oversee MMUs in a timely and responsive 
manner. The Commission itself will be adequately informed of the 
results of MMU monitoring through the referral process and through the 
various venues for the sharing of market information; this sharing of 
market information applies as well to the states and other interested 
bodies, who will thereby be adequately apprised of MMU performance and 
can bring any concerns they may have in this regard to the RTO or ISO 
or to the Commission.
    189. The Commission declines to propose a formal auditing procedure 
for MMUs, but expects that their work product will be of the highest 
quality. The Commission remains free to undertake an audit in any given 
instance, should that appear to be appropriate, and any concerns 
regarding the quality of MMU work product can always be brought to the 
Commission's attention. The Commission also declines to propose a 
blanket requirement that all changes in MMU status, such as contract 
termination or renewal, be subject to Commission review and approval. 
Although requirements of this type are currently contained in the 
contractual arrangements of certain RTOs and ISOs,\162\ the Commission 
declines to propose extending this requirement to all RTOs and ISOs, in 
accordance with our reluctance to impose a ``one size fits all'' 
approach in structural areas. We believe the issue should be dealt with 
on a case-by-case basis.
---------------------------------------------------------------------------

    \162\ E.g., Midwest ISO cannot terminate its agreement with its 
market monitor (an independent contractor) without Commission 
approval. Open Access Transmission and Energy Markets Tariff for the 
Midwest Independent Transmission System Operator, Inc., Attachment 
S-1, FERC Electric Tariff, Third Revised Volume No. 1, Second 
Revised Sheet No. 1659 (2005). SPP cannot terminate its agreement 
with its external market monitor without Commission approval. 
Southwest Power Pool Open Access Transmission Tariff, FERC Electric 
Tariff, Fourth Revised Volume No. 1, Attachment AJ, Sec.  11, Second 
Revised Sheet No. 699 (2006). The same is true for ISO-NE. 
Participants Agreement among ISO New England, Inc. and the New 
England Power Pool, et al., Sec.  9.4.5.
---------------------------------------------------------------------------

    190. With respect to PJM's concern that it may be burdened with 
oversight responsibility over MMUs without possessing full authority to 
carry out that responsibility, the Commission notes that its reporting 
proposal does nothing to increase the limitations on an RTO's or ISO's 
authority over its MMU. For MMUs that currently report to management, 
the proposal merely shifts oversight from management to the board.\163\ 
Furthermore, the monitoring functions of MMUs affect sales for resale 
and the transmission of electric power in interstate commerce, and as 
such are properly subject to Commission regulation to ensure MMU 
objectivity. As we noted in Order No. 2000,\164\ the Commission has a 
responsibility to protect against anticompetitive effects in 
electricity markets,\165\ and an independent MMU is an important 
element upon which we rely to safeguard such competition. Our proposal 
maintains oversight authority within the RTO or ISO, while fostering 
MMU independence through the elimination of direct management control. 
For these reasons, the Commission believes the proposal strikes the 
appropriate balance between MMU independence and RTO/ISO oversight.
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    \163\ PJM cites Cal. Indep. Sys. Operator Corp. v. FERC, 372 
F.3d 395 (DC Cir. 2004), in support of its concern. However, that 
case involved FERC's attempt to replace existing CAISO board members 
with a slate proposed by an independent search firm. Obviously, 
alteration of the very composition of an RTO or ISO board is an 
entirely different matter from a requirement that MMUs report to the 
board, instead of to management. The latter requirement in no way 
interferes with the internal composition of the board. Furthermore, 
the cited case noted that if FERC concluded that CAISO lacked the 
independence or other necessary attributes to constitute an ISO, it 
need not approve CAISO as an ISO. Id. at 404. Similarly, it is the 
Commission's view that the MMU may lack sufficient independence if 
it reports to management, rather than to the board; thus we may 
require RTOs and ISOs, as a condition of their continued RTO/ISO 
status, to incorporate the proposed requirement in their tariffs.
    \164\ Order No. 2000, FERC Stats. & Regs. ] 31,089 at 31,155.
    \165\ See Gulf States Utilities v. FPC, 411 U.S. 747, 758-59 
(1973).
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iii. Functions
(a) Preliminary Proposals in the ANOPR
    191. Noting that the issue of independence is integrally related to 
that of the functions MMUs are expected to perform, the Commission 
proposed continuing the following existing functions of MMUs: (1) 
Identifying ineffective market rules and

[[Page 12601]]

tariff provisions and recommending proposed rule and tariff changes; 
(2) reviewing and reporting on the performance of the wholesale 
markets; and (3) identifying and notifying the Commission staff of 
instances in which a market participant's behavior may require 
investigation. The Commission also proposed requiring the MMUs to 
advise the Commission and other interested entities, in addition to the 
RTO or ISO, of recommendations for rule or tariff changes; retaining 
the existing Protocols (with appropriate updates) governing referral of 
potential market violations to the Commission, which are included as an 
Appendix to the Policy Statement; \166\ and expanding the subject 
matter of such referrals to include suspected rule or tariff violations 
committed by an RTO or ISO as well as by market participants, as well 
as suspected violations of other Commission-approved rules and 
regulations, such as Affiliate Restrictions \167\ and Standards of 
Conduct.
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    \166\ The Commission clarified that since issuance of the Policy 
Statement, Market Behavior Rule 2, referred to in the Protocols, has 
been rescinded and replaced by the Commission's Anti-Manipulation 
Rules. Therefore, violations currently to be referred to the 
Commission include conduct suspected of violating the Anti-
Manipulation Rules, as well as tariff violations and violations of 
the remaining, codified Market Behavior Rules. See Order No. 674 and 
Order No. 670.
    \167\ The previous term ``Code of Conduct'' has been replaced by 
``Affiliate Restrictions'' in the final rule for Market-Based Rates 
for Wholesale Sales of Electric Energy, Capacity, and Ancillary 
Services by Public Utilities, Order No. 697, 72 FR 39,904 (July 20, 
2007), FERC Stats. & Regs. ] 31,252 (2007).
---------------------------------------------------------------------------

(b) Comments on the ANOPR Proposals and Questions
    192. There was general agreement from commenters concerning 
continuation of the three functions identified in the ANOPR. Several 
commenters stated that MMUs should not themselves participate in 
effectuating market design, although they should advise the RTO or ISO 
on proposed weaknesses in the existing market design and make 
suggestions for improving it.\168\ A few commenters opposed reporting 
suspected RTO or ISO violations, arguing that this would impair the 
frank exchange of information between RTO or ISO employees and the 
MMU.\169\ However, most comments on the subject supported such 
reporting, and several commenters suggested that such reporting be 
expanded to include instances of inappropriate dispatch (either too 
conservative or too aggressive) which, although not constituting tariff 
violations, might nonetheless impair optimal market performance.\170\
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    \168\ See, e.g., Old Dominion at 23; OMS at 18; OPSI at 9; NY TO 
at 15.
    \169\ NYISO at 25-26; CAISO at 7-8.
    \170\ Strategic Energy at 13.
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    193. Several commenters opposed a requirement that MMUs report 
suspected violations of the Standards of Conduct or Affiliate 
Restrictions, arguing that the MMUs do not have expertise in this area 
and should not be diverted from their main task of monitoring the 
markets.\171\ A number of the comments suggested that the MMUs should 
not audit for such violations, but should report them if they come 
across them in the ordinary course of business.\172\ Similarly, some 
commenters suggested that MMUs should not audit for suspected rule or 
tariff violations by the RTOs or ISOs, but should report them if they 
came across them in the ordinary course of business.\173\
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    \171\ See, e.g., EEI at 45; EPSA at 47; Exelon at 26; 
FirstEnergy at 10-11; Pepco at 17.
    \172\ Duke Energy at 23; NYISO at 25-26; ISO-NE at 8-9.
    \173\ ISO-NE at 8; Duke Energy at 22.
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    194. The commenters generally supported reporting proposed tariff 
or rule changes to other interested parties as well as to the RTO and 
ISO, particularly mentioning market participants and stakeholders.\174\ 
NEPOOL Participants, however, cautioned that in certain instances this 
might effectively broadcast the existence of a ``loophole'' that could 
be exploited before a rule or tariff change could be accomplished.\175\
---------------------------------------------------------------------------

    \174\ See, e.g., Old Dominion at 23; Pepco at 16; Ameren at 13; 
APPA at 76-77.
    \175\ NEPOOL Participants at 29-30.
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(c) Commission Proposal
    195. The Commission notes that its proposals in the ANOPR did not 
contemplate that the MMU make market design decisions itself, which are 
within the purview of the RTO or ISO through stakeholder processes and 
Commission approval, but rather that the MMU should advise the RTO or 
ISO and the Commission in this area. It was also not the Commission's 
intention that the MMU be required to seek out potential violations by 
the RTO or ISO, or audit for Standards of Conduct or Affiliate 
Restrictions violations. The Commission agrees that any proactive 
investigations in these areas would divert the resources of the MMU 
from its primary responsibilities and potentially embroil it in areas 
not within its core expertise. Standards of Conduct and Affiliate 
Restrictions violations in particular may be difficult to identify 
without possession of specialized knowledge. Therefore, the Commission 
agrees that any suspected violations in these areas need be referred 
only if discovered in the ordinary course of the MMU's monitoring 
duties. Any final determination as to whether a violation has occurred 
would, of course, be the responsibility of the Commission.
    196. However, the Commission finds little merit in the suggestion 
that our proposal to require MMUs to report suspected misconduct by 
RTOs and ISOs would impair the frank exchange of information between 
RTO or ISO employees and the MMU. Such an argument could equally be 
applied to scrutiny by any independent entity and, taken to its logical 
conclusion, would effectively exempt RTOs and ISOs from investigation. 
Permitting such an exemption might encourage a culture of lax adherence 
to rule and tariff requirements.
    197. The Commission agrees that an RTO or ISO could conduct 
dispatch in such a way as to result in unnecessary market 
inefficiencies, and therefore proposes that the MMU should advise 
Commission staff of any substantial concerns it has along these 
lines.\176\ With respect to broadening the reporting of proposed rule 
and tariff changes to other interested parties as well as to the RTO or 
ISO, the Commission finds merit in the concern that such broad 
dissemination of information might make entities aware of a 
``loophole'' that could be exploited before the necessary rule or 
tariff change could be effected. For that reason, the Commission 
proposes that an exception be made to the general rule of full 
disclosure, which exception would provide that in the event the MMU 
believes broad dissemination of such information in a given instance 
could lead to exploitation, that it limit distribution of the 
information to the RTO or ISO and to Commission staff, with an 
explanation of why further dissemination should be avoided at that 
time.
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    \176\ If the MMU believes the dispatch practice rises to the 
level of a tariff violation, the MMU should follow the procedures 
outlined in the Protocols for referring market violations to the 
Commission, which involve a written referral to the Office of 
Enforcement with copies to the Office of Energy Market Regulation 
and the Commission's Office of the General Counsel. Otherwise, its 
concerns should be brought to the attention of the Division of 
Energy Market Oversight in the Office of Enforcement.
---------------------------------------------------------------------------

    198. The Commission therefore proposes that the functions an MMU is 
to perform include the following: (1) Evaluating existing and proposed 
market rules, tariff provisions and market design elements for their 
effectiveness, and recommending

[[Page 12602]]

proposed rule and tariff changes not only to the RTO or ISO, but also 
to the Commission's Office of Energy Market Regulation staff and to 
other interested entities such as state commissions and market 
participants, with the caveat that the MMU is not to effectuate its 
proposed market design itself (a task belonging to the RTO or ISO), and 
with the further caveat that the MMU should limit distribution of its 
identifications and recommendations to the RTO or ISO and to Commission 
staff in the event it believes broader dissemination could lead to 
exploitation, with an explanation of why further dissemination should 
be avoided at that time; (2) reviewing and reporting on the performance 
of the wholesale markets to the RTO or ISO, the Commission, and other 
interested entities such as state commissions and market participants; 
and (3) identifying and notifying the Commission's Office of 
Enforcement staff of instances in which a market participant's 
behavior, or that of the RTO or ISO, may require investigation, 
including suspected rule or tariff violations, market manipulation, 
inappropriate dispatch, and suspected violations of Commission-approved 
rules and regulations.
    199. In furtherance of its goal of ensuring independent analysis on 
the part of MMUs, the Commission also proposes that RTOs and ISOs 
include a provision in their tariffs specifying that they may not alter 
the reports generated by the MMUs nor dictate the conclusions reached 
by the MMUs, although they may establish a reasonable mechanism for 
review and comment on MMU reports while still in draft form. The 
Commission believes this proposal will enable the MMU to receive 
potentially helpful comment, while removing the ability of the RTO or 
ISO to unreasonably influence or impede the MMU's analysis.
iv. Mitigation and Operations
(a) Preliminary Proposals in the ANOPR
    200. The Commission expressed concern about whether it was possible 
for MMUs to maintain independence in evaluating and reporting on market 
performance while at the same time providing support to the RTO or ISO 
in the administration of its tariff, which often takes the form of MMU-
conducted market power mitigation. The Commission noted that because 
the operation and mitigation functions performed by MMUs directly 
affect market outcomes and performance, an inherent conflict arises 
when an MMU reports on market outcomes that the MMU itself has 
influenced. For these reasons, the Commission proposed requiring that 
MMUs refrain from assisting the RTO or ISO in tariff administration, 
from participating in RTO/ISO market operations such as mitigation, and 
from taking direct actions to influence the market, and instead 
concentrate on their role of providing market evaluation, reports, and 
advice.
(b) Comments on the ANOPR Proposals and Questions
    201. As to the issue of tariff administration, there was 
substantial, although not universal, agreement that this was a task 
which properly falls within the purview of the RTO or ISO, not the MMU. 
A few commenters took a middle position, suggesting that in a hybrid 
structure, the internal MMU could be involved in tariff administration, 
but not the external MMU.\177\ Some commenters requested clarification 
as to what was envisioned in the concept of tariff administration.\178\
---------------------------------------------------------------------------

    \177\ EEI at 46; New York PSC at 11-12; NY TO at 16-17.
    \178\ See, e.g., OMS at 25-26; OPSI at 20-22; PSEG at 17-19.
---------------------------------------------------------------------------

    202. There was no such agreement on the proposal to remove MMUs 
from mitigation, and this issue proved to be the most contentious one 
in the entire market monitoring section. A substantial minority of 
commenters concurred in the ANOPR proposal, agreeing that it 
constituted a conflict of interest for the MMUs to conduct mitigation, 
and stating that it would compromise the MMU's independence for it to 
both evaluate market performance and conduct mitigation.\179\ A number 
of market participants, such as Dominion Resources, FirstEnergy, Duke 
Energy, Dynegy and Pepco, support the proposal. NCEMC, AWEA, and 
Silicon Valley Power also support the proposal.
    203. EPSA stated that the MMU should not assist tariff 
administration or market operations, including mitigation, on any 
independent basis not clearly outlined in the tariff.\180\ EEI agreed 
that there should be a functional separation between the MMUs and the 
operational activities of the RTOs and ISOs, which EEI states can be 
accomplished either by having the RTOs and ISOs perform operational 
functions, or having the internal market monitor perform them.\181\
---------------------------------------------------------------------------

    \179\ See, e.g., Ameren at 39; Xcel at 24; Dynegy at 5; Duke 
Energy at 23; EPSA at 45-46; Mirant at 13.
    \180\ EPSA at 45.
    \181\ EEI at 46.
---------------------------------------------------------------------------

    204. A majority of commenters, representing a spectrum of market 
participants, consumer groups, and RTOs and ISOs, opposed the proposal 
to remove the MMU from mitigation, and advanced a variety of reasons 
against it.\182\ Several commenters, including Portland Cement, the 
Pennsylvania PUC, OPSI and OMS, maintained that it would create an even 
greater conflict of interest, because the RTO or ISO would have a role 
both in rule development and implementation.\183\ Commenters also 
stated that the RTO or ISO would be more heavily influenced than would 
an MMU by market participants, upon whom it depends for its existence, 
and that its employees have close personal relationships with market 
participants and are often former employees of market 
participants.\184\ OMS suggested RTO or ISO management might be 
hesitant to perform a needed mitigation measure if the measure were to 
affect a market participant with a credible threat to leave the RTO or 
ISO.\185\ Potomac Economics suggested the RTO or ISO can be insulated 
from market participant influence by having the MMU administer 
mitigation, whereas if the RTO or ISO had responsibility for the task 
it would face the full brunt of market participant displeasure and 
influence.\186\ Midwest ISO and OPSI opined that consumers would feel 
less confidence in the fair application of mitigation were the function 
to be transferred to the RTO or ISO.\187\
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    \182\ See, e.g., American Forest at 47-49; APPA at 74-77; BP 
Energy at 31; California PUC at 21-23; Industrial Coalitions at 21-
23; Joint Consumer Advocates at 20-21; NARUC at 11; NEPOOL 
Participants at 30-32; Northeast Utilities at 13-14; New England 
Power Generators at 12-13; OMS at 23; OPSI at 13-19; Pennsylvania 
PUC at 16-17.
    \183\ Portland Cement at 19; Pennsylvania PUC at 16; OPSI at 17; 
OMS at 23.
    \184\ See, e.g., Portland Cement at 19.
    \185\ OMS at 23.
    \186\ Potomac Economics at 7-8.
    \187\ Midwest ISO at 25-26; OPSI at 13.
---------------------------------------------------------------------------

    205. Another argument against the proposal was voiced by the 
Pennsylvania PUC, which stated that RTO and ISO managers have acquired 
their primary expertise in transmission or generation operations and 
have little expertise in economics.\188\ ISO-NE and TAPS suggested that 
administering mitigation gives the MMU better familiarity with the 
working of the market and assists it in performing its analytical 
functions.\189\ Other commenters stated that most mitigation is non-
discretionary, and therefore would not draw the MMU into a substantial 
conflict of interest as far as its analytic tasks are concerned.\190\ 
One commenter suggested that a technical

[[Page 12603]]

conference be convened to examine the issue.\191\
---------------------------------------------------------------------------

    \188\ Pennsylvania PUC at 16-17.
    \189\ ISO-NE at 10-12; TAPS at 59.
    \190\ See, e.g., Potomac Economics at 6.
    \191\ New England Conference at 19.
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    206. The RTOs and ISOs, including ISO-NE, Midwest ISO, and NYISO, 
were mainly opposed to removing the MMU from mitigation.\192\ CAISO 
stated it had no opinion, but wanted clarification as to whether the 
ISO or an independent entity would do the mitigation.\193\ SPP stated 
it did not object, but indicated that it believed it would be in 
compliance if its internal MMU administered the mitigation (which was 
not the intent of the ANOPR proposal).\194\ PJM, whose market monitor 
does not administer mitigation, supports the proposal.\195\
---------------------------------------------------------------------------

    \192\ ISO-NE at 9-12; Midwest ISO at 25; NYISO at 23-24.
    \193\ CAISO at 8.
    \194\ SPP at 10.
    \195\ PJM at 25-27.
---------------------------------------------------------------------------

(c) Commission Proposal
    207. The ANOPR proposal to remove MMUs from tariff administration 
was designed to strengthen their independence. The current practice of 
allowing MMUs to support the RTOs and ISOs in tariff administration 
necessarily makes their role subordinate to that of the RTOs and ISOs, 
and thus weakens that independence. Furthermore, freeing MMUs from 
tariff administration would allow them to objectively monitor the 
markets, without the bias that might arise from their personal 
involvement in tariff administration.
    208. Some commenters argue that RTOs and ISOs do not currently have 
individuals qualified to carry out mitigation. If true, this condition 
is simply a reflection of the fact that the RTOs and ISOs have not 
needed to hire such personnel, since the MMUs were already performing 
the task for them. If necessary, RTOs and ISOs could acquire the staff 
needed to carry out mitigation functions, and once this was 
accomplished the MMUs would be able to concentrate on their core job of 
monitoring the markets, without the potential conflict of interest that 
arises from reviewing their own mitigation.
    209. Several commenters contend that RTOs and ISOs are more 
susceptible to influence from market participants than are MMUs, and 
therefore would not be as diligent in performing mitigation. However, 
mitigation is supposed to be nondiscretionary in nature. RTOs and ISOs, 
as well as MMUs, are required to limit the administration of tariff 
compliance to those provisions expressly set forth in the tariff, 
involve objectively identifiable behavior, and do not subject the 
seller to sanctions or consequences other than those expressly approved 
by the Commission and set forth in the tariff, with the right of appeal 
to the Commission.\196\ That being the case, any failure by the RTO or 
ISO to carry out required mitigation would be readily apparent to the 
MMU, whose job of monitoring the markets necessarily includes 
determining whether mitigation has been properly performed. Any 
persistent or substantial failure by the RTO or ISO in this regard 
would constitute a tariff violation and, as such, should be referred to 
the Commission's Office of Enforcement staff.
---------------------------------------------------------------------------

    \196\ Market Behavior Rules Order, 105 FERC ] 61,218 at P 182; 
Policy Statement, 111 FERC ] 61,267 at P 5.
---------------------------------------------------------------------------

    210. The Commission therefore proposes that MMUs be removed from 
tariff administration, including mitigation. Although we believe the 
advantages of doing so outweigh the temporary transition pains that may 
result, we are nonetheless sensitive to the many concerns raised by 
those commenters who oppose the proposal. We therefore solicit comments 
on the activities that would be needed to make the transition to RTO/
ISO-administered mitigation, on any difficulties the MMU might be 
anticipated to experience in monitoring mitigation performed by the RTO 
or ISO, and any additional sensitivities that commenters wish to raise 
regarding the proposal.
v. Ethics
(a) Preliminary Proposals in the ANOPR
    211. The Commission proposed imposing certain minimum ethics 
standards upon market monitor personnel, in particular prohibiting such 
personnel from owning financial interests in any market participants. 
The Commission noted that all existing RTOs and ISOs have some type of 
conflict of interest or other ethics provisions, although not always in 
their tariffs, and proposed standardizing such provisions and requiring 
their inclusion in the tariffs themselves.
(b) Comments on the ANOPR Proposals and Questions
    212. Most commenters agreed that certain minimum ethical standards 
should be imposed on MMU employees, citing in particular conflict of 
interest provisions.\197\ Many argued that the RTOs and ISOs be allowed 
the flexibility to develop their own provisions, in addition to the 
core minimum set forth by the Commission.\198\ Some commenters thought 
it unnecessary to include the standards in the tariffs, suggesting they 
could be posted on the RTO or ISO Web site instead.\199\
---------------------------------------------------------------------------

    \197\ See, e.g., Duke Energy at 24; Old Dominion at 25; OMS at 
27-28; OPSI at 22; Silicon Valley Power at 13; Steel Producers at 
19.
    \198\ See, e.g., APPA at 77; EEI at 49; Midwest ISO at 28; NYISO 
at 17; Pepco at 18-19.
    \199\ EPSA at 46; Exelon at 27.
---------------------------------------------------------------------------

(c) Commission Proposal
    213. The Commission agrees with the majority of the commenters that 
ethical standards for MMU employees should be included in the RTO or 
ISO tariff. Such inclusion would allow protest by intervenors and 
permit Commission review and enforcement.
    214. In light of the fact that RTOs and ISOs currently impose 
ethical standards on their MMUs, although not always in their tariffs, 
and which in some cases are the same standards they apply to their 
other employees, the Commission proposes that development of the 
particular ethical standards to be applied to MMUs be left in the first 
instance to the discretion of the RTOs and ISOs. However, the 
Commission believes these standards should include certain minimum 
requirements to be imposed on MMU employees, as follows: (i) Employees 
shall have no material affiliation (to be defined by the RTO or ISO) 
with any market participant or affiliate; (ii) employees shall not 
serve as an officer, employee, or partner of a market participant; 
(iii) employees shall have no material financial interest in any market 
participant or affiliate (allowing for such potential exceptions as 
mutual funds and non-directed investments); (iv) employees shall not 
engage in any market transactions other than the performance of their 
duties under the tariff; (v) employees shall not be compensated, other 
than by the RTO or ISO, for any expert witness testimony or other 
commercial services to the RTO or ISO or to any other party in 
connection with any legal or regulatory proceeding or commercial 
transaction relating to the RTO or ISO or to the RTO or ISO markets; 
(vi) employees may not accept anything of value from a market 
participant in excess of a de minimis amount, to be decided on by the 
RTO or ISO; and (vii) employees must advise their supervisor (or, in 
the case of the MMU manager himself, advise the RTO or ISO board) in 
the event they seek employment with a market participant and must 
disqualify themselves from participating in any matter that would

[[Page 12604]]

have an effect on the financial interest of such market 
participant.\200\
---------------------------------------------------------------------------

    \200\ Some external MMUs may currently have business 
associations which would be prohibited under these proposed minimum 
requirements, such as unrelated consulting work for participants in 
its RTO's or ISO's markets. If that is the case, the RTO or ISO 
should propose a suitable transition plan in its compliance filing.
---------------------------------------------------------------------------

vi. Tariff Provisions
(a) Preliminary Proposals in the ANOPR
    215. The Commission proposed that each RTO and ISO set forth all 
its provisions involving market monitoring in one section of its 
tariff, noting that in order for MMUs to achieve transparency of 
function, the detailed obligations imposed upon them must be made clear 
and accessible, and also be subject to approval and enforcement by the 
Commission.
(b) Comments on the ANOPR Proposals and Questions
    216. There was widespread support for this proposal, although some 
commenters proposed that non-substantive MMU provisions be posted 
instead on the RTO or ISO Web site.\201\ Duke Energy proposed that the 
RTO or ISO be allowed to perform centralization of the tariff 
provisions the next time it makes an amendment to its market monitoring 
rules.\202\ The PJM MMU proposed that MMU provisions be included 
elsewhere in the tariff as well as in the MMU section, if the context 
so requires.\203\
---------------------------------------------------------------------------

    \201\ EPSA at 46; Pepco at 19.
    \202\ Duke Energy at 24.
    \203\ PJM MMU at 17.
---------------------------------------------------------------------------

(c) Commission Proposal
    217. In accordance with the bulk of the comments on this subject, 
the Commission proposes that the RTOs and ISOs be required to include 
in their tariffs, and centralize in one section, all their MMU 
provisions. Including all MMU provisions in the tariff will ensure they 
are subject to the compliance requirements that attach to tariff 
provisions, and will give notice to interested parties, and thus an 
opportunity to intervene, when a tariff filing is made. As noted in the 
ANOPR, centralization of the MMU provisions has the obvious advantage 
of clarity and ease of reference. The Commission also proposes that the 
RTOs and ISOs include a mission statement for the MMU in the 
introductory portions of the section. This statement should set forth 
the goals to be achieved by the MMU, including the protection of both 
consumers and market participants by the identification and reporting 
of market design flaws and market power abuses.
    218. The Commission disagrees with the comment requesting that the 
RTOs or ISOs be permitted to delay centralization until such time as 
they may choose, or otherwise be required, to make an amendment to 
their MMU rules. Such amendments will in all likelihood be required 
after issuance of a final rulemaking in this proceeding, and in any 
event the requirement should not be unduly onerous. Therefore, the 
Commission proposes that the RTOs and ISOs centralize their MMU tariff 
provisions when they make their compliance filings in connection with 
this proceeding. The Commission also sees no reason to forbid the RTOs 
and ISOs from posting MMU provisions elsewhere in their tariffs as well 
as in their MMU sections, should clarity and context so require, as 
long as appropriate cross-referencing is made.
b. Information Sharing
    219. The Commission advanced proposals in the ANOPR that responded 
to requests of commenters at the technical conference for dissemination 
of expanded market information, and to a broader group of recipients. 
In particular, given the integral relationship between wholesale and 
retail rates, the Commission acknowledged the need for information by 
state commissions to assist them in performing their regulatory 
functions. However, the Commission noted that since public disclosure 
of certain information could harm market participants or could 
facilitate collusion under some circumstances, it was necessary to 
balance the need for information access with confidentiality concerns. 
The Commission solicited comments on the proposed changes.
i. Enhanced Information Dissemination
(a) Preliminary Proposals in the ANOPR
    220. The Commission proposed enhancing the dissemination of 
information in several areas. Specifically, the Commission proposed 
that MMUs be required to report comprehensively on aggregate market and 
RTO/ISO performance on a regular basis, but no less frequently than 
quarterly, to Commission staff, to staff of interested state 
commissions, and to the management and board of directors of the RTOs 
or ISOs. Further, the Commission proposed that MMUs should be required 
to deliver materials supporting their conclusions; make one or more of 
their staff members available for a conference call with 
representatives from the Commission, state commissions, and RTO or ISO; 
and work cooperatively to develop any further materials which might be 
useful to the Commission, to the state commissions and to the RTOs or 
ISOs.\204\ Finally, the Commission proposed that offer and bid data, 
without identification of the market participants and with a lag of 
three months, be posted on the RTO or ISO Web site.
---------------------------------------------------------------------------

    \204\ The Commission clarified that such reports and meetings 
were not intended to restrict the MMU from meeting individually with 
Commission staff, staff of state commissions, market participants, 
or other stakeholders, or sharing information with these various 
constituencies, subject to appropriate restrictions on 
confidentiality.
---------------------------------------------------------------------------

    221. The Commission requested comment on whether the proposal met 
the needs of the state commissions and whether there were other kinds 
of information needed by state commissions to fulfill their regulatory 
responsibilities. The Commission further solicited comment on whether 
there was a generic standard or test that could be used to determine 
what specific information should be provided to state commissions.
(b) Comments on the ANOPR Proposals and Questions
    222. No comments were received proposing a generic standard or test 
to determine the specific information that should be provided to state 
commissions. There were relatively few comments identifying specific 
types of data needed; \205\ rather, most commenters supporting greater 
access argued that state agencies should receive all available market 
information in order to assist them in their regulatory tasks.\206\
---------------------------------------------------------------------------

    \205\ The California PUC set forth a lengthy list of desired 
market information, such as confidential and disaggregated data, bid 
data, generator dispatch data, generator performance data, unit 
commitment, scheduled and operational levels, and what units set 
clearing prices. It cautioned, however, that California's needs are 
specific to its market design and structure as a single state ISO, 
and that data reporting protocols would vary from state to state. 
California PUC at 27-30.
    \206\ See, e.g., FirstEnergy at 11; NARUC at 6; Massachusetts AG 
at 5; Joint Consumer Advocates at 22; New York PSC at 13.
---------------------------------------------------------------------------

    223. There was substantial support for the proposal to require 
quarterly reports and conference calls.\207\ Some commenters, however, 
thought comprehensive reports would be too costly and unduly time 
consuming.\208\ Pepco suggested that these quarterly

[[Page 12605]]

reports not be as extensive as the current annual reports, in order to 
avoid an excessive drain on the money and resources of the MMUs.\209\ 
There was also concern that confidentiality protections be 
observed.\210\ At least one commenter suggested that state attorneys 
general be included in the process as well as state commissions, since 
not all energy providers and consumers are associated with entities 
regulated by state commissions.\211\ Some commenters, although 
recognizing that inclusion of market participants in conference calls 
would be unwieldy, proposed that they be included in the dissemination 
of the reports.\212\
---------------------------------------------------------------------------

    \207\ See, e.g., BlueStar Energy at 6-7; Duke Energy at 26; 
Industrial Consumers at 37; NEPOOL Participants at 32; New England 
Conference at 19; North Carolina Electric Membership at 11; NRECA at 
24; Old Dominion at 26.
    \208\ EEI at 50; EPSA at 48; Mirant at 15; Duke Energy at 26.
    \209\ Pepco at 19-20.
    \210\ Constellation at 19; J. Aron, Barclays, Morgan Stanley at 
6; Old Dominion at 26.
    \211\ APPA at 84. See also LPPC at 15.
    \212\ See, e.g., Old Dominion at 26.
---------------------------------------------------------------------------

    224. There was substantial comment on the proposal to reduce the 
lag period for offer and bid data to three months, with a majority 
either favoring the Commission's proposal or not actively opposing 
it.\213\ Some commenters stated that the lag period should be even 
shorter than three months, arguing that such information is released in 
Australia and the United Kingdom in close to real time, with no 
apparent adverse effects.\214\ Others favored retention of the six-
month period.\215\ There was substantial support for something slightly 
longer than three months, in order to avoid the problem of data release 
within the same season; such release, it was argued, would provide 
opportunities for collusion and market power abuse.\216\ EEI notes that 
different RTOs and ISOs have reached differing conclusions as to the 
appropriate lag time, and suggested that the Commission take into 
account regional differences, with a lag time no greater than six 
months and no less than three months.\217\
---------------------------------------------------------------------------

    \213\ See, e.g., Reliant at 22; PJM at 29; PSEG at 20; SMUD at 
15; CAISO at 10; Connecticut and Massachusetts Municipals at 27; DC 
Energy at 9; Massachusetts AG at 5; Midwest ISO at 29; NEPOOL 
Participants at 33.
    \214\ Industrial Consumers at 37-38; TAPS at 61.
    \215\ See, e.g., Ameren at 42; Duke Energy at 26-27; Dynegy at 
6; Industrial Coalitions at 24; NJBPU at 2; PJM MMU at 18.
    \216\ See, e.g., Dynegy at 6; NJPBU at 2; OMS at 35; OPSI at 29; 
Old Dominion at 26.
    \217\ EEI at 52-53.
---------------------------------------------------------------------------

    225. Some commenters argued that masking the identity of the 
participants harmed the smaller players, contending that the larger 
players already have software programs which enable them to ascertain 
the identities of the participants.\218\ OPSI supported maintaining 
confidentiality by the aggregation of cost data,\219\ and Reliant 
argued that bidding data should be masked to avoid matching offers with 
the known output of the plant in question, thereby revealing the 
identity of the participant.\220\
---------------------------------------------------------------------------

    \218\ Pennsylvania PUC at 18; TAPS at 62.
    \219\ OPSI at 30. OPSI includes reference price or unit 
estimated cost data within the term.
    \220\ Reliant at 22. Reliant used the term ``bid data,'' which 
the Commission assumes refers to offers, given the company's concern 
over matching offers to unit output.
---------------------------------------------------------------------------

    (c) Commission Proposal
    226. The Commission declines to propose a generic standard or test 
to determine the type of information that may be disseminated to state 
commissions. Inasmuch as there was no support for such a standard, the 
Commission believes the type of information to be released may most 
fruitfully continue to be developed on a case-by-case basis, so long as 
it generally consists of market analyses of the type regularly gathered 
by the MMUs in the course of business, and so long as it remains 
subject to appropriate confidentiality restrictions.
    227. The Commission proposes that market participants be included 
in the dissemination of reports, which could be accomplished via 
posting them on the RTO or ISO Web site. However, the Commission agrees 
that including market participants on conference calls would be 
unwieldy, and proposes limiting participation on such calls to 
Commission staff, RTO and ISO staff, staff of interested state 
commissions, and staff of state attorneys general should they express a 
desire to attend.
    228. The Commission agrees that quarterly reports should not be as 
extensive as the annual state of the market reports. Preparing overly 
extensive reports would divert the attention of the MMUs from their 
tasks of daily monitoring and of providing recommendations to the RTO 
or ISO and the Commission regarding desirable rule and tariff changes. 
The Commission also believes that the annual state of the market 
reports have proven to be useful documents, and proposes that the RTOs 
and ISOs include in their tariffs a requirement for the MMUs to produce 
them, with the same dissemination (or broader, if desired) as the 
quarterly reports.
    229. The Commission is persuaded by the comments that no harm 
generally would result from shortening the current six-month lag 
period.\221\ However, the Commission acknowledges that in some 
instances release of such information in the same season could afford 
opportunities for collusion.\222\ Therefore, the Commission proposes 
that the time period for the release of offer and bid data be reduced 
to three months, but that the RTO or ISO may propose a shorter period, 
with accompanying justification. However, if the RTO or ISO 
demonstrates a potential collusion concern, it may propose a four-month 
lag period or, alternatively, some other mechanism to delay the release 
of a report if the release were otherwise to occur in the same season 
as reflected in the data.
---------------------------------------------------------------------------

    \221\ The Commission recently approved the request of ISO-NE and 
NEPOOL to shorten the lag time for release of ISO-NE offer and bid 
data from six months to roughly three months. ISO New England Inc. 
and New England Power Pool, 121 FERC ] 61,035 (2007) (ISO-NE Bid/
Offer Order).
    \222\ In the ISO-NE Bid/Offer Order, we found that the 
combination of ISO-NE's ability to expeditiously file for a rule 
change if negative impacts on the market were experienced, and the 
existing tariff language that masks the bid/offer data, adequately 
protected against the risk of collusion.
---------------------------------------------------------------------------

    230. The Commission proposes retaining the practice of masking the 
identity of participants when releasing offer and bid data. The 
possibility raised by a few commenters that some players may be able to 
surmise the identity of participants argues, if anything, for further 
protection, not for less. The Commission further proposes that the RTO 
or ISO include in its compliance filing a justification of its policy 
regarding the aggregation or lack thereof of offer data and of cost 
data, discussing the manner in which it believes its policy avoids 
participant harm and the possibility of collusion, while fostering 
market transparency.
ii. Tailored Requests for Information
(a) Preliminary Proposals in the ANOPR
    231. The Commission proposed that state commissions may make 
reasonable requests for additional tailored information from the MMUs, 
acknowledging that information such as general analyses of the market 
and aggregated price data may assist state commissions in performing 
their regulatory functions. The Commission stated that these requests 
should be limited to information regarding general market trends and 
performance, and not encompass information designed to aid state 
enforcement or actions against individual companies. This restriction 
was proposed in light of the limited resources of MMUs and the fact 
that states have their own enforcement agencies which are more properly 
employed for such tasks. However, the Commission proposed that a state 
commission could, on a case-by-case basis, request that the Commission 
authorize the release of otherwise proscribed data. The Commission 
would then evaluate whether there was a

[[Page 12606]]

compelling need for the requested information, and decide whether 
adequate protections could be fashioned for commercially sensitive 
material.
(b) Comments on the ANOPR Proposals and Questions
    232. There was substantial support for the Commission's proposal to 
allow state commissions to make tailored requests for information, with 
the caveat that such requests should not be permitted to place too 
great a burden on the workload of the MMUs.\223\ Several commenters 
suggested this problem could be solved by limiting the information 
provided by the MMU to that generated in the ordinary course of 
business.\224\ Other commenters objected to the restriction prohibiting 
the release of information designed for enforcement purposes, arguing 
that the states have little other means of access to the necessary 
information.\225\ A number of commenters cautioned that requests for 
information must be accompanied by assurances of confidentiality.\226\ 
At least some RTOs and ISOs currently have provisions in their tariffs 
governing the release of confidential information; \227\ however, OMS 
asserts that such tariff provisions (at least with respect to Midwest 
ISO) are so restrictive as to effectively bar the release of needed 
information.\228\ Several commenters proposed that before an MMU be 
allowed to release information pertaining to a particular market 
participant, that the participant be given the opportunity to object 
and to correct any inaccurate information proposed to be released.\229\
---------------------------------------------------------------------------

    \223\ See, e.g., Reliant at 19; PJM Power Providers at 10.
    \224\ See, e.g., PJM Power Providers at 10; Exelon at 28.
    \225\ NARUC at 9; Ohio PUC at 19.
    \226\ Constellation at 19; Joint Consumer Advocates at 22; 
Midwest ISO at 30.
    \227\ See, e.g., Midwest ISO at 30; SPP at 11.
    \228\ OMS at 31.
    \229\ See, e.g., EEI at 51; FirstEnergy at 11; DC Energy at 8.
---------------------------------------------------------------------------

(c) Commission Proposal
    233. The Commission notes that entertaining tailored requests for 
information from state commissions subjects the MMU to the risk that it 
will be diverted from its core functions of monitoring the market and 
making rule and tariff recommendations to the RTO or ISO. Therefore, 
the decision as to whether to respond to such requests, assuming they 
otherwise fall within acceptable parameters, should be made by the MMU, 
in light of its budgetary and time limitations.
    234. The Commission continues to believe its proposed restriction 
on information designed for enforcement purposes is a reasonable one. 
Such requests would not only implicate serious confidentiality 
concerns, they could overwhelm the MMU's workload, as they would likely 
involve more detailed investigations than would be required for general 
market information or for MMU referrals to the Commission. While states 
may not have the tools and expertise to monitor the market as 
effectively as can the MMUs, they do have access to resources to carry 
out enforcement functions. Furthermore, the costs of state enforcement 
should rightfully be borne by the states, not by the MMUs or RTOs and 
ISOs. Therefore, the Commission proposes that MMUs may entertain 
requests for information from state commissions, so long as such 
information pertains to general market trends and performance, is not 
designed to aid state enforcement or actions against individual 
companies,\230\ and the MMU can accommodate such requests within its 
budgetary and time constraints without jeopardizing its ability to 
perform its core tariff-defined functions.
---------------------------------------------------------------------------

    \230\ However, if during the ordinary course of its activities 
an MMU were to discover evidence of wrongdoing that was within a 
state commission's jurisdiction, it is expected that the MMU would 
report such information to the state commission.
---------------------------------------------------------------------------

    235. The Commission also believes that while confidentiality 
provisions serve a useful purpose, they should not be drafted in such a 
way as to impose unnecessary barriers to the dissemination of 
information. Therefore, the Commission proposes that RTOs and ISOs 
develop confidentiality provisions for their tariffs that will protect 
commercially sensitive material, but which will not be so restrictive 
as to permit the release of little if any information.
    236. The Commission also agrees that if requested information 
pertains to specific market participants, other than offer and bid 
data, that as a matter of fairness the named market participant should 
be given notice and the opportunity to contest the information. 
Therefore, the Commission proposes that the RTOs and ISOs include such 
a provision in their tariffs.
    237. In the ANOPR, the Commission proposed permitting state 
commissions to petition the Commission on a case-by-case basis for 
information that does not fall within the proposed acceptable 
parameters. This safety valve should alleviate state concerns that they 
may be prevented from acquiring information for which they have a 
compelling need, while also ensuring that the Commission will be able 
to examine such requests in light both of state needs and the ability 
to fashion adequate confidentiality protections. Therefore, the 
Commission proposes that the RTOs and ISOs note the availability of 
this exception in their tariffs.
iii. Commission Referrals
(a) Preliminary Proposals in the ANOPR
    238. The Commission stated that MMUs should continue to respect the 
confidentiality of their referrals of suspected wrongdoing to the 
Commission, and not disclose such referrals to other entities, 
including state commissions. The Commission also expressed its 
intention not to disseminate information regarding its investigations, 
noting that the Commission's rules require that such information be 
kept nonpublic unless the Commission authorizes, in any given case, 
that it be publicly disclosed.\231\ The Commission noted, however, that 
it intended to continue the practice of Commission staff providing the 
MMUs with generic feedback regarding enforcement issues.
---------------------------------------------------------------------------

    \231\ 18 CFR 1b.9 (2007). Other exceptions include cases where 
the information has been made a matter of public record in an 
adjudicatory proceeding, and where disclosure is required by the 
Freedom of Information Act, 5 U.S.C. 552 et seq. (2006).
---------------------------------------------------------------------------

(b) Comments on the ANOPR Proposals and Questions
    239. Comments were received on both sides of this issue, with state 
representatives arguing for release of MMU referral information, for 
the results of Commission investigations, and for disclosure of the 
progress of Commission investigations.\232\ Other commenters 
acknowledged the legal and policy considerations noted by the 
Commission, and concurred in the need to maintain confidentiality.\233\ 
The California PUC, while stating that it understood the need for 
confidentiality, proposed that in the event wrongdoing is discovered 
that affects a state commission with appropriate jurisdiction, that 
such commission should be notified of the wrongdoing.\234\ Some 
commenters argued that state bodies have procedures in place to protect 
confidentiality, and so should not be barred from receiving such 
information from the MMUs and the Commission.\235\ Constellation, 
however, cautions that these procedures may not protect disclosure from 
Freedom of

[[Page 12607]]

Information Act (FOIA) requests or requests made under equivalent state 
statutes.\236\
---------------------------------------------------------------------------

    \232\ See, e.g., California PUC at 32; Ohio PUC at 19; OMS at 
37-38; OPSI at 31-32.
    \233\ See, e.g., Reliant at 19; Exelon at 29.
    \234\ California PUC at 32.
    \235\ See, e.g., New York PSC at 15; North Carolina Commission 
at 7; OPSI at 32.
    \236\ Constellation at 19.
---------------------------------------------------------------------------

(c) Commission Proposal
    240. The Commission notes that the commenters that argued for the 
release of referral and investigative information to such bodies as 
state commissions did not generally address the substantial legal and 
policy arguments against such release, other than to note that some 
state bodies have confidentiality procedures (which may or may not 
withstand FOIA-type requests). As the Commission observed in the ANOPR, 
not only do Commission rules prohibit such release, but release could 
impede the willingness of market participants to self-report and 
otherwise cooperate in investigations, and could injure innocent 
persons who might be erroneously implicated or adversely affected by 
simply being associated with an investigation. Therefore, the 
Commission proposes that the existing provisions regarding the 
confidentiality of MMU referrals to the Commission, as well as the 
confidentiality of the progress and results of its own investigations, 
be retained.
c. Pro Forma Tariff
i. Preliminary Proposals in the ANOPR
    241. Finally, the Commission in the ANOPR stated our intent to 
include in this NOPR a proposed pro forma MMU section for RTO/ISO 
tariffs, which would contain standardized core provisions but also 
allow for regional variations. The Commission stated that it 
anticipates including in the pro forma MMU section protocols for the 
referral of tariff, rule and market manipulation violations to the 
Office of Enforcement, as well as protocols for the referral of 
perceived market design flaws and recommended tariff changes to the 
Office of Energy Market Regulation. The Commission solicited comments 
on the structure and content of such a pro forma section.
ii. Comments on the ANOPR Proposals and Questions
    242. There was substantial support for a pro forma tariff section 
of core MMU provisions. However, a number of entities, such as the 
Midwest ISO, cautioned that a pro forma tariff would ignore regional 
variations, disregard stakeholder consensus and increase compliance 
burdens. Those arguing for a pro forma tariff supported the ANOPR 
proposal that each RTO or ISO be given the flexibility to propose 
individual provisions, in order to reflect regional variations. NYISO 
cautioned against the Commission attempting a pro forma mitigation 
provision.
iii. Commission Proposal
    243. The Commission had proposed in the ANOPR that a pro forma MMU 
tariff section would be limited to essential core MMU provisions, such 
as functions, oversight, tools and information sharing, thus freeing 
the RTOs and ISOs to propose regional variations. In light of the fact 
that in this NOPR we are proposing that many important aspects of the 
market monitoring relationship with the RTOs and ISOs be left to the 
discretion of the individual RTOs and ISOs, and in light of the fact 
that there may well be other regional variations which the RTOs and 
ISOs may wish to propose, the Commission believes a pro forma tariff 
section, which would necessarily have a large number of blank 
subsections, would be of limited value.
    244. For that reason, the Commission proposes that instead of 
requiring the RTOs and ISOs to follow the outlines of a pro forma MMU 
tariff section, that they conform their tariff to the requirements that 
will be ultimately set forth in the rulemaking to be issued in this 
docket, including centralization of the MMU provisions in one section. 
The Commission also proposes that each RTO and ISO include in its 
tariff protocols for the referral of tariff, rule and market 
manipulation violations to the Office of Enforcement, revised as 
discussed above, and for the referral of perceived market design flaws 
and recommended tariff changes to the Office of Energy Market 
Regulation.

D. Responsiveness of RTOs and ISOs to Stakeholders and Customers

    245. In this section of the NOPR, the Commission proposes to 
establish new criteria intended to ensure that an RTO or ISO board is 
responsive to the RTO's or ISO's customers and other stakeholders. 
These criteria will include: (1) Inclusiveness; (2) fairness in 
balancing diverse interests; (3) representation of minority positions; 
and (4) ongoing responsiveness. The Commission proposes to require each 
RTO or ISO to submit a compliance filing demonstrating that it has in 
place or will adopt practices and procedures to ensure that it is 
responsive to stakeholders and customers. In the compliance filing, the 
Commission encourages each RTO or ISO to evaluate what practices and 
procedures may best satisfy the responsiveness criteria.
    246. In the ANOPR, the Commission made a preliminary proposal to 
improve responsiveness of RTO and ISO boards of directors to customers 
and other stakeholders. By responsiveness, we mean an RTO or ISO 
board's willingness, as evidenced in its practices and procedures, to 
directly receive concerns and recommendations from customers and other 
stakeholders, and to fully consider and take actions in response to the 
issues that are raised. We also sought comment on several issues 
focusing on whether and how RTO and ISO responsiveness to stakeholders 
can be improved, including management practices and stakeholder 
participation in the budgeting process.
1. Background
    247. In Order No. 888, the Commission encouraged but did not 
require the formation of ISOs, delineating eleven principles defining 
the operations and structure of a properly functioning ISO.\237\ 
Similarly, in Order No. 2000, the Commission encouraged utilities to 
join RTOs voluntarily and set out the characteristics that an RTO must 
possess and the minimum functions that it must perform.\238\ Embodied 
in Order Nos. 888 and 2000 is the requirement that the regional 
transmission entity be independent from market participants.
---------------------------------------------------------------------------

    \237\ Promoting Wholesale Competition Through Open Access Non-
Discriminatory Transmission Services by Public Utilities; Recovery 
of Stranded Costs by Public Utilities and Transmitting Utilities, 
Order No. 888, FERC Stats. & Regs. ] 31,036, at 31,730-32 (1996), 
order on reh'g, Order No. 888-A, FERC Stats. & Regs. ] 31,048, order 
on reh'g, Order No. 888-B, 81 FERC ] 61,248 (1997), order on reh'g, 
Order No. 888-C, 82 FERC ] 61,046 (1998), aff'd in relevant part sub 
nom. Transmission Access Policy Study Group v. FERC, 225 F.3d 667 
(DC Cir. 2000), aff'd sub nom. New York v. FERC, 535 U.S. 1 (2002).
    \238\ Order No. 2000-A, FERC Stats. & Regs. ] 31,092 at 30,993.
---------------------------------------------------------------------------

    248. Although it required independence, Order No. 2000 did not 
mandate detailed governance requirements for an RTO board of directors. 
The Commission stated that, given the early stage of RTO formation, it 
would be ``counterproductive'' to impose a one-size-fits-all approach 
to governance when RTOs may have varying structures based on their 
regional needs.\239\ Therefore, the Commission stated that it would 
review governance proposals on a case-by-case basis.\240\ The 
Commission also provided guidance based on existing governance 
arrangements, emphasizing the

[[Page 12608]]

importance of stakeholder input regarding both RTO formation and 
ongoing operations. The Commission stated that stakeholder committees 
should have balanced representation on such committees so that no one 
stakeholder class dominates the committee's recommendations. The 
Commission added that, in the case of a non-stakeholder board, it is 
important that this board not become isolated.\241\ For these reasons, 
the Commission explained that both formal and informal mechanisms 
should be used to ensure that stakeholders can convey their concerns to 
the non-stakeholder board. This standard is no different for currently-
operating ISOs, as the ISO principle of independence requires fair 
representation of all types of users of the system to ensure that the 
ISO formulates policies, operates the system, and resolves disputes in 
a fair and non-discriminatory manner.\242\
---------------------------------------------------------------------------

    \239\ Id. at 31,073. The Commission noted that existing ISOs 
have varying forms of governance. Some used a two-tier form of 
governance with a non-stakeholder board and advisory committees of 
stakeholders while one ISO in particular, CAISO, employed a 
decision-making board consisting of both stakeholders and non-
stakeholders. Id.
    \240\ Id. at 31,073-74.
    \241\ Id.
    \242\ Order No. 888, FERC Stats. & Regs. ] 31,036 at 31,730-31.
---------------------------------------------------------------------------

2. Preliminary Proposals in the ANOPR
    249. In the ANOPR, the Commission made the preliminary conclusion 
that representatives of RTO and ISO customers and other stakeholders 
should have some form of effective direct access to the RTO or ISO 
board of directors.\243\ The Commission asked whether each RTO and ISO 
should be required to develop and implement a means to ensure that 
customers and other stakeholders have such access.\244\ The Commission 
made the preliminary proposal that either of two mechanisms, a hybrid 
board or a board advisory committee, could accomplish the goal of 
enhancing customer and other stakeholder access to the board.\245\
---------------------------------------------------------------------------

    \243\ ANOPR, FERC Stats. & Regs. ] 32,617 at P 148.
    \244\ Id. P 149.
    \245\ Id. P 151, 153.
---------------------------------------------------------------------------

    250. The Commission explained that a hybrid board would be composed 
of both independent members and stakeholder members, with each member 
holding a seat on the board and participating fully in board decisions 
with an equal vote. The Commission stated that a hybrid board would 
directly expose the board to stakeholders' concerns and that it 
believed that it should be possible to structure a hybrid board without 
sacrificing overall board independence.\246\
---------------------------------------------------------------------------

    \246\ The Commission also noted that certain restrictions may be 
necessary for the hybrid board proposal to ensure that stakeholder 
members do not inappropriately serve their own interests. Id. P 152.
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    251. Alternatively, the Commission suggested that a board advisory 
committee, comprised of senior executives of the various stakeholder 
groups, could serve as an expert panel that would inform the board of 
stakeholder views. The board advisory committee would have no voting 
authority on board decisions, but could make recommendations directly 
to the board on matters before the board and on matters it believes the 
board should address. The Commission stated that it envisioned such a 
committee to include members selected to represent a reasonable range 
of diverse interests.\247\
---------------------------------------------------------------------------

    \247\ Id. P 153-54.
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    252. Based on these two models of improving RTO and ISO 
responsiveness, the Commission sought comments on the following 
questions:
     How should any hybrid board be structured? What is an 
appropriate limit on the percentage of non-independent board members? 
If a variety of customer views are to be represented, what implications 
does this have for the size of the board?
     What, if any, rules and restrictions should be placed on 
the stakeholder board members of a hybrid board?
     Can the reform proposed here be met through other means 
such as increased direct board interaction with customers and other 
stakeholders, e.g., through open board meetings or through required 
attendance of board members at major stakeholder meetings of the RTO?
     Are there measures--such as customer satisfaction 
measures, cost oversight benchmarks, or stakeholder participation 
measures--that RTOs and ISOs should use to assess the success of the 
mechanism for improving responsiveness?
    253. In the ANOPR, the Commission also requested comment on whether 
any reforms are necessary to increase management responsiveness to 
stakeholders. Among specific topics, the Commission requested comment 
on whether it should encourage or require RTOs and ISOs to publish a 
strategic plan that includes plans for ensuring responsiveness to 
customers and stakeholders, set performance criteria for executive 
managers based in part on responsiveness to stakeholders, and relate 
executive compensation to a measure of responsiveness to stakeholders.
3. Comments on the ANOPR Proposals and Questions
    254. The Commission received numerous responses from commenters 
regarding the questions posed in the ANOPR. A majority agrees with the 
Commission's conclusion that more effective direct access to RTO and 
ISO boards is needed. They do not agree, however, on the mechanism to 
achieve that goal. Some commenters favor the hybrid board, but many 
express concern with this approach, preferring the board advisory 
committee. Several commenters support using both a hybrid board and a 
board advisory committee,\248\ noting that the two approaches are not 
mutually exclusive.\249\ Several commenters discussed changes in RTO 
and ISO management practices to improve the responsiveness.
---------------------------------------------------------------------------

    \248\ E.g., AEP at 7; Ameren at 44; APPA at 88. SMUD states that 
the Commission should explore both approaches. SMUD at 20-22.
    \249\ NYISO suggested a shared governance model as an 
alternative to the hybrid board and the board advisory committee 
models proposed in the ANOPR. NYISO at 6.
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a. Comments on the Hybrid Board Approach
    255. Some commenters support the proposal for a hybrid board 
approach, stating that a hybrid board would improve RTO responsiveness 
and allow stakeholder access to an RTO and ISO board.\250\ While they 
believe that such a board would be a good mechanism to achieve the 
Commission's goal, they also state that some requirements on how such a 
board should be structured are necessary. For example, California Munis 
state that stakeholder board members should not form a majority of an 
RTO's or ISO's board under a hybrid board form of governance.\251\ SMUD 
states that a hybrid board should include diverse representation and 
must be properly balanced so that no single interest is unduly 
influential.\252\ TAPS recommends that within a hybrid board, 
independent directors should hold a majority of board seats to prevent 
capture by stakeholders.\253\ Further, before implementing the hybrid 
board approach, the Connecticut and Massachusetts Municipals recommend 
that the Commission provide clarity regarding any possible conflict of 
interest concerns among stakeholder directors.\254\
---------------------------------------------------------------------------

    \250\ E.g., California Munis at 15; Silicon Valley Power at 15; 
Connecticut and Massachusetts Municipals at 16; Wisconsin Industrial 
at 11; TAPS at 34; Industrial Consumers at 40.
    \251\ California Munis at 15.
    \252\ SMUD at 21.
    \253\ TAPS at 34.
    \254\ Connecticut and Massachusetts Municipals at 17.
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    256. Industrial Consumers recommend that the Commission require 
each RTO or ISO to establish a hybrid board, but only if 
representatives of loads (large and small customers) are assured equal 
representation with

[[Page 12609]]

supply-side interests. They note that Electric Reliability Council of 
Texas (ERCOT) already has a hybrid board.\255\ Industrial Consumers 
propose that non-independent stakeholder members should represent less 
than half of the total ISO and RTO board (unlike in ERCOT). They add 
that an equal number of stakeholders should represent supply-side and 
demand-side (consumer) interests.\256\ To that end, Industrial 
Consumers state that it may be necessary to require some form of 
rotation among stakeholder groups. Finally, they note that all existing 
ISO and RTO boards already have a ``hybrid'' feature because some 
members are retired utility executives, and they urge the Commission to 
consider counting such members as stakeholders in hybrid boards.
---------------------------------------------------------------------------

    \255\ Industrial Consumers note that the ERCOT hybrid board is 
composed of the following: (1) Five unaffiliated independent board 
members (two serve as chair and vice chair); (2) independent power 
marketers; (3) industrial consumers; (4) commercial consumers; (5) 
independent retail electric providers; (6) electric cooperatives; 
(7) residential consumers; (8) investor-owned utilities; (9) 
independent generators; and (10) municipally-owned utilities. 
Industrial Consumers at 41.
    \256\ For example, a ten-member board would have four 
stakeholder members: two representing suppliers and two representing 
consumers. Id.
---------------------------------------------------------------------------

    257. Wisconsin Industrial also recommends a hybrid board structure, 
with the condition that end-use customer and supplier representation be 
equal. Wisconsin Industrial believes that a hybrid board has an 
advantage in that a variety of stakeholder interests can be objectively 
and directly represented without first being filtered through RTO and 
ISO management.\257\
---------------------------------------------------------------------------

    \257\ Wisconsin Industrial at 11.
---------------------------------------------------------------------------

    258. Further, several of the commenters that support the hybrid 
board oppose the advisory board committee, noting that such a committee 
would not provide for direct discussion and information exchange, and 
that its advice could be ignored by board members.\258\ Others note the 
disadvantages of an advisory board committee.\259\
---------------------------------------------------------------------------

    \258\ E.g., TAPS at 40-42.
    \259\ For example, Indianapolis P&L notes that, while the 
Midwest ISO advisory committee provides some value, it faces 
challenges in its communication with the board of directors because 
management views are sometimes at odds with stakeholder views, the 
time for the advisory committee to consult with the board on 
technically complex issues is limited, and competing messages from 
committee members dilute and muddle the message. Indianapolis P&L at 
6-7.
---------------------------------------------------------------------------

    259. Many commenters, however, do not support the hybrid board 
approach, emphasizing that a hybrid board can, among other things, 
jeopardize the independence of an RTO or ISO board.\260\ They contend 
that RTO and ISO independence must be preserved because it gives 
participants in organized wholesale markets the confidence that: (1) 
The markets are being administered fairly; (2) proprietary and critical 
infrastructure information is being protected; and (3) customers will 
ultimately receive the benefits of competition.
---------------------------------------------------------------------------

    \260\ E.g., California PUC at 34-35; DC Energy at 9; Comverge at 
12; Dominion Resources at 10; Duke Energy at 29; Dynegy at 7; 
FirstEnergy at 12; Industrial Coalitions at 27; ITC at 5-13; Joint 
Consumer Advocates at 24; North Carolina Commission at 8; OMS at 42; 
NARUC at 12; Old Dominion at 31; Pepco at 22; The Alliance at 19; 
Xcel at 27.
---------------------------------------------------------------------------

    260. Many commenters argue that stakeholder representation on a 
hybrid board would conflict with stakeholders' fiduciary responsibility 
to their employers, making it difficult for the stakeholder member to 
be impartial when the goal of that member's organization is to maximize 
its company's profits. Therefore, they note that it is unrealistic to 
expect stakeholder board members to refrain from acting in the best 
interests of the entity with which they are affiliated.
    261. Some commenters also question whether a hybrid board can 
ensure fair representation, arguing that smaller companies are less 
likely to have the resources necessary to participate in such a 
board,\261\ thus not all sectors of the market would be fairly 
represented, resulting in the potential for undue influence.
---------------------------------------------------------------------------

    \261\ E.g., Comverge at 12; Industrial Coalitions at 25-28; The 
Alliance at 19-20.
---------------------------------------------------------------------------

    262. To address those concerns for undue influence, commenters have 
suggested that the selection of non-independent board members should 
require a supermajority vote. APPA recommends that RTO and ISO 
stakeholder directors be elected by a supermajority of stakeholder 
sectors, contending that stakeholder representatives should be balanced 
between generation and load interests.\262\ APPA further expands on its 
proposal by stating that using a supermajority election process will 
``ensure that well-respected and knowledgeable members of the 
stakeholder community serve in this capacity.'' \263\ TAPS suggests 
that a supermajority vote requirement for selection of stakeholder 
board members would go a long way to mitigate concerns that the 
stakeholder board members would use their position inappropriately to 
advance their parochial interests.\264\
---------------------------------------------------------------------------

    \262\ APPA at 13.
    \263\ Id. at 93.
    \264\ TAPS at 45. Both APPA and TAPS reference a similar 
recommendation from a Wisconsin Public Power Inc. (WPPI) white 
paper, contained as Attachment A to the TAPS comments. WPPI suggests 
that ``selection of the interested [non-independent] board members 
should require supermajority voting approval'' and that ``an 
election of an interested board member should require an affirmative 
vote of 67 [percent] of all sectors.'' Id. at 70.
---------------------------------------------------------------------------

    263. Further, some commenters contend that a hybrid board composed 
of both independent and stakeholder members could complicate and impede 
effective board decision-making because of the effort of non-
independent stakeholders to serve their own interests.\265\ They note 
that a hybrid board is far more likely to be unwieldy and ineffective 
because of the need to represent so many different market interests. 
Several commenters also argue that the Commission does not have the 
legal authority to dictate the composition of the board of a 
Commission-regulated entity.\266\
---------------------------------------------------------------------------

    \265\ E.g., Alcoa at 28; DC Energy at 10; California PUC at 35.
    \266\ See, e.g., California PUC at 35 (citing Cal. Indep. Sys. 
Operator Corp. v. FERC, 372 F.3d 395 (DC Cir. 2004)).
---------------------------------------------------------------------------

b. Comments on the Board Advisory Committee Approach
    264. Many commenters indicate that having a board advisory 
committee is the preferable approach to achieving the Commission's goal 
of improving responsiveness of RTOs and ISOs.\267\ They state that a 
board advisory committee with a wide range of stakeholder interests 
that has direct access to the board of directors would increase RTO and 
ISO responsiveness and be the most effective way to balance the 
interests of stakeholders.
---------------------------------------------------------------------------

    \267\ E.g., California PUC at 36; Comverge at 12; Suez at 9; Old 
Dominion at 31; OPSI at 42; Joint Consumer Advocates at 24; North 
Carolina Commission at 9; NARUC at 12; Pepco at 22-23; Xcel at 27-
28.
---------------------------------------------------------------------------

    265. Several commenters state that a board advisory committee would 
be a good starting point for improving communications between the board 
and stakeholders. For example, North Carolina Electric Membership 
believes that a board advisory committee would allow stakeholders to 
provide and receive strategic insight to the boards.\268\ In addition 
to such a committee, it notes the need for more opportunities for 
communication between the board and the stakeholders. Such 
communication can be achieved by board member attendance at major 
stakeholder meetings and by board solicitation of stakeholder position 
papers on relevant

[[Page 12610]]

issues.\269\ A few of the commenters also note that they support open 
RTO and ISO board meetings.\270\
---------------------------------------------------------------------------

    \268\ North Carolina Electric Membership at 4.
    \269\ For example, North Carolina Electric Membership suggests 
``town hall'' sessions for members where board attendance is 
required on topics derived by the liaison committee (i.e., board 
advisory committee). It also notes that requiring the board to 
explain the basis for its decision on particular issues in writing 
could improve communication and add transparency to the process. 
North Carolina Electric Membership at 5.
    \270\ For example, the OMS believes that an open board meeting 
would allow stakeholders to assess the nature and quality of the 
information being provided to the board, whether the board has 
adequately understood and considered stakeholder issues and 
concerns, and whether the board has made a fair and balanced 
decision. OMS at 43. In contrast, SMUD does not support open board 
meetings, but suggests that a better alternative may be for boards 
to hold technical sessions with stakeholders for information 
gathering before board meetings take place. SMUD at 22.
---------------------------------------------------------------------------

    266. Some commenters suggest guidelines on how a board advisory 
committee should be structured and how it should function. For example, 
OPSI states that the board advisory committee: (1) Must have authority 
to make recommendations directly to the board on matters before the 
board and on matters it believes the board should address; (2) must be 
required to allow for the communication of minority views to the board; 
and (3) should have membership limited to a reasonable number of 
individuals.\271\ OPSI and NARUC recommend that state commissions and 
state consumer advocates be entitled to representation on the board 
advisory committee.\272\ North Carolina Commission proposes that the 
board advisory committee should be given the right to suggest nominees 
to board positions and that the RTO and ISO board could be required to 
respond in writing to proposals submitted by the advisory committee.
---------------------------------------------------------------------------

    \271\ OPSI at 43.
    \272\ Id. See also NARUC at 12.
---------------------------------------------------------------------------

    267. Additionally, LPPC states that a board advisory committee must 
be closely involved in RTO and ISO board discussions, must represent a 
broader range of stakeholder interests, and should supplement, not 
replace, existing stakeholder representation on operating technical 
committees.\273\
---------------------------------------------------------------------------

    \273\ LPPC at 17. See also Industrial Consumers at 41 
(suggesting that a board advisory committee should be balanced, be 
charged with electing the board members, and be responsible for 
approving any changes in the bylaws).
---------------------------------------------------------------------------

c. Comments on the Need To Increase Management Responsiveness
    268. APPA, TAPS, and the Connecticut and Massachusetts Municipals 
recommend that RTO and ISO mission statements and/or charters clearly 
define consumer-oriented goals. They recommend that these documents be 
modified to require the RTO or ISO to provide ``reliable service at the 
lowest possible reasonable rates,'' \274\ or similar wording to that 
effect. APPA would include an explicit obligation that the RTO or ISO 
work to reduce power costs to consumers.
---------------------------------------------------------------------------

    \274\ TAPS at 33.
---------------------------------------------------------------------------

    269. Several commenters also addressed the topic of performance 
criteria for executive managers' responsiveness to stakeholder and 
consumer interests. For example, DC Energy supports the Commission 
requiring each RTO and ISO to take steps to ensure management 
responsiveness, such as stakeholder input on public strategic plans, 
periodic measurement of customer satisfaction, and RTO- or ISO-
developed performance criteria for executive managers with a focus on 
reliability and market efficiency criteria.\275\ North Carolina 
Commission suggests the Commission focus on measures of responsiveness 
such as timely responses to customer or stakeholder requests.\276\ The 
North Carolina Commission also suggests that the Commission should 
focus on behavior-based measures to improve RTO and ISO effectiveness, 
such as whether the RTO and ISO has clear staff assignments; whether it 
has contact information easily available on its Web site; the length of 
time for a stakeholder to secure an answer to a question; how long it 
takes a market participant to receive a correction of a billing or 
settlement error; and how often transmission service or interconnection 
studies are delayed. LPPC suggests four areas that should be covered in 
performance measures include accomplishment of the mission, ability to 
meet budget projections, compliance with NERC standards, and measured 
stakeholder satisfaction.\277\ CAISO supports Commission adoption of 
performance criteria for executive managers, stating that it has 
already implemented most of the ANOPR proposals, including an incentive 
compensation program for all employees that contains specific goals for 
improving stakeholder processes and timely response to stakeholder 
inquiries.\278\
---------------------------------------------------------------------------

    \275\ DC Energy at 10.
    \276\ North Carolina Commission at 9-10.
    \277\ LPPC at 19.
    \278\ CAISO at 14.
---------------------------------------------------------------------------

d. Comments on Regional Differences
    270. In addition to the two approaches described in the ANOPR, 
several commenters suggest that the Commission should allow for 
regional differences, and not administer a one-size-fits-all 
approach.\279\ Instead, given the differences among RTOs and ISOs in 
governance and stakeholder needs, the Commission should require RTOs 
and ISOs to work with customers and other stakeholders to create 
programs specific to each regional entity. For example, EEI notes that 
it is important that each RTO and ISO have the flexibility to adopt the 
means of direct stakeholder access that is most effective for that 
particular RTO or ISO.\280\ NARUC also notes that stakeholder 
representation in RTO and ISO processes is not uniform across all 
sectors; therefore, it urges the Commission to review RTO and ISO 
processes to ensure equivalent treatment of all stakeholders.\281\
---------------------------------------------------------------------------

    \279\ E.g., Allegheny at 7; ISO-NE at 31-33; EPSA at 50; Pepco 
at 23; SPP at 12-13; National Grid at 17-20; EEI at 57-61.
    \280\ EEI recommends that the Commission issue a policy 
statement declaring that stakeholders should have effective direct 
access to RTO and ISO boards and executive management. It also 
argues that ``the Commission should not take any action that would 
require the basic structure of RTOs and ISOs and their underlying 
governing contracts, such as the transmission owners' agreement, to 
be reopened without the consent of the parties involved.'' EEI at 
59.
    \281\ NARUC at 13.
---------------------------------------------------------------------------

    271. OPSI recommends that the Commission not impose particular 
mandates, but should express its intention to hold RTO and ISO boards 
accountable, and leave it to the boards to develop appropriate ways to 
ensure such responsiveness. OPSI also urges the Commission to establish 
an annual opportunity for interested parties to submit an assessment of 
the RTO's or ISO's performance in the preceding year to the 
Commission.\282\
---------------------------------------------------------------------------

    \282\ OPSI at 45.
---------------------------------------------------------------------------

4. The Need for Commission Action
    272. In Order No. 2000, the Commission determined that independence 
is a required characteristic necessary for an RTO to prevent any undue 
discrimination and to bring benefits to market participants. In that 
respect, the Commission stated that an RTO's decision-making process 
must be independent in both reality and perception.\283\ The Commission 
did not believe that detailed guidance regarding governance structure 
was necessary given the early stage of RTO formation and the varying 
structures of governance among regional entities. Instead, the 
Commission required RTOs to have an ``open architecture'' so that the 
organization and its members would have the necessary flexibility to 
improve the structure, geographic scope, market scope, and operations 
of the

[[Page 12611]]

organization. Although the Commission required that proposed changes 
continue to satisfy RTO minimum characteristics and functions,\284\ 
open architecture allowed the original RTO design to evolve to reflect 
changes in member needs.
---------------------------------------------------------------------------

    \283\ Order No. 2000, FERC Stats. & Regs. ] 31,089 at 31,061.
    \284\ Id. at 31,170.
---------------------------------------------------------------------------

    273. Since Order No. 2000 was issued, RTOs and ISOs have evolved. 
Given the size and complexity of RTOs and ISOs today, it is not 
surprising that tension has arisen between the goals of independent 
decision-making and responsiveness to stakeholders, as an RTO or ISO 
cannot satisfy every group on every issue. The RTO and ISO management 
and boards of directors face increasing difficulty (as well as 
increasing responsibility) in understanding the impact of their 
decisions on the various stakeholder classes. Attempting to accommodate 
stakeholders' needs on each issue has been a difficult task borne by 
the boards and other employees of the RTOs and ISOs.
    274. Creating a mechanism and process to enable the board to be 
responsive to the needs of stakeholders is critical to an independent 
governance structure. Moreover, it is necessary for customers and other 
stakeholders to have confidence in the decisions that come out of RTO 
and ISO processes. Similarly, management responsiveness to customers 
and stakeholders plays an important role in implementing the RTO and 
ISO policies and achieving its objectives in a manner that customers 
and other stakeholders perceive to be fair, balanced, and effective. 
The Commission proposes a set of criteria, discussed below, for 
assessing the mechanism or process by which an RTO or ISO achieves 
board responsiveness to its members and customers.
5. Proposed Reform
    275. The Commission proposes to require each RTO and ISO to 
demonstrate in a compliance filing that it is achieving RTO and ISO 
responsiveness, and we propose to assess the filed practices or 
procedures for achieving RTO and ISO board responsiveness using the 
following criteria: (1) Inclusiveness; (2) fairness in balancing 
diverse interests; (3) representation of minority positions; and (4) 
ongoing responsiveness. We believe that access by customers and other 
stakeholders to the board based on these criteria will provide them 
with the opportunity to ensure that their concerns are considered. We 
also believe that any RTO or ISO practices or procedures that satisfy 
these criteria will ensure that RTO and ISO boards and management are 
reasonably responsive to the needs of RTO and ISO members and 
customers.
    276. Accordingly, an RTO or ISO must comply with this proposed 
requirement by submitting a filing that proposes changes to its 
responsiveness practices and procedures to comply with the proposed 
requirement or that demonstrates its practices and procedures already 
satisfy the requirement for responsiveness. This filing would be 
submitted within six months of the date the final rule is published in 
the Federal Register. The Commission will assess whether each filing 
satisfies the proposed requirement and issue additional orders as 
necessary.
    277. The Commission agrees with commenters that a one-size-fits-all 
approach may not be beneficial given the varying structure and needs of 
each regional entity. Therefore, instead of prescribing a specific 
mechanism for all RTOs and ISOs, the Commission proposes to take a 
flexible approach. Various mechanisms may satisfy the proposed 
criteria. We encourage each RTO or ISO to develop a mechanism that best 
suits its own governance structure and stakeholder needs. The 
Commission presented two options for consideration, the board advisory 
committee and the hybrid board.\285\ While we view the board advisory 
committee as a particularly strong mechanism for enhancing 
responsiveness, the Commission expects each RTO or ISO and its 
stakeholders to develop the mechanism that best suits its needs.
---------------------------------------------------------------------------

    \285\ Any RTO or ISO that chooses to propose a hybrid board 
structure must ensure that the non-independent board members 
constitute less than a majority of the board and must limit the 
eligibility to be a non-independent board member to market 
participants in that RTO or ISO market.
---------------------------------------------------------------------------

    278. We seek comment, however, on whether RTOs and ISOs should be 
encouraged, or required, to base their process for selecting non-
independent members of the board or of a board advisory committee on a 
supermajority vote of eligible stakeholders.
    279. We propose to require each RTO and ISO, in its compliance 
filing, to demonstrate that it has satisfied the following criteria:
     Inclusiveness--The practices and procedures must ensure 
that any customer or other stakeholder affected by the operation of the 
RTO or ISO, or its representative is permitted to communicate its views 
to the RTO or ISO board.
     Fairness in Balancing Diverse Interests--The practices and 
procedures must ensure that the interests of customers or other 
stakeholders are equitably considered and that deliberation and 
consideration of RTO and ISO issues are not dominated by any single 
stakeholder category.
     Representation of Minority Positions--The practices and 
procedures must ensure that, in instances where stakeholders are not in 
total agreement on a particular issue, minority positions are 
communicated to the board at the same time as majority positions.
     Ongoing Responsiveness--The practices and procedures must 
provide for stakeholder input into RTO or ISO decisions as well as 
mechanisms to provide feedback to stakeholders to ensure that 
information exchange and communication continue over time.
    280. The Commission proposes to require that each RTO and ISO post 
on its Web site a mission statement or charter for its organization. 
The Commission encourages each RTO and ISO to set forth in these 
documents the organization's purpose, guiding principles, and 
commitment to responsiveness to customers and other stakeholders, and 
ultimately to the consumers who benefit from and pay for electricity 
services.
    281. We also encourage each RTO and ISO to ensure that its 
management programs, including, but not limited to, incentive 
compensation plans for executive managers, give appropriate weight to 
stakeholder responsiveness. Such plans should give appropriate 
consideration to important service delivery goals such as reducing 
congestion costs, timely response to transmission service requests, 
prompt resolution of statements, billing, and disputes, and other 
customer service measures of performance.\286\
---------------------------------------------------------------------------

    \286\ The Commission understands that RTO and ISO executive 
management compensation plans may already be based on various 
measures of performance. If these already adequately take account of 
customer responsiveness, the RTO or ISO may report this in its 
compliance filing.
---------------------------------------------------------------------------

V. Applicability of the Proposed Rule and Compliance Procedures

    282. The Commission has a responsibility under FPA sections 205 and 
206 to ensure that the rates, charges, classifications, and service of 
public utilities (and any rule, regulation, practice, or contract 
affecting any of these) are just and reasonable and not unduly 
discriminatory, and to remedy undue discrimination in the provision of 
such services. Our action in this NOPR proposes to fulfill those 
responsibilities by proposing reforms to improve the operation of 
organized

[[Page 12612]]

wholesale markets. It is necessary to remedy any problems in wholesale 
markets to ensure that rates and services in RTO and ISO markets remain 
just and reasonable and not unduly discriminatory.
    283. The Commission proposes to apply the final rule in this 
proceeding to all RTOs and ISOs by requiring them to demonstrate 
compliance with the proposed requirements discussed in each section of 
the NOPR: (1) Demand response; (2) long-term power contracting; (3) 
market monitoring; and (4) RTO and ISO responsiveness. The Commission 
proposes to require each RTO and ISO to report to the Commission, on 
the deadlines specified below or six months following its certification 
as an RTO or commencement of operations as an ISO, that describes 
whether the entity is already in compliance with the requirements of 
the final rule, or describing its plans to attain compliance, including 
a timeline with intermediate deadlines and appropriate proposed tariff 
and market rule revisions. The Commission will assess whether each 
filing satisfies the proposed requirements and issue further orders for 
each RTO and ISO.
    284. For the proposed requirements under demand response, the 
filing addressing ancillary services and deviation charges, and the 
filing for ARCs and shortage pricing must be submitted within six 
months of the date the final rule is published in the Federal Register.
    285. The filing to comply with the proposed requirements regarding 
long-term contracts, MMU reforms and RTO responsiveness must be 
submitted within six months of the date the final rule is published in 
the Federal Register.

VI. Information Collection Statement

    286. The Office of Management and Budget (OMB) regulations require 
approval of certain information collection requirements imposed by 
agency rules.\287\ Upon approval of a collection(s) of information, OMB 
will assign an OMB control number and an expiration date. Respondents 
subject to the filing requirements of this rule will not be penalized 
for failing to respond to these collections of information unless the 
collections of information display a valid OMB control number. This 
NOPR amends the Commission's regulations to improve the operation of 
organized wholesale electric power markets. The objective of this 
proposed rule is to improve market design and competition in organized 
markets. Through this rule the Commission hopes to provide remedies by 
ensuring (1) that new criteria are established so RTOs and ISOs are 
responsive to their customers and stakeholders; (2) improve market 
monitoring within RTOs and ISOs by requiring them to provide their 
Market Monitoring Units with access to market data and sufficient 
resources to perform their duties; (3) transparency in the marketplace 
by requiring RTOs and ISOs to dedicate portions of their Web sites so 
market participants can avail themselves of information concerning 
offers to buy or sell power on a long-term basis; and (4) require RTOs 
and ISOs to institute certain reforms in the demand response programs 
to remove several disincentives and barriers to provide for more 
efficient operation of markets while at the same time encouraging new 
technologies. Filings by RTOs and ISOs would be made under Part 35 of 
the Commission's regulations. The information provided for under Part 
35 is identified as FERC-516.
---------------------------------------------------------------------------

    \287\ 5 CFR 1320.11 (2007).
---------------------------------------------------------------------------

    287. The Commission is submitting these reporting requirements to 
OMB for its review and approval under section 3507(d) of the Paperwork 
Reduction Act.\288\ Comments are solicited on the Commission's need for 
this information, whether the information will have practical utility, 
the accuracy of provided burden estimates, ways to enhance the quality, 
utility, and clarity of the information to be collected, and any 
suggested methods for minimizing the respondent's burden, including the 
use of automated information techniques.
---------------------------------------------------------------------------

    \288\ 44 U.S.C. 3507(d) (2000).
---------------------------------------------------------------------------

    Burden Estimate: The Public Reporting burden for the requirements 
contained in the NOPR is as follows:

----------------------------------------------------------------------------------------------------------------
                                                     Number of       Number of       Hours per     Total annual
                 Data collection                    respondents      responses       response          hours
----------------------------------------------------------------------------------------------------------------
FERC-516 Task Allow demand response to provide                 6               1             433           2,598
 certain ancillary services.....................
Remove certain deviation charges................               5               1             288           1,440
Permit aggregation of Retail Customers..........               6               1           102.5             615
Allow pricing to ration demand during a shortage               6               1             649           3,894
Long-term contract postings.....................               6               1              30             180
MMUs............................................               6               1             129             774
Require RTO board responsiveness to customers...               6               1             180            1080
Require RTO self-assessment.....................               6               1             650           3,900
                                                 ---------------------------------------------------------------
    Totals......................................  ..............  ..............  ..............          14,481
----------------------------------------------------------------------------------------------------------------

    Total Annual Hours for Collection: (Reporting + recordkeeping, (if 
appropriate)) = Total hours for performing tasks 1 through 8 as 
identified above = 14,481 hours.
    Information Collection Costs: The Commission seeks comments on the 
costs to comply with these requirements. It has projected the average 
annualized cost to be:

Legal expertise = $473,526 (2,368 hours @ $200 an hour)
Technical Expertise = $712,038 (4,747 hours @ $150 an hour) (RTO/ISO 
Senior Staff, Stakeholder participants)
Administrative Support = $108,701 (2,718 hours @ $40 an hour)
IT Support = $236,448 (2,489 hours @ $95 an hour)
Participatory Expenditures = $2,160,000 (96 participants @ $1,000 per 
day on average 4.5 days per activity for five of the eight activities 
identified above)
Total = $3,690,713
    * Differences in RTO/ISO staff hourly rates are to differentiate 
between administrative support staff and senior staff.
    Total cost estimates: $3,690,713.
    Title: FERC-516 ``Electric Rate Schedule Filings''.
    Action: Proposed Collections.
    OMB Control No: 1902-0096.
    Respondents: Business or other for profit, and/or not for profit 
institutions.
    Frequency of Responses: One time to initially comply with the rule, 
and then

[[Page 12613]]

on occasion as needed to revise or modify.
    Necessity of the Information: This proposed rule, if adopted, would 
further the improvement of competitive wholesale electric markets and 
the provision of transmission services in the RTO and ISO regions. The 
Commission recognizes that significant differences exist among the 
regions, industry structures, and sources of electric generation, 
population demographics and even weather patterns. In fulfilling its 
responsibilities under sections 205 and 206 of the Federal Power Act, 
the Commission is required to address, and has the authority to remedy, 
undue discrimination and anticompetitive effects.
    Internal review: The Commission has reviewed the requirements 
pertaining to transmission organizations with organized electricity 
markets and determined the proposed requirements are necessary to meet 
the provisions of the Federal Power Act.
    288. These requirements conform to the Commission's plan for 
efficient information collection, communication and management within 
the energy industry. The Commission has assured itself, by means of 
internal review, that there is specific, objective support for the 
burden estimates associated with the information requirements.
    289. Interested persons may obtain information on the reporting 
requirements by contacting: Federal Energy Regulatory Commission, 888 
First Street, NE., Washington, DC 20426, Attention: Michael Miller, 
Office of the Executive Director, Phone: (202) 502-8415, fax: (202) 
273-0873, e-mail: [email protected]. Comments on the requirements 
of the proposed rule may also be sent to the Office of Information and 
Regulatory Affairs, Office of Management and Budget, Washington, DC 
20503, Attention: Desk Officer for the Federal Energy Regulatory 
Commission, fax (202) 395-7285, e-mail: [email protected].

VII. Environmental Analysis

    290. The Commission is required to prepare an Environmental 
Assessment or an Environmental Impact Statement for any action that may 
have a significant adverse effect on the human environment.\289\ The 
Commission concludes that neither an Environmental Assessment nor an 
Environmental Impact statement is required for this NOPR under section 
380.4(a)(15) of the Commission's regulations, which provides a 
categorical exemption for approval of actions under sections 205 and 
206 of the FPA relating to the filing of schedules containing all rates 
and charges for the transmission or sale subject to the Commission's 
jurisdiction, plus the classification, practices, contracts, and 
regulations that affect rates, charges, classifications, and 
services.\290\
---------------------------------------------------------------------------

    \289\ Regulations Implementing the National Environmental Policy 
Act, Order No. 486, FERC Stats. & Regs. ] 30,783 (1987).
    \290\ 18 CFR 380.4(a)(15) (2007).
---------------------------------------------------------------------------

VIII. Regulatory Flexibility Act Certification

    291. The Regulatory Flexibility Act of 1980 (RFA) \291\ generally 
requires a description and analysis of rules that will have significant 
economic impact on a substantial number of small entities. Most, if not 
all, of the transmission organizations to which the requirements of 
this rule would apply do not fall within the definition of small 
entities.\292\
---------------------------------------------------------------------------

    \291\ 5 U.S.C. 601-12 (2000).
    \292\ The RFA definition of ``small entity'' refers to the 
definition provided in the Small Business Act, which defines a 
``small business concern'' as a business that is independently owned 
and operated and that is not dominant in its field of operation. See 
5 U.S.C. 601(3), citing to Section 3 of the Small Business Act, 15 
U.S.C. 632 (2000). The Small Business Size Standards component of 
the North American Industry Classification system defines a small 
utility as one that, including its affiliates is primarily engaged 
in the generation, transmission, or distribution of electric energy 
for sale, and whose total electric output for the preceding fiscal 
years did not exceed 4 MWh. 13 CFR 121.202 (Sector 22, Utilities, 
North American Industry Classification System, NAICS) (2004).
---------------------------------------------------------------------------

    Those entities to be impacted directly by this rule include the 
following:
     California Independent Service Operator Corp. (CAISO) is a 
nonprofit organization comprised of more than 90 electric transmission 
companies and generators operating in its markets and serving more than 
30 million customers.
     New York Independent System Operator, Inc. (NYISO) is a 
nonprofit organization that oversees wholesale electricity markets 
serving 19.2 million customers. NYISO manages a 10,775-mile network of 
high-voltage lines.
     PJM Interconnection, LLC (PJM) is comprised of more than 
450 members including power generators, transmission owners, 
electricity distributors, power marketers and large industrial 
customers and serving 13 states and the District of Columbia.
     Southwest Power Pool, Inc. (SPP) is comprised of 50 
members serving 4.5 million customers in 8 states and has 52,301 miles 
of transmission lines.
     Midwest Independent Transmission System Operator, Inc. 
(Midwest ISO) is a nonprofit organization with over 131,000 megawatts 
of installed generation. Midwest ISO has 93,600 miles of transmission 
lines and serves 15 states and one Canadian province.
     ISO New England Inc. (ISO-NE) is a regional transmission 
organization serving 6 states in New England. The system is comprised 
of more than 8,000 miles of high voltage transmission lines and several 
hundred generating facilities of which more than 350 are under ISO-NE's 
direct control.
    Therefore, the Commission certifies that this rule will not have a 
significant economic impact on a substantial number of small entities. 
Accordingly, no regulatory flexibility analysis is required.

IX. Comment Procedures

    292. The Commission invites interested persons to submit comments 
on the matters and issues proposed in this notice to be adopted, 
including any related matters or alternative proposals that commenters 
may wish to discuss. Comments are due April 21, 2008. Comments must 
refer to Docket Nos. AD07-7-000 and RM07-19-000, and must include the 
commenter's name, the organization they represent, if applicable, and 
their address in their comments.
    293. The Commission encourages comments to be filed electronically 
via the eFiling link on the Commission's Web site at http://www.ferc.gov. The Commission accepts most standard word processing 
formats. Documents created electronically using word processing 
software should be filed in native applications or print-to-PDF format 
and not in a scanned format. Commenters filing electronically do not 
need to make a paper filing.
    294. Commenters that are not able to file comments electronically 
must send an original and 14 copies of their comments to: Federal 
Energy Regulatory Commission, Secretary of the Commission, 888 First 
Street, NE., Washington, DC 20426.
    295. All comments will be placed in the Commission's public files 
and may be viewed, printed, or downloaded remotely as described in the 
Document Availability section below. Commenters on this proposal are 
not required to serve copies of their comments on other commenters.

X. Document Availability

    296. In addition to publishing the full text of this document in 
the Federal Register, the Commission provides all interested persons an 
opportunity to view and/or print the contents of this document via the 
Internet through FERC's Home Page (http://www.ferc.gov)

[[Page 12614]]

and in FERC's Public Reference Room during normal business hours (8:30 
a.m. to 5 p.m. Eastern time) at 888 First Street, NE., Room 2A, 
Washington DC 20426.
    297. From FERC's Home Page on the Internet, this information is 
available on eLibrary. The full text of this document is available on 
eLibrary in PDF and Microsoft Word format for viewing, printing, and/or 
downloading. To access this document in eLibrary, type the docket 
number excluding the last three digits of this document in the docket 
number field.
    298. User assistance is available for eLibrary and the FERC's Web 
site during normal business hours from FERC Online Support at 202-502-
6652 (toll free at 1-866-208-3676) or e-mail at 
[email protected], or the Public Reference Room at (202) 502-
8371, TTY (202) 502-8659. E-mail the Public Reference Room at 
[email protected].

List of Subjects in 18 CFR Part 35

    Electric power rates, Electric utilities, Reporting and 
recordkeeping requirements.

    By direction of the Commission. Commissioner Kelly concurring in 
part and dissenting in part with a separate statement attached. 
Commissioner Wellinghoff concurring with a separate statement attached.

 Nathaniel J. Davis, Sr.,
Deputy Secretary.
    In consideration of the foregoing, the Commission proposes to amend 
part 35, Chapter I, Title 18, of the Code of Federal Regulations, as 
follows:

PART 35--FILING OF RATE SCHEDULES AND TARIFFS

    1. The authority citation for part 35 continues to read as follows:

    Authority: 16 U.S.C. 791a-825r, 2601-2645; 31 U.S.C. 9701; 42 
U.S.C. 7101-7352.

    2. Amend Sec.  35.28 as follows:
    a. Amend paragraph (b) to add paragraphs (b)(4), (b)(5), (b)(6), 
and (b)(7).
    b. Add a new paragraph (g).


Sec.  35.28  Non-discriminatory open access transmission tariff.

* * * * *
    (b) * * *
    (4) Demand response means a reduction in the consumption of 
electric energy by customers from their expected consumption in 
response to an increase in the price of electric energy or to incentive 
payments designed to induce lower consumption of electric energy.
    (5) Demand response resource means a resource capable of providing 
demand response.
    (6) An operating reserve shortage means a period when the amount of 
available supply falls short of demand plus the operating reserve 
requirement.
    (7) Market Monitoring Unit (MMU) means the person or entity 
responsible for carrying out the market monitoring functions which the 
Commission has ordered Commission-approved ISOs and RTOs to perform.
* * * * *
    (g) Tariffs and operations of Commission-approved ISOs and RTOs--
(1) Demand response and pricing. (i) Ancillary services provided by 
demand response resources. (A) Every Commission-approved ISO and RTO 
that operates organized markets based on competitive bidding for energy 
imbalance, spinning reserves, supplemental reserves, reactive power and 
voltage control, and regulation and frequency response ancillary 
services (or its functional equivalent in the Commission-approved ISO's 
or RTO's tariff) must accept bids from demand response resources in 
these markets for that product on a basis comparable to any other 
resources, if the demand response resource meets the necessary 
technical requirements under the tariff and submits a bid under the 
Commission-approved ISO's or RTO's bidding rules at or below the 
market-clearing price, unless the laws or regulations of the relevant 
retail regulatory authority do not permit a retail customer to 
participate.
    (B) The Commission-approved ISO or RTO must allow providers of a 
demand response resource to specify the following in their bids:
    (1) A maximum duration in hours that the demand response resource 
may be dispatched;
    (2) A maximum number of times that the demand response resource may 
be dispatched during a day; and
    (3) A maximum amount of electric energy that the demand response 
resource may be required to provide either daily or weekly.
    (ii) Removal of deviation charges. A Commission-approved ISO or RTO 
with a tariff that contains a day-ahead and a real-time market may not 
assess a charge to a purchaser of electric energy in its day-ahead 
market for purchasing less power in the real-time market during a real-
time market period for which the Commission-approved ISO or RTO 
declares an operating reserve shortage or makes a generic request to 
reduce load to avoid an operating reserve shortage.
    (iii) Aggregation of retail customers. Commission-approved ISOs or 
RTOs must permit a qualified aggregator of retail customers to bid a 
demand response on behalf of retail customers directly into the 
Commission-approved ISO's or RTO's organized markets, unless the laws 
and regulations of the relevant electric retail regulatory authority do 
not permit a retail customer to participate.
    (iv) Price formation during periods of operating reserve shortage. 
(A) Commission-approved ISOs and RTOs must modify their market rules to 
allow the market-clearing price during periods of operating reserve 
shortage to reach a level that rebalances supply and demand so as to 
maintain reliability while providing sufficient provisions for 
mitigating market power.
    (B) A Commission-approved ISO or RTO may phase in this modification 
of its market rules.
    (2) Long-term power contracting in organized markets. A Commission-
approved ISO or RTO must provide a portion of its Web site for market 
participants to post offers to buy or sell power on a long-term basis.
    (3) Market monitoring policies. (i) Commission-approved ISOs and 
RTOs must modify their tariff provisions governing their Market 
Monitoring Units to reflect the directives provided in Order No. 
[insert order number], including the following:
    (A) Commission-approved ISOs and RTOs must include in their tariffs 
a provision to provide their Market Monitoring Units access to 
Commission-approved ISO and RTO market data, resources and personnel to 
enable the Market Monitoring Unit to carry out their functions.
    (B) The tariff provision must provide the Market Monitoring Unit 
complete access to the Commission-approved ISO's and RTO's database of 
market information.
    (C) The tariff provision must provide that any data created by the 
Market Monitoring Unit, including, but not limited to, reconfiguring of 
the Commission-approved ISO's and RTO's data, will be kept within the 
exclusive control of the Market Monitoring Unit.
    (D) The Market Monitoring Unit must report to the Commission-
approved ISO or RTO board of directors, with its management members 
removed, or to an independent committee of the Commission-approved ISO 
or RTO board of directors. A Commission-approved ISO and RTO that has 
both an internal MMU and an external MMU may permit the internal MMU to 
report to management and the external MMU to report to the Commission-
approved ISO or RTO board of directors with its management members 
removed, or to an

[[Page 12615]]

independent committee of the Commission-approved ISO or RTO board of 
directors.
    (E) Commission-approved ISOs and RTOs may not alter the reports 
generated by the Market Monitoring Unit, or dictate the conclusions 
reached by the Market Monitoring Unit.
    (F) Commission-approved ISOs and RTOs must consolidate the core 
Market Monitoring Unit provisions into one section in their tariffs as 
provided in paragraph (g)(6) of this section.
    (ii) Functions of Market Monitoring Unit. The Market Monitoring 
Unit must perform the following functions:
    (A) Evaluate existing and proposed market rules, tariff provisions 
and market design elements for their effectiveness and recommend 
proposed rule and tariff changes to the Commission-approved ISO or RTO, 
to the Commission's Office of Energy Market Regulation staff and to 
other interested entities such as state commissions and market 
participants.
    (B) Review and report on the performance of the wholesale markets 
to the Commission-approved ISO or RTO, the Commission, and other 
interested entities such as state commissions and market participants 
on at least a quarterly basis and submit a more comprehensive annual 
state of the market report. The Market Monitoring Unit may issue 
additional reports as necessary.
    (C) Identify and notify the Commission's Office of Enforcement 
staff of instances in which a market participant's or the Commission-
approved ISO's or RTO's behavior may require investigation, including, 
but not limited to, suspected rule or tariff violations, market 
manipulation, inappropriate dispatch, and suspected violations of 
Commission-approved rules and regulations.
    (D) The Market Monitoring Unit, whether internal or external, may 
not participate in the administration of the Commission-approved ISO's 
or RTO's tariff, including mitigation.
    (iii) Market Monitoring Unit ethical standards. Commission-approved 
ISOs and RTOs must include ethical standards for employees in their 
Market Monitoring Units. At a minimum, the ethical standards must 
include the following requirements:
    (A) Market Monitoring Unit employees must have no material 
affiliation with any market participant or affiliate.
    (B) Market Monitoring Unit employees must not serve as an officer, 
employee, or partner of a market participant.
    (C) Market Monitoring Unit employees must have no material 
financial interest in any market participant or affiliate with 
potential exceptions for mutual funds and non-directed investments.
    (D) Market Monitoring Unit employees must not engage in any market 
transactions other than the performance of their duties under the 
tariff.
    (E) Market Monitoring Unit employees must not be compensated for 
any expert witness testimony or other commercial services to the 
Commission-approved ISO or RTO or to any other party in connection with 
any legal or regulatory proceeding or commercial transaction relating 
to the Commission-approved ISO or RTO or to the Commission-approved ISO 
or RTO markets.
    (F) Market Monitoring Unit employees may not accept anything of 
value from a market participant in excess of a de minimis amount.
    (G) Market Monitoring Unit employees must advise a supervisor in 
the event they seek employment with a market participant, and must 
disqualify themselves from participating in any matter that would have 
an effect on the financial interest of the market participant.
    (4) Offer and bid data. (i) Unless a Commission-approved ISO or RTO 
obtains Commission approval for a different period, Commission-approved 
ISOs and RTOs must release their offer and bid data within three 
months.
    (ii) Commission-approved ISOs and RTOs may mask the identity of 
market participants when releasing offer and bid data.
    (5) Responsiveness of Commission-approved ISOs and RTOs. 
Commission-approved ISOs and RTOs must adopt business practices and 
procedures that achieve Commission-approved ISO and RTO board of 
directors' responsiveness to customers and other stakeholders and 
satisfy the following criteria:
    (i) Inclusiveness. The practices and procedures must ensure that 
any customer or stakeholder affected by the operation of the 
Commission-approved ISO or RTO, or its representative, is permitted to 
communicate its views to the RTO or ISO board;
    (ii) Fairness in balancing diverse interests. The practices and 
procedures must ensure that the interests of customers or other 
stakeholders are equitably considered and that deliberation and 
consideration of Commission-approved ISO and RTO issues are not 
dominated by any single stakeholder category;
    (iii) Representation of minority positions. The practices and 
procedures must ensure that, in instances where stakeholders are not in 
total agreement on a particular issue, minority positions are 
communicated to the board of directors at the same time as majority 
positions; and
    (iv) Ongoing responsiveness. The practices and procedures must 
provide for stakeholder input into RTO or ISO decisions as well as 
mechanisms to provide feedback to stakeholders to ensure that 
information exchange and communication continue over time.
    (6) Compliance filings. All Commission-approved ISOs and RTOs must 
make a compliance filing with the Commission as described in Order No. 
[insert order number] under the following schedule:
    (i) The compliance filing addressing the accepting of bids from 
demand response resources in markets for ancillary services on a basis 
comparable to other resources, removal of deviation charges, 
aggregation of retail customers, shortage pricing during periods of 
operating reserve shortage, long-term power contracting in organized 
markets, Market Monitoring Units, Commission-approved ISO and RTO board 
of directors' responsiveness, and reporting on the study of the need 
for further reforms to remove barriers to comparable treatment of 
demand response resources must be submitted on or before [insert date 
that is six months after date of publication of Final Rule in the 
Federal Register].
    (ii) A public utility that is approved as a Regional Transmission 
Organization under Sec.  35.34 of this part, or that is not approved 
but begins to operate regional markets for electric energy or ancillary 
services after [insert effective date of Final Rule], must comply with 
Order No. [insert order number] and the provisions of paragraphs (g)(1) 
through (g)(5) of this section before beginning operations.

    Note: The following appendices will not appear in the Code of 
Federal Regulations.

Appendix A: Commenter Acronyms Commenters to the ANOPR in Docket Nos. 
RM07-19-000 and AD07-7-000

    AARP, et al.--AARP; American Antitrust Institute; American 
Chemistry Council; American Forest & Paper Association; American 
Iron and Steel Institute; American Municipal Power-Ohio; American 
Public Power Association; Association of Businesses Advocating 
Tariff Equity; Citizen Power; Citizens Utility Board of Illinois; 
Coalition of Midwest Transmission Customers; Colorado Office of 
Consumer Counsel; Consumer Federation of America; Council of 
Industrial Boiler Owners; Democracy and Regulation;

[[Page 12616]]

Electricity Consumers Resource Council; Florida Industrial Power 
Users Group; Illinois Industrial Energy Consumers; Illinois Public 
Interest Research Group; Industrial Energy Consumers of America; 
Industrial Energy Consumers of Pennsylvania; Industrial Energy 
Users-Ohio; Louisiana Energy Users Group; Maryland Office of the 
People's Counsel; Maryland Public Interest Research Group; Missouri 
Industrial Energy Consumers; National Association of State Utility 
Consumer Advocates; NEPOOL Industrial Customer Coalition; Office of 
the People's Counsel of the District of Columbia; Ohio Hospital 
Association, Ohio Manufacturers' Association; Ohio Partners for 
Affordable Energy; PJM Industrial Customer Coalition, Portland 
Cement Association; Power in the Public Interest, Public Citizen, 
Inc.; Public Utility Law Project of New York, Inc.; Steel 
Manufacturers Association; West Virginia Energy Users Group; 
Wisconsin Industrial Energy Group, Inc.; and Wisconsin Paper 
Council.
    AEP--American Electric Power Service Corporation.
    Alcoa--Alcoa, Inc.
    Allegheny Energy--Allegheny Power and Allegheny Energy Supply 
Company, LLC.
    Ameren--Ameren Services Company.
    American Forest--American Forest & Paper Association.
    APPA--American Public Power Association.
    ATC--American Transmission Company, LLC.
    AWEA--American Wind Energy Association.
    Blue Ridge--Blue Ridge Power Agency.
    BlueStar Energy--BlueStar Energy Services, Inc.
    BP Energy--BP Energy Company.
    Cal DWR--California Department of Water Resources State Water 
Project.
    CAISO--California Independent System Operator Corporation.
    California Munis--California Municipal Utilities Association.
    California PUC--California Public Utilities Commission.
    COMPETE Coalition--171 various entities.
    COMPETE, et al.--7-Eleven, Inc.; Allegheny Energy, Alliance for 
Real Energy Options; Alliance for Retail Choice, Alliance for Retail 
Energy Markets; Alliance for Retail Markets; Ardmore Power 
Logistics; Professor Ross Baldick, IEEE Fellow, Department of 
Electrical and Computer Engineering, The University of Texas at 
Austin; Big Lots Stores, Inc.; Nora Mead Brownell, BC Consulting, 
former FERC Commissioner and former PaPUC Commissioner; H. Sterling 
Burnett, PhD., Senior Fellow, National Center for Policy Analysis; 
California Alliance for Competitive Energy Solutions; California 
Grocers Association; California Retailers Association; Laura 
Chappelle, Attorney, former Chairman, MI PSC; Colorado Independent 
Energy Association; Constellation Energy; Comverge, Maryland; DC 
Energy, LLC; David W. DeRamus, Partner, Bates White, LLC; Direct 
Energy Services, LLC; Richard A. Drom, Partner, Powell Goldstein 
LLP; Edison Mission Energy; Electric Power Supply Association; 
Electric Power Generation Association; Energy Association of 
Pennsylvania; Energy Curtailment Specialists, Inc.; Enermetrix; 
Enerwise Global Technologies; Exelon Corporation; FirstEnergy Corp.; 
William L. Flynn, Partner, Harris Beach PLLS, former Chairman, NY 
PSC; John Hanger, former PaPUC Commissioner; Hess Corp.; William W. 
Hogan, Raymond Plank Professor of Global Energy Policy, John F. 
Kennedy School of Government, Harvard University; Illinois Energy 
Association; Independent Power Producers of New York; JC Penny; 
Kimball Resources, Inc.; Jerry J. Langdon, former FERC Commissioner; 
LS Power Associates, LP; Luminant; Macy's Inc., Midwest Independent 
Power Suppliers; Mirant Corporation; Elizabeth A. Moler, Exelon 
Corp., former Chair of FERC; National Energy Marketers Association; 
New England Energy Alliance; New England Power Generators 
Association, Inc.; Northwest and Intermountain Power Producers 
Coalition; NRG Energy, Inc.; Nuclear Energy Institute; PennFuture; 
PetSmart, Inc.; Piney Creek LP; PJM Power Providers Group; PowerGrid 
Systems, Inc.; PPL Corporation; Priority Power Management, Ltd.; 
PSEG Companies; John M. Quain, Buchanan Ingersoll & Rooney PC, 
former Chairman of PaPUC; Reliant Energy; Retail Energy Suppliers 
Association; Safeway, Inc.; School Project for Utility Rate 
Reduction; Sempra Energy; Shell Energy North America; Silicon Valley 
Leadership Group; Vernon L. Smith, Nobel Laureate, Professor of 
Economics and Law, Chapman University; David A. Svanda, Svanda 
Consulting, former MI PSC Commissioner and former President of 
NARUC; Glen Thomas, GT Power, former Chairman of PaPUC; Telga 
Corporation; Texas Competitive Power Advocates; TXU Energy; Wal-Mart 
Stores, Inc.; Western Power Trading Forum; and Pat Wood, III, former 
Chairman of FERC and the PUCT.
    Comverge--Comverge, Inc.
    Connecticut and Massachusetts Municipals--Connecticut Municipal 
Electric Energy Cooperative and Massachusetts Municipal Wholesale 
Electric Company.
    Constellation--Constellation Energy Commodities Group, Inc.; 
Constellation NewEnergy, Inc.; and Constellation Generation Group, 
LLC.
    DC Energy--DC Energy, LLC.
    Detroit Edison--Detroit Edison Company.
    Dominion Resources--Dominion Resources Services, Inc.
    Duke Energy--Duke Energy Corporation.
    Dynegy--Dynegy Power Corporation.
    EEI--Edison Electric Institute and Alliance of Energy Suppliers.
    EnergyConnect--Energy Connect, Inc.
    Energy Curtailment--Energy Curtailment Specialists, Inc.
    EnerNOC--EnerNOC, Inc.
    EPSA--The Electric Power Supply Association.
    Exelon--Exelon Corporation.
    FTC--Federal Trade Commission.
    FirstEnergy--FirstEnergy Service Company, on behalf of 
FirstEnergy Solutions Corp. and the transmission and distribution 
owning utility subsidiaries of FirstEnergy Corp.: American 
Transmission Systems, Inc.; The Cleveland Electric Illuminating 
Company; Jersey Central Power and Light Company; Metropolitan Edison 
Company; Ohio Edison Company; Pennsylvania Electric Company; 
Pennsylvania Power Company; and The Toledo Edison Company.
    Mr. Hogan--William W. Hogan and Susan L. Pope.
    Indianapolis P&L--Indianapolis Power and Light Company.
    Industrial Coalitions--Coalition of Midwest Transmission 
Customers; NEPOOL Industrial Customer Coalition; and PJM Industrial 
Customer Coalition.
    Industrial Consumers--Electricity Consumers Resource Council; 
American Iron and Steel Institute; and American Chemistry Council.
    ISO-NE--ISO New England, Inc.
    ISO/RTO Council--ISO/RTO Council: California Independent System 
Operator Corporation; ISO New England, Inc.; the Midwest Independent 
Transmission System Operator, Inc.; New York Independent System 
Operator, Inc.; PJM Interconnection, LLC; Southwest Power Pool.
    ITC--International Transmission Company and Michigan Electric 
Transmission Company, LLC.
    Integrys--Integrys Energy Services, Inc.
    J.Aron, Barclays, Morgan Stanley--J.Aron & Company, Barclays 
Capital, and Morgan Stanley Capital Group Inc.
    Joint Consumer Advocates--Ohio Consumers Counsel; District of 
Columbia Office of the People's Counsel; Pennsylvania Office of 
Consumer Advocate; Illinois Citizens Utility Board; Maryland Office 
of People's Counsel; and New Jersey Department of the Public 
Advocate, Division of Rate Counsel.
    Kansas CC--Kansas Corporation Commission.
    LPPC--Large Public Power Council.
    Massachusetts AG--Massachusetts Attorney General.
    Mr. McCullough--Robert McCullough.
    Midwest ISO--Midwest Independent Transmission System Operator, 
Inc.
    Midwest ISO TOs--Midwest ISO Transmission Owners.
    Mirant--Mirant Corporation.
    NARUC--National Association of Regulatory Utility Commissions.
    National Energy Marketers--National Energy Marketers 
Association.
    National Grid--National Grid USA.
    NEPOOL Participants--NEPOOL Participants Committee.
    New England Conference--New England Conference of Public 
Utilities Commissioners; Connecticut Department of Public Utility 
Control; Massachusetts Department of Public Utilities; Massachusetts 
Department of Energy Resources; New Hampshire Public Utilities 
Commission; Rhode Island Public Utilities Commission; the Vermont 
Department of Public Service; and Vermont Public Service Board.
    New England Power Generators--New England Power Generators 
Association.
    New York PSC--New York State Public Service Commission.
    NJBPU--New Jersey Board of Public Utilities.
    NJ BPU Commissioner Bator--New Jersey Board of Public Utilities 
Commissioner Christine V. Bator.

[[Page 12617]]

    North Carolina Commission--North Carolina Utilities Commission; 
Public Staff--North Carolina Utilities Commission; and the Attorney 
General of the State of North Carolina.
    North Carolina Electric Membership--North Carolina Electric 
Membership Corporation.
    Northeast Utilities--Northeast Utilities.
    NRECA--National Rural Electric Cooperative Association.
    NRG--NRG Energy, Inc.
    NSTAR--NSTAR Electric Company.
    NYISO--New York Independent System Operator Corp.
    NY TOs--New York Transmission Owners.
    Ohio PUC--Public Utilities Commission of Ohio.
    Old Dominion--Old Dominion Electric Cooperative.
    OMS--Organization of MISO States.
    OPSI--Organization of PJM States, Inc.
    Otter Tail--Otter Tail Power Company.
    Pennsylvania PUC--Pennsylvania Public Utilities Commission.
    Pepco--Pepco Holdings, Inc.; Delmarva Power & Light Company; 
Atlantic City Electric Company; Conectiv Energy Supply Inc.; and 
Pepco Energy Services, Inc.
    PGC--PGC Electricity Committee.
    PG&E--Pacific Gas and Electric Company.
    PJM--PJM Interconnection, LLC.
    PJM Power Providers--PJM Power Providers Group.
    PJM MMU--Independent Market Monitoring Unit of PJM.
    Portland Cement--Portland Cement Association.
    Portland Cement Association, et al.--Multiple Intervenors; PJM 
Industrial Customer Coalition; Connecticut Industrial Energy 
Consumers; Industrial Energy Users-Ohio; Mittal Steel USA, Inc.
    Potomac Economics--Potomac Economics, Inc.
    Power in Public Interest--Power in the Public Interest.
    PPL Parties--PPL Parties.
    PSEG--PSEG Companies: Public Service Electric and Gas Company; 
PSEG Power LLC and PSEG Energy Resources & Trade LLC.
    Public Interest Organizations--Center for Energy Efficiency & 
Renewable Technologies; Connecticut Office of Consumer Counsel; 
Conservation Law Foundation; Delaware Division of the Public 
Advocate; Environmental Law & Policy Center; Fresh Energy, Natural 
Resources Defense Council; New Hampshire Office of Consumer 
Advocate; Office of the Ohio Consumers' Counsel; Pace Energy 
Project; Project for Sustainable FERC Energy Policy; Renewable 
Northwest Project; Union of Concerned Scientists and West Wind 
Wires.
    Reliant--Reliant Energy, Inc.
    Safeway--Safeway, Inc.
    Silicon Valley Power--Silicon Valley Power.
    SMUD--Sacramento Municipal Utility District.
    SoCal Edison-SDG&E--Southern California Edison Company and San 
Diego Gas & Electric.
    SPP--Southwest Power Pool, Inc.
    Steel Manufacturers--Steel Manufacturers Association.
    Steel Producers--Steel Producers.
    Strategic Energy--Strategic Energy, LLC.
    SUEZ--SUEZ Energy North America, Inc.
    TAPS--Transmission Access Policy Study Group.
    The Alliance--The Alliance For Retail Energy Markets.
    Utility Savings--Utility Savings & Refund, LLC.
    Wal-Mart--Wal-Mart Stores, Inc.
    Wisconsin Industrial--Wisconsin Industrial Energy Group.
    WSPP--WSPP Inc.
    Xcel--Xcel Energy Services, Inc., on behalf of Northern States 
Power Company; Northern States Power Company; Wisconsin, Public 
Service Company of Colorado; and Southwestern Public Service 
Company.

United States of America Federal Energy Regulatory Commission

Wholesale Competition in Regions With Organized Electric Markets--
Docket Nos. RM07-19-000 AD07-7-000

Issued February 22, 2008.
KELLY, Commissioner, concurring in part and dissenting in part:
    I support many of the efforts enumerated in the Notice of 
Proposed Rulemaking (NOPR) which requests comment on proposals to 
improve the operation of wholesale electric markets. I believe that 
it is extremely important that we ensure that wholesale markets are 
competitive thereby allowing the Commission to fulfill our statutory 
mandate to ensure adequate and reliable non-discriminatory service 
at just and reasonable rates. Unfortunately, I am concerned 
regarding the potential impact of several of the proposals related 
to demand response, market monitoring, and promoting regional 
transmission organization (RTO)/independent system operator (ISO) 
responsiveness.
    I continue to be troubled by the NOPR's proposal in the Market 
Rules Governing Price Formation During Periods of Operating Reserve 
Shortage section. This section would attempt to stimulate demand 
response by allowing RTOs/ISOs to implement scarcity pricing by 
modifying market power mitigation rules in organized markets, such 
as raising energy supply offer caps and demand bid caps. I 
appreciate the efforts made in the NOPR to address market power 
associated with scarcity pricing and to ensure that there is an 
adequate record regarding any scarcity pricing proposal, including 
soliciting the views of each RTO/ISO market monitor on any proposed 
reform in this area. However, these positive changes in the NOPR 
proposal have not alleviated my concerns regarding the very real 
impacts on customers associated with raising energy supply offer 
caps and demand bid caps in emergency situations.
    I believe that absent appropriate resource adequacy requirements 
and the necessary demand response infrastructure to give consumers 
the ability to respond to higher prices, it is not responsible to 
allow energy supply offer caps and demand bid caps to rise without 
regard to the impacts on consumers. I do not per se oppose scarcity 
pricing. However, I believe that there is a crucial timing issue 
that we must consider regarding any scarcity pricing proposal. Prior 
to implementing scarcity pricing in any market, we must have 
resources in place to meet demand. One essential way to accomplish 
this goal is through resource adequacy requirements. If a market is 
resource adequate, then there will be fewer emergency situations 
and, when those emergencies do occur, having demand response in 
place will help reduce prices in times of scarcity. Therefore, 
resource adequacy requirements and the ability of demand response to 
participate in a market go hand in hand with protecting consumers 
from market power and thereby making scarcity pricing proposals just 
and reasonable.
    Some may look at this as a chicken and egg debate where if we 
allow energy supply offer caps and demand bid caps to increase 
without restraint this will raise prices thereby encouraging 
additional generation and demand response to enter the market. On 
the other hand, what happens in the meantime to consumers as we 
allow prices to rise without restraint and we are still waiting for 
these theoretical incentives to building adequate generation and 
demand response infrastructure to kick in? We must never lose sight 
of the interests of consumers as we engage in this kind of 
philosophical debate because they will be the ones who will lose out 
if we miscalculate. The necessary generation and demand response 
infrastructure must be in place prior to allowing energy supply 
offer caps and demand bid caps to rise or be eliminated. 
Unfortunately, this is not the case. As Commission staff noted in 
the 2006 FERC Staff Demand Response Assessment, advanced metering 
currently has low market penetration of less than six percent in the 
United States.\293\ This means that consumers do not have the tools 
they need in order to make choices regarding rising prices and 
respond accordingly.
---------------------------------------------------------------------------

    \293\ Assessment of Demand Response and Advanced Metering: Staff 
Report, Docket No. AD06-2-000, at 26 (2006) (2006 FERC Staff Demand 
Response Assessment).
---------------------------------------------------------------------------

    On the issue of market monitoring, I disagree with the NOPR's 
proposal to remove market monitors from tariff administration, 
particularly market power mitigation. I believe that market 
monitoring units (MMUs) should continue to perform mitigation. The 
NOPR states that the issue of removing MMUs from mitigation ``proved 
to be the most contentious one in the entire market monitoring 
section.'' \294\ This is for good reason. As Portland Cement noted 
in its comments, ``The MMU's are better positioned to make 
determinations regarding the exercise of market power than are the 
RTO/ISO staff members who frequently have long standing close 
personal relationships with the very market participants whose 
actions at times need to be mitigated.'' \295\ Further, I agree with 
Portland Cement's statement that having RTO/ISO staff mitigate 
creates a much greater conflict of interest than any incidental

[[Page 12618]]

conflict created by having the internal MMU both mitigate and report 
on the functioning of the markets.\296\ The New York Independent 
System Operator (NYISO) also agrees that the concerns expressed in 
support of removing the MMU from mitigation are misplaced.\297\ 
NYISO further stated that ``[t]here is no reason to fear that a 
market monitor would hesitate to report market power problems or 
potential market abuses just because it was involved in implementing 
mitigation measures in that market.'' \298\ BP Energy asserts that 
``shifting the mitigation responsibility to RTO staff gives rise to 
a much larger conflict of interest than exists with having 
mitigation responsibility lie with the independent MMU 
exclusively.'' \299\ Therefore, I disagree with the NOPR's proposal 
to remove MMUs from mitigation.
---------------------------------------------------------------------------

    \294\ Wholesale Competition in Regions with Organized Electric 
Markets, Notice of Proposed Rulemaking, 122 FERC ] 61,617, at P 202 
(2008).
    \295\ Portland Cement Association Aug. 16, 2007 Comments, Docket 
Nos. AD07-7, RM07-19, at 19.
    \296\ Id.
    \297\ NYISO Sept. 14, 2007 Comments, Docket Nos. AD07-7, RM07-
19, at 23.
    \298\ Id. at 24 (citation omitted).
    \299\ BP Energy Company Sept. 14, 2007 Comments, Docket Nos. 
AD07-7, RM07-19, at 31.
---------------------------------------------------------------------------

    Additionally, I would have strengthened the market monitoring 
section. For example, the NOPR proposes to retain existing 
provisions regarding the confidentiality of the progress and results 
of the Commission's own investigations. I believe that, subject to 
appropriate confidentiality limitations, the Commission should 
provide MMUs with information on referrals that the MMU provides to 
the Commission. I would also have supported requiring RTOs/ISOs to 
file tariff provisions to allow them to take enforcement action with 
respect to objectively identifiable behavior that does not subject 
the seller to sanctions or consequence other than those expressly 
approved by the Commission and set forth in the tariff and with the 
right of appeal, consistent with the Policy Statement on Market 
Monitoring Units.\300\
---------------------------------------------------------------------------

    \300\ Policy Statement on Market Monitoring Units, 111 FERC ] 
61,267, at P 5 (2005) (citation omitted).
---------------------------------------------------------------------------

    Further, I disagree with the NOPR's proposal to promote 
responsiveness of RTOs/ISOs by allowing them to adopt hybrid boards 
with stakeholder members. Providing for stakeholder representatives 
on an RTO/ISO board is inconsistent with an independent governing 
structure. The Commission has already spoken clearly on the 
importance of RTOs/ISOs being independent of market participants. 
Having an independent board is the cornerstone of RTO/ISO policy. 
Order Nos. 888 \301\ and 2000 \302\ require that an RTO/ISO be 
independent from market participants in order to provide regional 
transmission and energy market services on a non-discriminatory 
basis. If an RTO or ISO adopted a hybrid board, I do not believe 
they could be categorized as independent. Additionally, I believe 
that an RTO or ISO with a hybrid board jeopardizes the ability of 
the Commission to apply the independent entity variation standard 
found in Order No. 2003 when considering modifications to such an 
RTO or ISO's pro forma Large Generator Interconnection Procedures 
(LGIP) and Large Generator Interconnection Agreement (LGIA).\303\
---------------------------------------------------------------------------

    \301\ Promoting Wholesale Competition Through Open Access Non-
Discriminatory Transmission Services by Public Utilities; Recovery 
of Stranded Costs by Public Utilities and Transmitting Utilities, 
Order No. 888, FERC Stats. & Regs. ] 31,036 (1996), order on reh'g, 
Order No. 888-A, FERC Stats. & Regs. ] 31,048, order on reh'g, Order 
No. 888-B, 81 FERC ] 61,248 (1997), order on reh'g, Order No. 888-C, 
82 FERC ] 61,046 (1998), aff'd in relevant part sub nom. 
Transmission Access Policy Study Group v. FERC, 225 F.3d 667 (DC 
Cir. 2000), aff'd sub nom. New York v. FERC, 535 U.S. 1 (2002).
    \302\ Regional Transmission Organizations, Order No. 2000, FERC 
Stats. & Regs. ] 31,089 (1999), order on reh'g, Order No. 2000-A, 
FERC Stats. & Regs. ] 31,092 (2000), aff'd sub nom. Pub. Util. Dist. 
No. 1 of Snohomish County, Washington v. FERC, 272 F.3d 607 (DC Cir. 
2001).
    \303\ Standardization of Generator Interconnection Agreements 
and Procedures, Order No. 2003, FERC Stats. & Regs. ] 31,146, at P 
26 (2003), order on reh'g, Order No. 2003-A, FERC Stats. & Regs. ] 
31,160, order on reh'g, Order No. 2003-B, FERC Stats. & Regs. ] 
31,171 (2004), order on reh'g, Order No. 2003-C, FERC Stats. & Regs. 
] 31,190 (2005), aff'd sub nom. Nat'l Ass'n of Regulatory Util. 
Comm'rs v. FERC, 475 F.3d 1277 (DC Cir. 2007).
---------------------------------------------------------------------------

    I also fear that a board with independent and non-independent 
members will suffer from a divisive atmosphere with suspicion as to 
whether non-independent board members were acting in the best 
interests of the RTO/ISO and its customers or in the best interest 
of the particular market participant represented by that non-
independent board member. In contrast, I believe that the NOPR's 
proposal to encourage RTOs and ISOs to establish a stakeholder 
advisory committee would meet the NOPR's goal of improving RTO/ISO 
responsiveness without jeopardizing the fundamental independence of 
RTOs/ISOs. I also believe consideration should be given to the RTO/
ISO mission statement as a tool to respond to any continuing 
stakeholder need for more RTO/ISO accountability.
    Finally, I support the long-term power contracting in organized 
markets section of the NOPR. I agree with the NOPR's suggestion that 
RTOs/ISOs conduct forums on long-term contracts to gather 
information and facilitate the exchange of ideas, similar to the one 
recently held by PJM. I believe that such forums will allow for an 
exchange of ideas on long-term contracting concerns and potentially 
foster solutions to these issues. I also agree that Commission staff 
should perform an analysis of the level of long-term contracting in 
organized market regions.
    Accordingly, for the reasons stated above, I concur in part and 
dissent in part on this NOPR.

Suedeen G. Kelly.

United States of America Federal Energy Regulatory Commission

Wholesale Competition in Regions With Organized Electric Markets--
Docket Nos. RM07-19-000, AD07-7-000

Issued February 22, 2008.
WELLINGHOFF, Commissioner, concurring:

    As the Commission states in this Notice of Proposed Rulemaking 
(NOPR), from the commencement of our first technical conference in 
this proceeding one year ago, our goal has been to identify specific 
reforms that can be made to optimize the efficiency of organized 
wholesale electric markets for the benefit of customers and, 
ultimately, the consumers who pay for electricity services. This 
NOPR marks an important step toward that goal, and I am pleased to 
support its issuance.
    I would like to draw attention to a few areas of this NOPR, on 
which I particularly encourage interested persons to submit 
comments.
    In this NOPR, the Commission highlights the importance of demand 
response to the organized markets. The Commission states that demand 
response helps to reduce prices in competitive wholesale markets in 
several ways, such as by reducing generator market power and 
flattening an area's load profile. The Commission also recognizes 
that the need for, and the focus on, demand response will continue 
to increase.
    The Commission makes several notable proposals in this NOPR 
related to demand response. One issue on which I encourage comments 
is the Commission's proposal to require each RTO and ISO to accept 
bids from demand response resources, on a basis comparable to any 
other resources, for ancillary services that are acquired in a 
competitive bidding process. The Commission states that this policy 
would increase the competitiveness of ancillary services markets, 
help reduce the price of ancillary services, and improve the 
reliability of the grid. I am interested in hearing from interested 
parties whether our proposals in this area are adequate to achieve 
those goals.
    The Commission also states that we intend to direct our staff to 
convene a technical conference shortly after we receive comments on 
this NOPR to consider critical issues related to demand response, 
such as appropriate compensation for demand response and potential 
solutions to remaining barriers to comparable treatment of demand 
response. We also propose to require each RTO and ISO to submit a 
study on these critical issues within six months of the issuance of 
a Final Rule in this proceeding. Those studies would include 
proposed solutions along with a timeline for implementation. I 
encourage interested parties to provide comments on this approach 
and to identify particular issues or areas that should be addressed 
in these RTO and ISO studies.
    In addition, I strongly encourage interested parties to comment 
on the Commission's proposal in this NOPR concerning market rules 
that govern price formation during periods of operating reserve 
shortage. It is important to note that these are infrequent periods 
when more resources, both generation and demand resources, are 
needed to maintain reliable electric service to consumers. I 
appreciate the extensive comments that we received on this issue in 
response to the ANOPR. I believe that this proposal in the NOPR is 
an improvement in several respects over the discussion in the ANOPR. 
Most notably, the Commission proposes to adopt requirements to 
ensure that proposals for pricing during periods of operating 
reserve shortage are designed to protect consumers against the 
exercise of market power and are supported by an adequate factual 
record. More specifically, we propose that a primary criterion for

[[Page 12619]]

approving such pricing proposals would be an adequate record 
demonstrating that provisions exist for mitigating market power and 
deterring gaming behavior, including, but not limited to, use of 
demand resources to discipline bidding behavior to competitive 
levels during periods of operating reserve shortage. I am 
particularly interested in receiving comments as to whether this and 
the other criteria proposed in this NOPR are appropriate, how the 
Commission should apply these criteria if we adopt them in a Final 
Rule, and whether there are additional criteria that we should 
consider in evaluating an RTO's or ISO's proposal for pricing during 
a period of operating reserve shortage.
    Finally, I would like to note that the Commission in this NOPR 
is directing each RTO or ISO to provide a forum for affected 
consumers to voice specific concerns (and to propose regional 
solutions) about market designs in its particular region, including 
concerns as to the value to the market of significant changes to the 
market rules. We are also directing our staff to convene a technical 
conference on two proposals that were submitted in comments in this 
proceeding. Through these and other steps taken in this NOPR, it is 
my intention for the Commission to demonstrate how seriously we take 
our statement that the proposals in this NOPR do not represent our 
final effort to enhance the efficient functioning of competitive 
organized markets for the benefit of consumers.

Jon Wellinghoff,
Commissioner.
[FR Doc. E8-3984 Filed 3-6-08; 8:45 am]
BILLING CODE 6717-01-P