[Federal Register Volume 74, Number 144 (Wednesday, July 29, 2009)]
[Rules and Regulations]
[Pages 37776-37801]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: E9-17364]



[[Page 37775]]

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Part II





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; Final 
Rule

Federal Register / Vol. 74, No. 144 / Wednesday, July 29, 2009 / 
Rules and Regulations

[[Page 37776]]


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DEPARTMENT OF ENERGY

Federal Energy Regulatory Commission

18 CFR Part 35

[Docket No. RM07-19-001; Order No. 719-A]


Wholesale Competition in Regions With Organized Electric Markets

July 16, 2009.
AGENCY: Federal Energy Regulatory Commission, DOE.

ACTION: Final rule; order on rehearing.

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SUMMARY: In this order on rehearing, the Federal Energy Regulatory 
Commission (Commission) affirms its basic determinations in Order No. 
719, Wholesale Competition in Regions with Organized Electric Markets, 
which amended Commission regulations to improve the operation of 
organized wholesale electric markets in four areas: Demand response, 
including pricing during periods of operating reserve shortage; long-
term power contracting; market-monitoring policies; and the 
responsiveness of RTOs and ISOs to their customers and other 
stakeholders. This order denies in part and grants in part rehearing 
and clarification regarding certain provisions of Order No. 719.

DATES: Effective Date: This is effective on August 28, 2009.

FOR FURTHER INFORMATION CONTACT:
Russell Profozich (Technical Information), Office of Energy Market 
Regulation, Federal Energy Regulatory Commission, 888 First Street, 
NE., Washington, DC 20426. <a href="/cdn-cgi/l/email-protection#bbe9cec8c8ded7d795ebc9d4ddd4c1d2d8d3fbdddec9d895dcd4cd"><span class="__cf_email__" data-cfemail="5200272121373e3e7c02203d343d283b313a12343720317c353d24">[email protected]</span></a>. (202) 502-6478.
Tina Ham (Legal Information), Office of the General Counsel, Federal 
Energy Regulatory Commission, 888 First Street, NE., Washington, DC 
20426. <a href="/cdn-cgi/l/email-protection#b5e1dcdbd49bfdd4d8f5d3d0c7d69bd2dac3"><span class="__cf_email__" data-cfemail="23774a4d420d6b424e63454651400d444c55">[email protected]</span></a>. (202) 502-6224.

SUPPLEMENTARY INFORMATION: 

                            Table of Contents
 
                                                              Paragraph
                                                               numbers
 
I. Introduction............................................            1
    A. Summary of Order No. 719............................            2
    B. Requests for Rehearing..............................           10
II. Discussion.............................................           13
    A. Demand Response and Pricing During Periods of                  13
     Operating Reserve Shortages in Organized Markets......
        1. Ancillary Services Provided by Demand Response             13
         Providers.........................................
            a. Request for Rehearing.......................           15
            b. Commission Determination....................           16
        2. Aggregation of Retail Customers.................           17
            a. Requests for Rehearing......................           18
            b. Commission Determination....................           41
        3. Market Rules Governing Price Formation During              72
         Periods of Operating Reserve Shortage.............
            a. Requests for Rehearing......................           74
            b. Commission Determination....................           93
    B. Long-Term Power Contracting in Organized Markets....          107
        1. Hedging Instruments.............................          108
            a. Request for Rehearing.......................          109
            b. Commission Determination....................          110
        2. Structural Issues...............................          111
            a. Request for Rehearing.......................          112
            b. Commission Determination....................          117
    C. Market-Monitoring Policies..........................          123
        1. Market Mitigation...............................          127
            a. Requests for Rehearing......................          129
            b. Commission Determination....................          133
        2. Relationship Between Internal and External MMU..          138
            a. Requests for Rehearing......................          139
            b. Commission Determination....................          141
        3. State Access to MMU Information.................          144
            a. Requests for Rehearing......................          145
            b. Commission Determination....................          146
        4. Offer and Bid Data..............................          151
            a. Requests for Rehearing or Clarification.....          152
            b. Commission Determination....................          156
        5. Ethics Provisions...............................          160
            a. Request for Rehearing or Clarification......          161
            b. Commission Determination....................          164
        6. Referral of Market Design Flaws.................          167
    D. Responsiveness of RTOs and ISOs to Customers and              171
     Other Stakeholders....................................
        1. Criteria for Responsiveness.....................          172
            a. Requests for Rehearing......................          173
            b. Commission Determination....................          178
        2. Hybrid Boards...................................          184
            a. Requests for Rehearing......................          186
            b. Commission Determination....................          189
        3. Mission Statements..............................          192
            a. Requests for Rehearing......................          193
            b. Commission Determination....................          194
III. Document Availability.................................          195
IV. Effective Date.........................................          198
Regulatory Text
 


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128 FERC ] 61,059

Before Commissioners: Jon Wellinghoff, Chairman; Suedeen G. Kelly, 
Marc Spitzer, and Philip D. Moeller.

I. Introduction

    1. On October 17, 2008, the Commission issued a Final Rule \1\ 
establishing reforms to improve the operation of organized wholesale 
electric power markets \2\ and amended its regulations under the 
Federal Power Act (FPA) in the areas of: (1) Demand response, including 
pricing during periods of operating reserve shortage; (2) long-term 
power contracting; (3) market-monitoring policies; and (4) the 
responsiveness of RTOs and ISOs to their customers and other 
stakeholders.\3\ The Commission stated that these reforms are intended 
to improve wholesale competition to protect consumers in several ways: 
By providing more supply options, encouraging new entry and innovation, 
spurring deployment of new technologies, removing barriers to 
comparable treatment of demand response, improving operating 
performance, exerting downward pressure on costs, and shifting risk 
away from consumers.
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    \1\ Wholesale Competition in Regions with Organized Electric 
Markets, Order No. 719, 73 FR 64,100 (Oct. 28, 2008), FERC Stats. & 
Regs. ] 31,281 (2008) (Order No. 719 or Final Rule).
    \2\ 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. 
The following Commission-approved 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 New 
England); California Independent System Operator Corp. (CAISO); and 
Southwest Power Pool, Inc. (SPP).
    \3\ In this rulemaking, the Commission also issued an advanced 
notice of proposed rulemaking, Wholesale Competition in Regions with 
Organized Electric Markets, Advance Notice of Proposed Rulemaking, 
FERC Stats. & Regs. ] 32,617 (2007) (ANOPR) and a notice of proposed 
rulemaking, Wholesale Competition in Regions with Organized Electric 
Markets, Notice of Proposed Rulemaking, FERC Stats. & Regs. ] 32,628 
(2008) (NOPR).
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A. Summary of Order No. 719

    2. In the area of demand response, the Commission required each RTO 
and ISO to: (1) Accept bids from demand response resources in RTOs' and 
ISOs' markets for certain ancillary services on a basis comparable to 
other resources; (2) eliminate, during a system emergency, a charge to 
a buyer that takes less electric energy in the real-time market than it 
purchased in the day-ahead market; (3) in certain circumstances, permit 
an aggregator of retail customers (ARC) to bid demand response on 
behalf of retail customers directly into the organized energy market; 
and (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.\4\
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    \4\ Order No. 719, FERC Stats. & Regs. ] 31,281 at P 4, 15.
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    3. Additionally, the Commission recognized that further reforms may 
be necessary to eliminate barriers to demand response in the future. To 
that end, the Commission required each RTO or ISO to assess and report 
on any remaining barriers to comparable treatment of demand response 
resources that are within the Commission's jurisdiction. The Commission 
further required each RTO's or ISO's Independent Market Monitor to 
submit a report describing its views on its RTO's or ISO's assessment 
to the Commission.\5\
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    \5\ Id. P 274.
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    4. With regard to long-term power contracting, the Commission 
required each RTO and ISO to dedicate a portion of its Web sites for 
market participants to post offers to buy or sell power on a long-term 
basis.
    5. To improve market monitoring, the Commission required each RTO 
and ISO to provide its Market Monitoring Unit (MMU) with access to 
market data, resources and personnel sufficient to carry out their 
duties, and required the MMU to report directly to the RTO or ISO board 
of directors.\6\ In addition, the Commission required 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 or the RTO's or ISO's behavior may require investigation.
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    \6\ The use of the phrase ``board of directors'' herein also 
includes the board of managers, board of governors, and similar 
entities. An internal MMU in a hybrid structure may report to 
management so long as it does not perform any of the core MMU 
functions.
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    6. The Commission also took the following actions with regard to 
MMUs: (1) Expanded the list of recipients of MMU recommendations 
regarding rule and tariff changes, and broadened the scope of behavior 
to be reported to the Commission; (2) modified MMU participation in 
tariff administration and market mitigation, required each RTO and ISO 
to include ethics standards for MMU employees in its tariff, and 
required each RTO and ISO to consolidate all its MMU provisions in one 
section of its tariff; and (3) expanded the dissemination of MMU market 
information to a broader constituency, with reports made on a more 
frequent basis than in the past, and reduced the time period before 
energy market bid and offer data are released to the public.
    7. Finally, the Commission established an obligation for each RTO 
and ISO to establish a means for customers and other stakeholders to 
have a form of direct access to the RTO or ISO board of directors, and 
thereby, increase its responsiveness to customers and other 
stakeholders. The Commission stated that it will assess each RTO's or 
ISO's compliance filing using four responsiveness criteria: (1) 
Inclusiveness; (2) fairness in balancing diverse interests; (3) 
representation of minority positions; and (4) ongoing responsiveness.
    8. The Commission stated in the Final Rule that its actions in 
these four areas are consistent with its duty to improve the operation 
of wholesale power markets.\7\ The Commission also reiterated its 
statement from the underlying Notice of Proposed Rulemaking that the 
reforms addressed in this proceeding do not represent the Commission's 
final effort to improve the functioning of competitive markets for the 
benefit of consumers. Rather, the Commission will continue to evaluate 
other specific reforms that may strengthen organized markets.\8\
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    \7\ Order No. 719, FERC Stats. & Regs. ] 31,281 at P 2.
    \8\ Id. P 14.
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    9. In each of the four areas, the Final Rule required each RTO or 
ISO to consult with its stakeholders and make a compliance filing that 
explains how its existing practices comply with the Final Rule's 
reforms, or its plans to attain compliance.\9\
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    \9\ Id. P 8, 578-83.
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B. Requests for Rehearing

    10. The following entities have filed timely requests for rehearing 
or for clarification of Order No. 719: American Electric Power 
Corporation (AEP); American Public Power Association (APPA) and 
California Municipal Utilities Association (CMUA) (jointly, APPA-CMUA); 
APPA, CMUA and National Rural Electric Cooperative Association (NRECA) 
(collectively, Joint Petitioners); Illinois Commerce

[[Page 37778]]

Commission; Coalition of Midwest Transmission Customers, NEPOOL 
Industrial Customer Coalition, and PJM Industrial Customers Coalition 
(collectively, Industrial Coalitions); Minnesota Public Utilities 
Commission (Minnesota PUC); National Association of Regulatory Utility 
Commissioners (NARUC); Public Utilities Commission of Ohio (Ohio PUC); 
Old Dominion Electric Cooperative (Old Dominion); Potomac Economics, 
Ltd. (Potomac Economics); Pennsylvania Public Utilities Commission 
(Pennsylvania PUC); Sacramento Municipal Utility District (SMUD); 
Transmission Access Policy Study Group (TAPS); and Public Service 
Commission of Wisconsin (Wisconsin PSC). New York Independent System 
Operator, Inc. (NYISO) submitted an untimely request for clarification. 
Additionally, PJM Interconnection, L.L.C. filed a motion for leave to 
respond and response to the requests for rehearing. Joint Petitioners 
filed an answer to PJM's motion.\10\
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    \10\ Additionally, Monitoring Analytics, LLC filed an out-of-
time motion to intervene in this proceeding, but did not seek 
rehearing.
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    11. We dismiss NYISO's untimely request for clarification of Order 
No. 719 because it is, in essence, an untimely request for rehearing. 
The courts have repeatedly recognized that the time period within which 
a party may file a petition for rehearing of a Commission order is 
statutorily established at 30 days by section 313(a) of the FPA\11\ and 
that the Commission has no discretion to extend that deadline.\12\ 
Accordingly, the Commission has long held that it lacks the authority 
to consider requests for rehearing filed more than 30 days after 
issuance of a Commission order.\13\
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    \11\ 16 U.S.C 825l.
    \12\ See, e.g., City of Campbell v. FERC, 770 F.2d 1180, 1183 
(D.C. Cir. 1985) (``The 30-day time requirement of [the FPA] is as 
much a part of the jurisdictional threshold as the mandate to file 
for a rehearing.''); Boston Gas Co. v. FERC, 575 F.2d 975, 977-98, 
979 (1st Cir. 1978) (describing identical rehearing provision of the 
Natural Gas Act as ``a tightly structured and formal provision. 
Neither the Commission nor the courts are given any form of 
jurisdictional discretion.'').
    \13\ See, e.g., Arkansas Power & Light Co., 19 FERC ] 61,115 at 
61,217-18, reh'g denied, 20 FERC ] 61,013, at 61,034 (1982). See 
also Public Serv. Co. of New Hampshire, 56 FERC ] 61,105, at 61,403 
(1991); CMS Midland, Inc., 56 FERC ] 61,177, at 61,623 (1991).
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    12. Rule 713(d)(1) of the Commission's Rules of Practice and 
Procedure, 18 CFR 385.713(d)(1) (2008), prohibits answers to requests 
for rehearing. Accordingly, we reject PJM's motion to respond to 
requests for rehearing and Joint Petitioners' answer to PJM's motion.

II. Discussion

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

1. Ancillary Services Provided by Demand Response Providers
    13. The Final Rule required 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. All accepted 
bids would receive the market-clearing price.\14\ The Commission 
determined that these requirements would remove barriers to the 
comparable treatment of demand-side and supply-side resources.
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    \14\ Order No. 719, FERC Stats. & Regs. ] 31,281 at P 47.
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    14. In the Final Rule, in response to commenters who asked the 
Commission to allow energy efficiency resources to bid into the 
organized markets, the Commission recognized the value of energy 
efficiency resources. The Commission stated that it has not excluded 
from eligibility as a provider of ancillary services any type of 
resource that is technically capable of providing the ancillary 
service, including energy efficiency resources. However, because this 
proceeding did not propose to include energy efficiency resources as 
providers of competitively procured ancillary services, the Commission 
stated that it did not have an adequate record to address this 
issue.\15\
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    \15\ Id. P 56.
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a. Request for Rehearing
    15. Pennsylvania PUC asserts that the Commission should uphold its 
``comparable terms and conditions'' principle regarding acceptance of 
demand response resources for ancillary services by requiring each RTO 
and ISO to file tariff provisions defining energy efficiency resources 
as resources qualified to bid into energy markets and ancillary 
services markets upon such terms and conditions as the RTO or ISO may 
propose. In addition, it asks the Commission to require each RTO and 
ISO to supply arguments and adequate record evidence in support of such 
a filing so that the Commission can determine whether energy efficiency 
resources are being accepted on a comparable basis with any other 
resources qualified to bid into energy markets and ancillary services 
markets.\16\
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    \16\ Pennsylvania PUC at 4.
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b. Commission Determination
    16. The Final Rule does not exclude from eligibility any type of 
resource that is technically capable of providing an ancillary service, 
and therefore we disagree with Pennsylvania PUC that the Final Rule 
leaves in place a barrier to the use of energy efficiency resources 
that we must remedy on rehearing. An RTO or ISO is free to work with 
its stakeholders and incorporate energy efficiency resources into its 
markets on a basis that is appropriate for its region.\17\
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    \17\ Order No. 719, FERC Stats. & Regs. ] 31,281 at P 276.
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2. Aggregation of Retail Customers
    17. Order No. 719 required 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. 
The Commission determined that allowing an ARC to act as an 
intermediary for many small retail loads that cannot individually 
participate in the organized market would reduce a barrier to demand 
response.\18\ The Commission directed RTOs and ISOs to submit 
compliance filings to propose amendments to their tariffs or otherwise 
demonstrate how their existing tariffs and market rules comply with the 
Final Rule.\19\
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    \18\ Id. P 154.
    \19\ Id. P 163.
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a. Requests for Rehearing
i. Commission Jurisdiction
    18. Several petitioners assert that the Final Rule's ARC 
requirements exceed the Commission's statutory authority under the 
FPA.\20\ TAPS and Joint Petitioners state that under section 201(a) of 
the FPA, the Commission's jurisdiction is limited to the transmission 
of electric energy in interstate commerce and the sale of such energy 
at wholesale in interstate

[[Page 37779]]

commerce.\21\ They argue that a retail customer's reduction of energy 
consumption is neither a wholesale sale of electric energy nor 
transmission in interstate commerce, and that retail sales are sales of 
electric energy to end users that are not sales for resale.\22\ Joint 
Petitioners add that a promise not to consume electric energy at a 
particular time is a product not covered by the plain language of the 
FPA.\23\\\ TAPS, therefore, concludes that the Commission lacks 
jurisdiction to modify retail electricity sales by effectively 
establishing a new rule that authorizes retail customers purchasing 
electricity (or non-consumption) to resell that electricity into 
wholesale markets, either directly or through a third party.\24\
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    \20\ See, e.g., TAPS at 9-13; Joint Petitioners at 18-23; NARUC 
at 3. NARUC states that it incorporates by reference the arguments 
presented on this issue by Joint Petitioners' request for rehearing. 
NARUC at 5.
    \21\ 16 U.S.C. 824(a).
    \22\ TAPS at 11-12; Joint Petitioners at 18-19 (citing United 
States v. Public Utils. Comm'n of California, 345 U.S. 295, 303 
(1953); Federal Power Comm'n v. Southern California Edison Co., 376 
U.S. 202, 216 (1964)).
    \23\ Joint Petitioners at 19.
    \24\ TAPS at 12-13 (citing N.Y. v. FERC, 535 U.S. 1, 20 (2002); 
FPC v. Conway Corp., 426 U.S. 271, 276-77 (1976)).
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    19. Joint Petitioners argue that the Final Rule's ARC requirement 
violates the separation of Federal and State jurisdiction because it 
effectively requires public power systems and cooperatives to take 
affirmative action to consider retail aggregation issues.\25\ Joint 
Petitioners state that the majority of these systems do not have laws 
or regulations addressing end-use customer aggregation. They argue that 
the Commission has no jurisdiction to require such affirmative action 
because it is beyond the scope of its legal authority set out in the 
FPA.
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    \25\ Joint Petitioners at 13, 18 (citing Northern States Power 
Co., 176 F.3d 1090, 1096 (8th Cir. 1999), reh'g en banc denied 1999 
U.S. App. LEXIS 23493 (8th Cir. Sept. 1, 1999), cert. denied sub 
nom.; Enron Power Mktg., Inc. v. Northern States Power Co., 528 U.S. 
1182 (2000); Atlantic City Electric Co. v. FERC, 295 F.3d 1, 8 (D.C. 
Cir. 2002)).
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    20. Additionally, TAPS argues that States' and relevant electric 
retail regulatory authorities' laws and regulations do not grant retail 
customers either the title or a contract right to resell retail 
electricity (or any such non-consumption). In that respect, TAPS argues 
that the Final Rule intrudes into retail electric service rates by 
requiring RTOs and ISOs to accept demand response bids that may be 
prohibited by State law, without first obtaining confirmation that such 
transactions are permitted by the relevant electric retail regulatory 
authority. Joint Petitioners also note that Congress acknowledged that 
State and local regulation extends to such consumption decisions when 
it directed State regulators and non-regulated utilities to consider 
implementing demand response programs at the State and local level in 
2007 amendments to the Public Utility Regulatory Policies Act 
(PURPA).\26\ Further, they argue that the Commission failed to explain 
how it has jurisdiction over the demand response programs of public 
power systems and cooperatives that are not public utilities, and are 
therefore exempt, under FPA section 201(f), from the Commission's FPA 
section 206 authority \27\ Joint Petitioners contend that the 
Commission cannot ``indirectly'' claim jurisdiction over non-
jurisdictional entities.\28\
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    \26\ Section 532 of the Energy Independence and Security Act of 
2007 amended PURPA section 111(d) by adding a new standard that 
requires consideration of rate design modifications to promote 
energy efficiency investments. 16 U.S.C. 2621(d). To assist in this 
effort, Joint Petitioners note that APPA and NRECA commissioned a 
reference manual regarding the new requirements. Reference Manual 
and Procedures for Implementation of the PURPA Standards in the 
Energy Independence and Security Act of 2007, Dr. Ken Rose and 
Michael Murphy, available at http://www.naruc.org/Publications/EISAStandardsManualFINAL.pdf. Joint Petitioners argue that efforts 
to have distribution cooperatives or public power distribution 
systems invest in a demand response program after considering these 
new federal PURPA standards could be undermined by the activities of 
third-party ARCs seeking to take the demand response of the public 
power or cooperative system's retail customers directly to the 
wholesale market. Joint Petitioners at 21.
    \27\ 16 U.S.C. 824(f). Joint Petitioners at 21 (citing 
Bonneville Power Administration, et al. v. FERC, 422 F.3d 908, 915 
(9th Cir. 2005).
    \28\ Joint Petitioners state that the ``Commission cannot 
bootstrap jurisdiction over * * * non-jurisdictional entities simply 
by pointing to jurisdiction over their retail customers'' and that 
the Commission ``cannot do indirectly what it cannot do directly.'' 
Joint Petitioners at 21 (citing Richmond Power & Light v. FERC, 574 
F.2d 610, 620 (D.C. Cir. 1978); Altamont Gas Transmission Co., et 
al. v. FERC, 92 F.3d 1239, 1248 (D.C. Cir. 1996); and Williams Gas 
Processing-Gulf Coast Co., L.P. v. FERC, 331 F.3d 1011, 1022 (D.C. 
Cir. 2003)).
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    21. Ohio PUC argues that third-party aggregation bids should be 
subject to State regulatory authority or approval.\29\ While it agrees 
that ARCs should be permitted to aggregate smaller loads, it asserts 
that retail customers and their representatives should not be 
classified as wholesale customers subject to the Commission's 
jurisdiction simply because they provide demand response to the 
wholesale market. Therefore, Ohio PUC contends that the Final Rule 
should have acknowledged that all contracts by third-party ARCs are 
subject to State retail jurisdiction and should be subject to State 
commission approval prior to providing demand response resources to an 
RTO or ISO.\30\
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    \29\ Ohio PUC at 6-7 (stating that ``it is the prerogative of 
each individual state commission to decide to what extent it will 
expose its retail customers to the wholesale market, and what, if 
any, advanced technology (i.e., smart meters) its retail customers 
desire and wish to purchase'').
    \30\ Id. at 6. The Wisconsin PSC states that it adopts Ohio 
PUC's arguments on this issue. Wisconsin PSC at 2. NARUC states that 
it incorporates by reference the arguments presented on this issue 
by Ohio PUC's request for rehearing. NARUC at 5.
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    22. Joint Petitioners ask the Commission to rule on rehearing that 
in the case of public power systems and cooperative utilities, RTOs and 
ISOs should not accept ARCs' demand response bids unless a system's 
relevant electric retail regulatory authority affirmatively informs the 
RTO or ISO that it permits aggregation by third-party ARCs.\31\ They 
believe that this approach would allow the Commission to encourage 
demand response while still respecting the State and local retail 
regulatory authorities. Similarly, TAPS urges the Commission to modify 
the opt-out structure of the ARC requirements by changing it to an opt-
in structure to remedy the jurisdictional defect and to avoid undue 
burden to small relevant electric retail regulatory authorities.\32\ 
TAPS argues that such modifications would invite relevant electric 
retail regulatory authorities to contact the RTO or ISO to provide the 
necessary notification. Joint Petitioners and TAPS state that absent a 
notification that permission has been granted, the RTO or ISO should 
presume that sales of demand response in RTO or ISO markets are not 
permitted.
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    \31\ Joint Petitioners at 15-16.
    \32\ Specifically, TAPS suggests that the Commission modify the 
regulatory text to replace: (1) The ``unless'' clause of 18 CFR 
35.28(g)(1)(B)(3)(iii) with ``if the relevant electric retail 
regulatory authority expressly permits a retail customer to 
participate''; and (2) the ``unless'' clause of 18 CFR 
35.28(g)(1)(i)(A) with ``if permitted by the laws or regulations of 
the relevant electric retail regulatory authority.'' TAPS at 28.
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    23. Additionally, TAPS argues that ARCs and other entities bidding 
demand response into RTO or ISO markets should be required to certify 
that their sales are permitted. It asserts that it would be difficult 
for RTOs or ISOs or relevant electric retail regulatory authorities to 
identify, independently, whether improper sales or aggregation occur. 
It states that entities bidding demand response into the RTO or ISO 
wholesale markets are in the best position to identify the specific 
retail loads and customers involved and to verify that such bids are 
permitted by the relevant electric retail regulatory authority. It 
notes that network customers must provide certification to support 
designation of network resources.\33\ Similarly, individual retail

[[Page 37780]]

customers and ARCs should be required to certify that their bids and 
sales of demand response into wholesale markets are permitted under 
applicable law, and submission by such entities of ineligible demand 
response bids should be a tariff violation.
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    \33\ Id. at 31. TAPS notes that under Order No. 890, network 
customers must attest, for each network resource identified for 
designation, that: (1) The transmission customer owns or has 
committed to purchase the designated network resource; and (2) the 
designated network resource meets the requirements for designated 
network resources. Preventing Undue Discrimination and Preference in 
Transmission Service, Order No. 890, FERC Stats. & Regs. ] 31,241, 
order on reh'g, Order No. 890-A, FERC Stats. & Regs. ] 31,261 
(2007), order on reh'g, Order No. 890-B, 123 FERC ] 61,299 (2008).
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    24. Further, AEP notes that the Final Rule permits retail customers 
to participate in an RTO's or ISO's demand program unless the laws or 
regulations of the relevant electric retail regulatory authority do not 
permit a retail customer to participate. It seeks clarification as to 
``whether this exception applies to [s]tate commission-approved tariff 
provisions that prohibit sales for resale.'' \34\
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    \34\ AEP at 1.
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    25. AEP asserts that a State commission in a non-retail choice 
State should have the opportunity to fully consider and determine 
whether an RTO or ISO wholesale demand response program is appropriate 
for that State. AEP is concerned that RTOs and ISOs may interpret the 
Final Rule's language on the ARC requirement to mean that RTOs and ISOs 
may proceed with demand response programs in States where retail 
customers are provided with State regulated average embedded cost 
rates, unless States specifically opt out of an RTO's or ISO's 
wholesale demand response program. AEP argues that such an 
interpretation would allow: (1) Non-choice retail customers with 
average embedded cost rates an opportunity to arbitrage their load 
through sales into wholesale markets to the detriment of remaining 
retail customers in that State; and (2) an RTO or ISO to set new policy 
without any consideration of unintended consequences to retail 
customers.\35\
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    \35\ Id. at 2.
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    26. Additionally, AEP notes that a retail customer's action could 
be considered a ``resale'' when the customer purchases electric service 
under a retail tariff and then receives compensation for bidding its 
load into the wholesale market through a demand response program. 
Therefore, AEP asks that the Commission either clarify the Final Rule 
to provide that participation in wholesale demand response programs by 
retail customers does not constitute a ``sale for resale,'' or require 
that retail customers seeking to participate in such programs seek such 
an exception from the applicable State commission.\36\
---------------------------------------------------------------------------

    \36\ Id. at 2-3.
---------------------------------------------------------------------------

ii. Burden on Small Entities and Regulatory Flexibility Analysis
    27. Several petitioners state that requiring the relevant electric 
retail regulatory authorities of each public system to consider some 
type of affirmative action on the ARC issue imposes a significant 
burden on them.\37\ For example, TAPS argues that the Final Rule 
requires every relevant electric retail regulatory authority, 
regardless of size, to address whether demand response sales may be bid 
into an RTO or ISO market and whether ARCs may aggregate demand 
response within the regulatory authority's jurisdiction.\38\ Joint 
Petitioners argue that, for the majority of retail regulatory 
authorities, this would be a substantial undertaking requiring a huge 
learning curve to become familiar with the process and consequently 
resulting in a lengthy legislative process.\39\ Similarly, TAPS asserts 
that it is a huge undertaking for the city council of every municipal 
electric system in an RTO or ISO to expressly address this issue 
through legislation or regulation.\40\ TAPS adds that the Final Rule 
effectively leaves enforcement responsibility with the relevant 
electric retail regulatory authority by requiring these entities to 
monitor and challenge any bids and certifications by ARCs that are not 
permitted within their jurisdiction.
---------------------------------------------------------------------------

    \37\ NARUC states that it incorporates by reference the 
arguments presented on this issue by Joint Petitioners' request for 
rehearing. NARUC at 5.
    \38\ TAPS at 25-26.
    \39\ For example, Joint Petitioners note that CMUA explained in 
its NOPR comments that the presumption of implicit authority to 
allow ARCs to aggregate bids makes no sense in California because 
direct access was suspended following the 2000-01 market crisis. 
Accordingly, California no longer has laws or regulations dealing 
with new direct access, and CMUA has not restructured its retail 
rules and ordinances with retail choice as an option. Therefore, 
Joint Petitioners state that to now require an affirmative action 
would be a substantial undertaking. Joint Petitioners at 16-17.
    \40\ TAPS notes that its members include: (1) AMP-Ohio, serving 
123 municipal electric systems in Midwest ISO and PJM; (2) Indiana 
Municipal Power Agency, serving 51 municipal electric systems in 
Midwest ISO and PJM; and (3) Wisconsin Public Power, serving 50 
municipal electric systems in Midwest ISO. TAPS at 26.
---------------------------------------------------------------------------

    28. Joint Petitioners argue that the Commission erred in certifying 
that Order No. 719 will not have a significant economic impact on a 
substantial number of small entities and certifying that the Final Rule 
complies with the Regulatory Flexibility Act of 1980 (RFA).\41\ Joint 
Petitioners assert that the reasoning underlying this certification is 
invalid and therefore seek rehearing.\42\ They emphasize that, unless 
public power systems and cooperatives take affirmative action to enact 
the necessary law or regulation, relevant electric retail authorities 
could risk having their public power systems' demand response programs 
undermined and day-to-day system operations disrupted by ARCs' demand 
response activities. They reiterate that it would be a significant 
burden for relevant electric retail regulatory authorities of over 
1,300 public power systems and 850 distribution cooperatives to take up 
this issue. Accordingly, Joint Petitioners maintain that the Final 
Rule's ARC requirement would result in a significant adverse impact on 
a substantial number of small entities and, therefore, the Commission 
is required to provide a certification under the RFA.
---------------------------------------------------------------------------

    \41\ 5 U.S.C. 601-12.
    \42\ Joint Petitioners at 23.
---------------------------------------------------------------------------

    29. TAPS also argues that by imposing responsibilities on small 
entities, the Final Rule ignores the RFA's requirements.\43\ TAPS 
disputes the Commission's cite to American Trucking Associations, Inc. 
v. EPA (American Trucking Associations) \44\ to support its position in 
the Final Rule that the RFA analysis is not required. It contends that, 
in that case, the Environmental Protection Agency (EPA) was not 
required to conduct an RFA analysis because whether the small entities 
at issue would be burdened by the EPA's action depended on the 
intermediate, discretionary action of the States. Under Order No. 719, 
however, TAPS asserts that the RTOs and ISOs have no such discretion to 
mitigate the impact of the Final Rule's requirements.\45\ TAPS further 
contends that American Trucking Associations does not relieve the 
Commission of its obligations under the RFA. Therefore, it suggests 
that the Commission modify the ARC requirement as stated above, to 
ensure that any relevant electric retail regulatory authority that 
wishes to allow third-party demand response aggregation could do so, 
without unduly

[[Page 37781]]

burdening hundreds of municipal entities.\46\
---------------------------------------------------------------------------

    \43\ TAPS at 26-27.
    \44\ American Trucking Ass'ns v. EPA, 175 F.3d 1027, 1044 (DC 
Cir. 1999), aff'd in part and rev'd in part sub nom. Whitman v. 
American Trucking Ass'ns, 531 U.S. 457 (2001).
    \45\ TAPS at 28. TAPS states that the Final Rule ``requires 
[load-serving entities] to either: (1) Invest in the legislative 
and/or regulatory procedures necessary to obtain an explicit `out' 
and enforce it; * * * or (2) undertake the implementation burdens 
necessary to accommodate ARCs and retail customers directly bidding 
retail demand response into wholesale markets.'' Id.
    \46\ Id. at 29.
---------------------------------------------------------------------------

    30. Joint Petitioners argue that the Commission erred in 
arbitrarily and capriciously refusing to consider APPA's compromise 
proposal regarding third-party aggregation.\47\ For entities below the 
RFA size requirement for small utilities, the RTO or ISO would be 
required to assume that ARC aggregation is not permitted unless the 
relevant electric retail regulatory authority of such public power 
system informed the RTO or ISO that it has elected to allow such 
aggregation. Joint Petitioners note that APPA argued in its NOPR 
comments that this size-differentiated regime would appropriately 
balance the Commission's interest in permitting demand-side 
participation in organized wholesale markets without the undue burden 
that the Final Rule places on small power systems. Joint Petitioners 
argue that Order No. 719 noted, but did not address, APPA's compromise 
proposal.\48\
---------------------------------------------------------------------------

    \47\ Joint Petitioners at 27. In its NOPR comments, APPA 
suggested an alternative approach of differentiating public power 
systems by their size. Under this alternative, the relevant electric 
retail regulatory authorities governing public power systems that 
are located in the RTO or ISO regions and larger than the RFA size 
requirement (i.e., 4 million MWh or more in total output in one 
year) would have to consider the issue of third-party ARCs and 
aggregation of their retail customers, if they had not already done 
so. They would have the affirmative requirement to inform their RTO 
or ISO whether their local election was not to permit the 
aggregation by ARCs on their public power systems, or permit it only 
under enumerated conditions in order to preclude third-party bidding 
of their consumers' loads. APPA NOPR Comments at 47-48.
    \48\ Joint Petitioners at 28-29.
---------------------------------------------------------------------------

    31. Similarly, TAPS asserts that, at a minimum, any affirmative 
regulatory action requirement should be restricted to systems that are 
larger than the RFA threshold of 4 million MWh. An alternative 
threshold, according to TAPS, would be ``those municipals with retail 
sales of more than 500 million kWh, as used in the PURPA.'' \49\ TAPS 
contends that limiting the application of the Final Rule's requirements 
in this manner would minimize the burden on small systems associated 
with either implementation of the Final Rule or compliance with its 
express prohibition requirement, consistent with the Final Rule's RFA 
certification.
---------------------------------------------------------------------------

    \49\ TAPS at 30.
---------------------------------------------------------------------------

iii. Effect on Existing Demand Response Programs and on Rates, 
Metering, and Billing Protocols
    32. TAPS argues on rehearing that the Commission failed to: (1) 
Adequately address the Final Rule's impact on existing demand response 
programs; and (2) provide sufficient evidence to justify the 
disruptions to wholesale and retail service that will be created by 
authorizing retail customers to sell their demand response in wholesale 
markets.
    33. According to TAPS, it requested in its NOPR comments that the 
Commission take steps not to undermine the existing tariff and 
contractual arrangements between load-serving entities and their 
customers for demand response programs.\50\ Yet, TAPS asserts, the 
Commission imposed new requirements without first independently 
assessing the Final Rule's impact on existing load-serving-entity-
administered demand response programs. It asks the Commission to 
clarify that the Final Rule's ARC requirement would not undermine or 
require any changes to existing aggregation programs that already 
function well.\51\
---------------------------------------------------------------------------

    \50\ Id. at 14 (citing TAPS NOPR Comments at 13-17).
    \51\ Id. at 14-15.
---------------------------------------------------------------------------

    34. According to TAPS, load-serving entity based programs provide 
significant value to all of their customers because load-serving 
entities can integrate their demand response programs into their power 
supply resource planning. This allows interruptions to be predictable 
and avoids the need to carry planning reserve for interruptible load. 
TAPS adds that customers can enjoy the protection of load-serving 
entity power supply planning and aggregation and average cost rates 
when they do not want to lower their consumption while wholesale prices 
are high.
    35. TAPS argues that the Commission's attempt to direct demand 
response into the RTO's or ISO's wholesale energy and ancillary 
services markets will cause load-serving entities to lose the planning 
benefits that a load-serving-entity-administered demand response 
program would normally provide. The load-serving entity would need to 
include in its planning for firm power supply the full loads of its 
retail customers who sell into wholesale markets or contract with ARCs, 
as well as carry full planning reserves to meet that load. Thus, TAPS 
asserts, the value to the load-serving entity and its other customers 
of avoiding peak block generation investments and additional reserves 
would be lost.\52\
---------------------------------------------------------------------------

    \52\ Id.
---------------------------------------------------------------------------

    36. Similarly, Joint Petitioners note that many public power 
systems and cooperatives have effectively acted as ARCs for their 
retail customers. This benefits customers because these not-for-profit 
entities pass on any savings from demand response measures to their 
customers in the form of lower rates. Joint Petitioners conclude that 
ARCs' activities would undercut the demand response regimes their 
public power systems and cooperatives already have in place or are 
developing by cherry-picking the demand response potential of specific 
retail customers, and reducing the savings to the customers of the 
public power system accruing from such programs.\53\ Also, they contend 
that allowing ARCs to selectively choose load-serving entity demand 
response resources would also deprive those load-serving entities of 
important resources used to keep rates down for all consumers. Load-
serving entities could no longer control individual customers' loads 
and engage in risk and portfolio management on behalf of their 
customers.\54\
---------------------------------------------------------------------------

    \53\ Joint Petitioners at 14-15.
    \54\ Id. at 15.
---------------------------------------------------------------------------

    37. TAPS further argues that, by authorizing retail customers to 
sell their non-consumption at high spot prices, the Final Rule changes 
the financial calculation for retail customers considering demand 
response. TAPS claims that this reduces load-serving entities' or 
customers' incentives to make the capital investments necessary to 
achieve significant, permanent reductions in electricity usage, in 
favor of short-term, peak-hour reductions that garner premium payments 
from ARCs and the wholesale market.\55\ TAPS argues that the load-
serving entity's loss of control over its retail customers' demand 
response could impair the load-serving entity's ability to plan for its 
load and harness that demand response to reduce the costs of serving 
all of its customers.
---------------------------------------------------------------------------

    \55\ TAPS at 17.
---------------------------------------------------------------------------

    38. Also, TAPS asserts that permitting direct demand response 
participation in wholesale markets and aggregation by third-party ARCs 
will significantly affect billing, metering, and settlement for the 
municipal system at both the wholesale and retail levels. Specifically, 
it contends that any system implemented by RTOs and ISOs to prevent 
double-counting could require major modifications to both RTO and ISO 
metering and settlement protocols and load-serving entities' metering 
and billing protocols.\56\ For example, TAPS states that municipals 
that allow individual retail customers and third-party ARCs to sell 
demand response into wholesale markets may be subject to phantom energy 
charges,\57\ based on

[[Page 37782]]

the amount of energy that those retail demand responders would 
otherwise have consumed. Consequently, this could result in deviation 
charges for load-serving entities for failure to accurately schedule 
their load. TAPS argues that, if ARC-aggregated load causes an 
unexpected drop in a load-serving entity's load, the load-serving 
entity will be subject to uplift charges if its real-time load is below 
its day-ahead load.\58\ Similarly, it adds that a decrease or an 
increase in a load-serving entity's load, triggered by unexpected, 
market-price driven demand response, could impose over- and under-
scheduling charges on a load-serving entity under the SPP's tariff.\59\
---------------------------------------------------------------------------

    \56\ Id. at 18.
    \57\ TAPS provides the following example to explain ``phantom 
energy'':
    [I]f a [transmission-dependent entity] with 100 MW of metered 
load in a given hour has a retail customer that has sold 5 MW of 
demand response energy into the RTO's energy imbalance market in 
that same hour, then to avoid double-counting the demand response 
that is already reflected in the [load-serving entity's] metered 
load, the RTO would charge the [load-serving entity] for 105 MWh of 
energy--i.e. as if the 5 MWh of demand response energy had been 
purchased by the [load-serving entity], delivered to the retail 
customer, and then re-sold. Id. at 19-20.
    \58\ Id. at 22. TAPS notes that such a deviation charge may not 
apply during an emergency, as provided elsewhere in Order No. 719.
    \59\ Id. (citing Southwest Power Pool, FERC Electric Tariff, 
Fifth Revised Volume No. 1, Attachment AE, sections 5.3 and 5.4).
---------------------------------------------------------------------------

    39. Arguing that demand response participation in wholesale 
markets, either directly or by third-party ARCs, will affect the 
scheduling and resource planning of the load-serving entities that 
serve the retail customers providing demand response, TAPS concludes 
that load-serving entities will need to develop a system for allocating 
the cost of phantom energy. TAPS believes that load-serving entities 
should assign those charges only to retail customers whose decision to 
sell their demand response into the wholesale market caused the load-
serving entity to incur those costs. Accordingly, TAPS requests that 
the Final Rule should be modified to direct RTOs and ISOs to provide 
detailed information, in real time, to affected load-serving entities 
on: (1) The identity of all individual retail customer load involved 
(even if aggregated by an ARC); and (2) the amount of such demand 
response for each billing interval.\60\
---------------------------------------------------------------------------

    \60\ Id.
---------------------------------------------------------------------------

    40. TAPS believes that, in total, the costs of accommodating 
wholesale demand response bids by selected retail customers outweigh 
the benefits. It asserts that the implementation of the Final Rule to 
accommodate wholesale demand response bids by retail customers will 
require RTOs and ISOs and load-serving entities to expend resources for 
uncertain benefits. For example, TAPS states that RTOs and ISOs will 
incur significant costs to design brand-new systems to accommodate, 
track, and verify demand response. Therefore, it asks that the 
Commission require RTOs and ISOs to evaluate the efficacy of ARC-based 
demand response programs, especially given the adverse impacts on load-
serving-entity-administered demand response programs, and to implement 
them only if that evaluation demonstrates that the benefits outweigh 
the costs.\61\
---------------------------------------------------------------------------

    \61\ Id. at 22-23.
---------------------------------------------------------------------------

b. Commission Determination
    41. In the Final Rule, the Commission adopted the NOPR proposal 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. The Commission reasoned that 
such an action would reduce a barrier to demand response participation 
in the organized markets subject to Commission jurisdiction.\62\ As 
discussed below, we affirm this broad finding, but deny in part and 
grant in part requests for rehearing on this issue.
---------------------------------------------------------------------------

    \62\ Order No. 719, FERC Stats. & Regs. ] 31,281 at P 594; NOPR, 
FERC Stats. & Regs. ] 32,628 at P 83.
---------------------------------------------------------------------------

i. Commission Jurisdiction
    42. Although the rehearing requests present the issue of Commission 
jurisdiction from various points of view and with emphasis on various 
groups of market participants or activities (and we will answer these 
arguments in turn), they all include the same basic issue: whether the 
Commission has jurisdiction to make rules requiring the RTOs and ISOs 
to accept demand response bids.
    43. Section 201(b) of the FPA confers jurisdiction on the 
Commission over the transmission of electric energy in interstate 
commerce, and sales of electric energy at wholesale in interstate 
commerce.\63\ Sections 205 and 206 of the FPA confer upon the 
Commission the responsibility to ensure that rates and charges for 
transmission and wholesale power sales by public utilities, including 
any rule, regulation, practice or contract affecting them, are just and 
reasonable and not unduly discriminatory or preferential.\64\ While FPA 
sections 201(f) and 201(b)(2) make clear that the Commission's 
authorities under Part II of the FPA do not apply to governmental 
entities and certain electric cooperatives, except as specifically 
provided, the Commission's regulation of the organized markets operated 
by RTOs and ISOs (which are public utilities) nevertheless affects 
governmental and cooperative entities that participate in those 
markets.
---------------------------------------------------------------------------

    \63\ 16 U.S.C. 824(b).
    \64\ Section 205(a) of the FPA charges the Commission with 
ensuring that rates and charges for jurisdictional sales by public 
utilities and ``all rules and regulations affecting or pertaining to 
such rates or charges'' are just and reasonable. Id. 824d(a). 
Section 206(a) gives the Commission authority over rate and charges 
by public utilities for jurisdictional sales as well as ``any rule, 
regulation, practice or contract affecting such rates and charges'' 
to make sure that they are just and reasonable and not unduly 
discriminatory or preferential. Id. 824e(a).
---------------------------------------------------------------------------

    44. In exercising its FPA section 206 authority to regulate public 
utility wholesale sales, the Commission concluded that well-functioning 
competitive wholesale electric markets should reflect current supply 
and demand conditions, and that wholesale markets work best when demand 
can respond to the wholesale price. Thus, the Commission began this 
proceeding with the goal of eliminating those barriers to demand 
response participation in the organized markets, and to ensure 
comparable treatment of all resources in these markets.\65\ The Final 
Rule's ARC requirement is one element of the Commission's effort to 
achieve this goal.
---------------------------------------------------------------------------

    \65\ In Order No. 890, the Commission found that sales of 
ancillary services by ``load services. * * * should be permitted 
where appropriate on a comparable basis to service provided by 
generation resources.'' Order No. 890, FERC Stats. & Regs. ] 31,241 
(2007).
---------------------------------------------------------------------------

    45. Courts have recognized that the Commission has broad authority 
under the FPA to identify practices that ``affect'' public utility 
wholesale rates under the FPA.\66\ For instance, most recently, the DC 
Circuit held that it was within the Commission's jurisdiction to review 
ISO New England's annual calculation of the minimum amount of wholesale 
electric capacity that must be available to assure reliable service in 
the New England region.\67\ The court stated that ``even if all the 
[Installed Capacity Requirement] did was help to find the right price, 
it would still amount to a `practice * * * affecting rates' '' for 
purposes of Commission authority.\68\
---------------------------------------------------------------------------

    \66\ See, e.g., City of Cleveland v. FERC, 773 F.2d 1368, 1376 
(D.C. Cir. 1985) (``[T]here is an infinitude of practices affecting 
rates and service. * * * It is obviously left to the Commission, 
within broad bounds of discretion, to give concrete application to 
this amorphous directive.'').
    \67\ Connecticut Dep't of Public Util. Control v. FERC, No. 07-
1375, slip op. at 14-15 (D.C. Cir. June 23, 2009).
    \68\ Id. at 15. The court further stated that ``[w]here capacity 
decisions about an interconnected bulk power system affect 
[Commission]-jurisdictional transmission rates for that system * * * 
they come within the Commission's authority,'' adding that ``there 
is nothing special about capacity decisions that places them beyond 
the Commission's jurisdiction''. Id. at 14-15.

---------------------------------------------------------------------------

[[Page 37783]]

    46. The Commission has found on several occasions that demand 
response affects wholesale markets, rates, and practices and, 
therefore, issued orders on various aspects of electric demand response 
in organized markets. Some of these orders approved various types of 
demand response programs, including programs to allow demand response 
to be used as a capacity resource \69\ and as a resource during system 
emergencies,\70\ 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 services markets, particularly as 
a provider of operating reserves, as well as programs to accept bids 
from ARCs.\71\
---------------------------------------------------------------------------

    \69\ See, e.g., PJM Interconnection, LLC, 117 FERC ] 61,331 
(2006); Devon Power L.L.C., 115 FERC ] 61,340, order on reh'g, 117 
FERC ] 61,133 (2006).
    \70\ 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).
    \71\ 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).
---------------------------------------------------------------------------

    47. Demand response affects public utility wholesale rates because 
decreasing demand will tend to result in lower prices and less price 
volatility.\72\ The Commission has noted that demand response has both 
a direct and an indirect effect on wholesale prices. The direct effect 
occurs when demand response is bid directly into the wholesale market: 
lower demand means a lower wholesale price. Demand response at the 
retail level affects the wholesale market indirectly because it reduces 
a load-serving entity's need to purchase power from the wholesale 
market.\73\ Demand response tends to flatten an area's load profile, 
which in turn may reduce the need to construct and use more costly 
resources during periods of high demand; the overall effect is to lower 
the average cost of producing energy.\74\ Demand response can help 
reduce generator market power: the more demand response is able to 
reduce peak prices, 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 a price that is too high.\75\ Moreover, 
demand response enhances system reliability.\76\ Thus, because demand 
response directly affects wholesale rates, reducing barriers to demand 
response in the organized wholesale markets helps the Commission to 
fulfill its responsibility, under sections 205 and 206 of the FPA, for 
ensuring that those rates are just and reasonable.\77\
---------------------------------------------------------------------------

    \72\ ANOPR, FERC Stats. & Regs. ] 32,617 at P 37.
    \73\ NOPR, FERC Stats. & Regs. ] 32,628 at P 29.
    \74\ Id. P 30. Increasing the presence of demand response also 
provides market participants with better information about where 
they should and should not construct upgrades. ``In current market 
contexts, constructing new generation facilities in response to a 
higher [installed capacity requirement] may even feel like an 
imperative. But petitioners have posited no source for that feeling 
other than internalization of the true costs of the alternatives, 
which is not only a requirement for efficient market outcomes, but, 
again, something the Commission may concededly pursue.'' Connecticut 
Dep't of Public Util. Control v. FERC, No. 07-1375, slip op. at 11 
(D.C. Cir. June 23, 2009).
    \75\ NOPR, FERC Stats. & Regs. ] 32,628 at P 31.
    \76\ For example, ``[b]y reducing electricity demand at critical 
times (e.g., when a generator or a transmission line unexpectedly 
fails), demand response that is dispatched by the system operator on 
short notice can help return electric system (or localized) reserves 
to pre-contingency levels.'' Federal Energy Regulatory Commission, 
Assessment of Demand Response and Advanced Metering: Staff Report, 
Docket No. AD06-2-000, at 11 (Aug. 2006) (2006 FERC Staff Demand 
Response Assessment); see also Federal Energy Regulatory Commission, 
Assessment of Demand Response and Advanced Metering: Staff Report, 
at 50-53 (Dec. 2008) (describing the use of demand response during 
system emergencies in 2007 to ensure system reliability).
    \77\ Where a provision or term directly affects a wholesale 
rate, it is within the Commission's jurisdiction. See, e.g., 
Connecticut Dep't of Public Util. Control v. FERC, No. 07-1375, slip 
op. at 10 (D.C. Cir. June 23, 2009) (finding that the Commission has 
jurisdiction to directly or indirectly establish prices for capacity 
even for the purposes of incentivizing construction of new 
generation facilities); Mississippi Industries v. FERC, 808 F.2d 
1525 (D.C. Cir. 1987), vacated in part on other grounds, 822 F.2d 
1103 (D.C. Cir. 1987) (holding that the Commission had jurisdiction 
over the allocation of a nuclear plant's capacity and costs because 
it ``directly affects costs and, consequently, wholesale rates.''); 
Municipalities of Groton v. FERC, 587 F.2d 1296, (D.C. Cir. 1978); 
Cal. Indep. Sys. Operator Corp., 119 FERC ] 61,076, at P 540-56 
(2007) (finding that maintaining adequate resources falls within 
Commission jurisdiction because it has a direct and significant 
effect on wholesale rates and services); ISO New England, Inc., 119 
FERC ] 61,161, at P 18-30 (2007) (same).
---------------------------------------------------------------------------

    48. While the Commission, in regulating public utility wholesale 
sales under the FPA, may act on demand response participation in the 
organized markets, we emphasize that this proceeding is a very 
narrowly-focused rule with respect to demand response resources. It 
directs an RTO or ISO that operates an organized wholesale electric 
market--a market subject to the Commission's exclusive jurisdiction--to 
reduce certain barriers to demand response participation in that 
market.\78\ We anticipate that reducing barriers to demand response 
participation in wholesale markets also may have beneficial effects as 
described above, including greater price stability and better 
information for market participants as to where they need to make grid 
improvements.
---------------------------------------------------------------------------

    \78\ Order No. 719, FERC Stats. & Regs. ] 31,281 at P 3; NOPR, 
FERC Stats. & Regs. ] 32,628 at P 282.
---------------------------------------------------------------------------

    49. Several requests for rehearing argue that the Final Rule 
exceeds this narrow scope, and violates the separation of Federal and 
State jurisdiction, by requiring load-serving entities, including 
public power systems and cooperative utilities, to take affirmative 
action to consider the issue of retail aggregation by ARCs. However, 
our Final Rule did not challenge the role of States and others to 
decide the eligibility of retail customers to provide demand response 
and, as explained below, we are taking additional steps to address the 
burden allegedly imposed by our Final Rule on smaller entities.
    50. Some rehearing requests, including those from TAPS and Joint 
Petitioners, ask us to assume that an ARC may not participate in RTO or 
ISO markets if the relevant State or local laws and regulations are 
unstated or do not clearly allow ARCs to bid into wholesale markets. We 
will grant rehearing only to the extent consistent with the compromise 
proposal by APPA and TAPS based on the RFA threshold of 4 million MWh 
as modified below. The RTO or ISO should not be in the position of 
having to interpret when the laws or regulations of a relevant electric 
retail regulatory authority are unclear. While we leave it to the 
relevant retail authority to decide the eligibility of retail 
customers, their decision or policy should be clear and explicit so 
that the RTO or ISO is not tasked with interpreting ambiguities.
    51. However, as discussed below, we agree with APPA and TAPS that 
it is reasonable to take a different approach here with small 
utilities.\79\ The Commission has previously distinguished small 
utilities using a 4

[[Page 37784]]

million MWh cutoff for purposes of granting waivers from Order No. 
889's \80\ standards of conduct for transmission providers \81\ or 
determining whether a specific cooperative should be considered a non-
public utility outside the scope of a refund obligation involving the 
California energy crisis.\82\ Similarly, Congress used the 4 million 
MWh cutoff in EPAct 2005 when amending exclusions in section 201(f) of 
the FPA to include small electric cooperatives.\83\ Congress also used 
this same cutoff to exempt small utilities from compliance with any 
rules or orders imposed under section 211A of the FPA, involving open 
access by unregulated transmitting utilities.\84\ We believe the same 
considerations underlying those actions by Congress and the Commission 
apply here. Thus, we will grant rehearing and adopt herein APPA's and 
TAPS's alternative proposal, with modifications. We direct RTOs and 
ISOs to amend their market rules as necessary to accept bids from ARCs 
that aggregate the demand response of: (1) The customers of utilities 
that distributed more than 4 million MWh in the previous fiscal year, 
and (2) the customers of utilities that distributed 4 million MWh or 
less in the previous fiscal year, where the relevant electric retail 
regulatory authority permits such customers' demand response to be bid 
into organized markets by an ARC. RTOs and ISOs may not accept bids 
from ARCs that aggregate the demand response of: (1) The customers of 
utilities that distributed more than 4 million MWh in the previous 
fiscal year, where the relevant electric retail regulatory authority 
prohibits such customers' demand response to be bid into organized 
markets by an ARC, or (2) the customers of utilities that distributed 4 
million MWh or less in the previous fiscal year, unless the relevant 
electric retail regulatory authority permits such customers' demand 
response to be bid into organized markets by an ARC.\85\
---------------------------------------------------------------------------

    \79\ 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. 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 year 
did not exceed 4 million MWh. 13 CFR 121.202 (Sector 22, Utilities, 
North American Industry Classification System (NAICS)) (2004).
    \80\ Open Access Same-Time Information System and Standards of 
Conduct, Order No. 889, FERC Stats. & Regs. ] 31,035, clarified, 77 
FERC ] 61,253 (1996), order on reh'g, Order No. 889-A, FERC Stats. & 
Regs. ] 31,049, reh'g denied, Order No. 889-B, 81 FERC ] 61,253 
(1997), aff'd in relevant part sub nom. Transmission Access Policy 
Study Group v. FERC, 225 F.3d 667 (D.C. Cir. 2006).
    \81\ See Wolverine Power Supply Coop., 127 FERC ] 61,159, at P 
15 (2009).
    \82\ See San Diego Gas & Elec. Co. v. Sellers of Energy and 
Ancillary Services in Markets Operated by the CAISO, 125 FERC ] 
61,297, at P 24 (2008).
    \83\ 16 U.S.C. 824(f).
    \84\ 16 U.S.C. 824j-l(c)(1).
    \85\ In the Final Rule, the Commission allowed RTOs and ISOs to 
specify certain requirements for an ARC's bids, including 
certification that participation is not precluded by the relevant 
electric retail regulatory authority. Order No. 719, FERC Stats. & 
Regs. ] 31,281 at P 158g.
---------------------------------------------------------------------------

    52. Petitioners argue that the Commission lacks jurisdiction over 
demand response because a retail customer's decision to reduce energy 
consumption does not fall within the Commission's authority under 
section 201 of the FPA. They assert that a reduction in consumption of 
energy does not constitute a wholesale sale or transmission of electric 
energy in interstate commerce. Petitioners miss the point. An RTO's or 
ISO's market rules are subject to our exclusive jurisdiction. These 
rules cover market bids from generators and from providers of demand 
response, which directly affect wholesale prices as discussed above. 
Accordingly, the Commission has found that it has jurisdiction to 
regulate the market rules under which an RTO or ISO accepts a demand 
response bid into a wholesale market.
    53. The Commission, in acting within its FPA jurisdiction, is also 
furthering Congressional policy to encourage demand response programs 
under EPAct 2005:

    It 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.\86\
---------------------------------------------------------------------------

    \86\ EPAct 2005, section 1252(f) (emphasis added).

    54. We recognize that demand response is a complex matter that is 
subject to the confluence of State and Federal jurisdiction. The Final 
Rule's intent and effect are neither to encourage or require actions 
that would violate State laws or regulations nor to classify retail 
customers and their representatives as wholesale customers, as Ohio PUC 
asserts. The Final Rule also does not make findings about retail 
customers' eligibility, under State or local laws, to bid demand 
response into the organized markets, either independently or through an 
ARC. The Commission also does not intend to make findings as to whether 
ARCs may do business under State or local laws, or whether ARCs' 
contracts with their retail customers are subject to State and local 
law. Nothing in the Final Rule authorizes a retail customer to violate 
existing State laws or regulations or contract rights. In that regard, 
we leave it to the appropriate State or local authorities to set and 
enforce their own requirements.
    55. Finally, with regard to AEP's request for clarification, we 
note that this proceeding is a very narrowly-focused rule, as discussed 
above. The clarification that AEP is seeking involves State laws and 
regulations, and how they are interpreted in relation to the policies 
contained in this proceeding. It is not within the scope of this 
rulemaking to interpret individual State laws and regulations.
ii. Burden on Small Entities and Regulatory Flexibility Analysis
    56. In regard to arguments concerning the burden of this rule on 
small entities and the need for RFA analysis, we reiterate that the 
Final Rule does not require a relevant electric retail regulatory 
authority to make any showing or to take any action in compliance with 
the Final Rule.\87\ The NOPR specifically stated that those entities 
directly affected by this proceeding are the six RTOs and ISOs, namely, 
CAISO, NYISO, PJM, SPP, Midwest ISO, and ISO New England.\88\ The Final 
Rule adopted this approach and established that its requirements, 
including the ARC requirement, apply only to RTOs and ISOs.\89\
---------------------------------------------------------------------------

    \87\ Order No. 719, FERC Stats. & Regs. ] 31,281 at P 155.
    \88\ NOPR, FERC Stats. & Regs. ] 32,628 at P 291.
    \89\ Order No. 719, FERC Stats. & Regs. ] 31,281 at P 155, 602.
---------------------------------------------------------------------------

    57. TAPS and Joint Petitioners contend that the Commission's 
requirement that RTOs and ISOs accept bids from ARCs makes it 
imperative for relevant electric retail regulatory authorities to 
decide whether ARCs within their jurisdiction may offer demand response 
into wholesale markets. TAPS and Joint Petitioners argue that it would 
be a major undertaking for a retail regulator to clarify for an RTO or 
ISO whether an ARC may aggregate the demand response of retail 
customers within the service territories of the load-serving entities 
it regulates. However, these entities have not provided any new 
arguments on rehearing, and we continue to find that the Final Rule 
does not require retail regulators to take any action whatsoever. The 
Final Rule indicated only that the RTO and ISO must accept bids from an 
ARC unless the laws or regulations of the relevant electric retail 
regulatory authority do not permit the ARC to bid. It did not require 
that retail regulators consider this issue or make any representation, 
nor did it require the RTO or ISO to impose on retail regulators the 
task of

[[Page 37785]]

communicating this lack of permission at all, much less through a 
complex or burdensome procedure.
    58. In its NOPR comments, APPA proposed an alternative approach, 
which Joint Petitioners and TAPS support on rehearing. APPA suggested 
that the retail regulators of public power systems that have output of 
more than 4 million MWh in one year would need to notify their RTOs or 
ISOs if their local election was to prohibit ARCs from aggregating 
retail customers. In the case of public power systems that do not meet 
this size requirement, however, the presumption would be reversed: the 
RTO or ISO would be required to assume that aggregation was not 
permitted unless the retail regulator instructed it to do otherwise.
    59. In response to those comments, we reiterate that the Commission 
does not intend to impose any affirmative obligation to act on relevant 
electric retail regulatory authorities. We will, however, grant 
rehearing in part and adopt a modified version of APPA's proposal. As 
indicated above, the Commission believes that using a 4 million MWh 
cutoff for purposes of distinguishing small utilities is 
appropriate.\90\
---------------------------------------------------------------------------

    \90\ See discussion supra P 51.
---------------------------------------------------------------------------

    60. Therefore, we direct RTOs and ISOs to amend their market rules 
as necessary to accept bids from ARCs that aggregate the demand 
response of: (1) The customers of utilities that distributed more than 
4 million MWh in the previous fiscal year, and (2) the customers of 
utilities that distributed 4 million MWh or less in the previous fiscal 
year, where the relevant electric retail regulatory authority permits 
such customers' demand response to be bid into organized markets by an 
ARC. RTOs and ISOs may not accept bids from ARCs that aggregate the 
demand response of: (1) The customers of utilities that distributed 
more than 4 million MWh in the previous fiscal year, where the relevant 
electric retail regulatory authority prohibits such customers' demand 
response to be bid into organized markets by an ARC, or (2) the 
customers of utilities that distributed 4 million MWh or less in the 
previous fiscal year, unless the relevant electric retail regulatory 
authority permits such customers' demand response to be bid into 
organized markets by an ARC. Our adoption of a modified version of 
APPA's alternative proposal provides that relevant electric retail 
regulatory authorities of small utilities meeting the above-noted 
criteria need not consider this issue except to permit ARCs to 
aggregate the demand response of retail customers of such small 
utilities.
    61. With regard to the arguments that the Commission erred by 
failing to do an RFA analysis, we note that if an agency certifies that 
the rule will not have a significant economic impact on a substantial 
number of small entities, as we have done in the Final Rule, it is not 
required to conduct an RFA analysis.\91\ RFA does not require an agency 
to assess the impact of a rule on all small entities that may be 
affected by a rule, only those entities that would be directly 
regulated by the rule.\92\ While State and local laws and regulations 
will determine whether many utilities--large or small--may be affected 
by this rule, the rule directly regulates only RTOs and ISOs.
---------------------------------------------------------------------------

    \91\ 16 U.S.C. 605(b).
    \92\ Mid-Tex Electric Corp., Inc. v. FERC, 773 F.2d 327, 342 
(D.C. Cir. 1985) (Mid-Tex) (``Congress did not intend to require 
that every agency consider every indirect effect that any regulation 
might have on small businesses in any stratum of the national 
economy'').
---------------------------------------------------------------------------

    62. Further, we reiterate that in American Trucking Associations, 
the court found that because the States, not EPA, had direct authority 
to impose regulations on small entities, EPA's rule did not have a 
direct impact on small entities. Accordingly, based on its holding in 
Mid-Tex, the court held that EPA is not required to conduct an RFA 
analysis.\93\ We reject TAPS's premise that this case is inapplicable 
to the issue of whether an RFA analysis is required for Order No. 719 
because RTOs and ISOs cannot mitigate the burden allegedly placed on 
small entities. The court in American Trucking Associations did not 
hold that whether the small entities at issue would be burdened by the 
EPA's action depended on the State's intermediate and discretionary 
action. Rather, the court noted that a State, under its broad 
discretion to determine how it implements EPA's rule, may choose not to 
comply with EPA's rule altogether. This would require EPA to adopt an 
implementation plan of its own and, thereby, impose a direct burden on 
small entities.\94\ The court noted that in such a circumstance, EPA 
stated that it will do an RFA analysis. Therefore, whether RTOs and 
ISOs are able to mitigate this burden is not an issue and does not 
affect the finding that Order No. 719 does not directly impact small 
entities, as in American Trucking Associations.
---------------------------------------------------------------------------

    \93\ American Trucking Associations, 175 F.3d at 1044.
    \94\ Id. at 1044 (``Only if a [s]tate does not submit a [state 
implementation plan] that complies with [EPA's rule], must the EPA 
adopt an implementation plan of its own, which would require the EPA 
to decide what burdens small entities should bear'').
---------------------------------------------------------------------------

    63. As stated earlier, the Final Rule does not require relevant 
electric retail regulatory authorities to take any specific action. As 
such, there was no direct impact on small entities associated with the 
draft regulations, and the Final Rule did not require a detailed 
analysis of alternative proposals that would have allegedly mitigated 
such a burden. We also note that while the requirements in the Final 
Rule will have no direct impact on small entities, we recognize the 
concerns raised by APPA and TAPS. Therefore, as noted above, we grant 
rehearing and adopt a modified version of APPA's alternative proposal.
    64. Each RTO or ISO is required to submit, within 90 days of the 
date that this order on rehearing is published in the Federal Register, 
a compliance filing with the Commission, proposing amendments to its 
tariffs or otherwise demonstrating how its existing tariffs and market 
design comply with the revisions adopted herein.
iii. Effect on Existing Demand Response Programs and on Rates, 
Metering, and Billing Protocols
    65. In the Final Rule, we found that aggregating small retail 
customers into larger pools of resources expands the amount of 
resources available to the market, increases competition, helps reduce 
prices to consumers, and enhances reliability.\95\ Petitioners have not 
demonstrated to the contrary. For example, petitioners have failed to 
present evidence that demand response aggregated by an ARC does not 
have the effect of lowering prices for all customers and maintaining 
reliability at a lower cost than would have been the case if the RTO or 
ISO had instead dispatched a resource that submitted a higher bid.
---------------------------------------------------------------------------

    \95\ Order No. 719, FERC Stats. & Regs. ] 31,281 at P 154.
---------------------------------------------------------------------------

    66. However, petitioners argue that the ARC requirement's effect on 
the existing demand response program of load-serving entities is 
substantial, and that the Commission failed to adequately consider such 
effects and certain protocol modifications needed to accommodate the 
Final Rule's policy. We note that petitioners have not provided clear 
evidence of such adverse impacts, but have merely asserted that they 
would occur if retail customers are permitted to participate in 
wholesale markets via ARCs. Also, petitioners have not shown why the 
issues they raise cannot be adequately addressed by each RTO and ISO 
through the

[[Page 37786]]

stakeholder process and included as part of the RTO's or ISO's 
compliance filing.\96\ As a result, we find that petitioners' arguments 
are speculative; they have not persuaded us that the policy decisions 
made in the Final Rule were the result of error. Therefore, we deny 
rehearing.
---------------------------------------------------------------------------

    \96\ The Final Rule provided regional flexibility for each RTO 
and ISO to work with its stakeholders in proposing market rules 
appropriate for its region. Id. P 155. Interested parties could 
participate in that stakeholder process. By filing comments on the 
RTO's or ISO's subsequent compliance filing, interested parties had 
an additional opportunity to address the Commission directly on any 
remaining concerns with the RTO's or ISO's implementation proposal. 
The Commission will address the merits of such implementation issues 
on a case-by-case basis.
---------------------------------------------------------------------------

    67. TAPS asks us to clarify that the Final Rule would not undermine 
or require any changes to existing retail aggregation programs. We 
reiterate that the Final Rule is designed to eliminate barriers to 
demand response participation in RTO or ISO markets. To that end, the 
Final Rule requires an RTO or ISO to accept bids into its markets from 
an ARC, unless the laws or regulations of the relevant electric retail 
regulatory authority for utilities that had total electric output for 
the preceding fiscal year of more than 4 million MWh do not permit a 
retail customer to participate. For smaller systems under the RFA size 
requirement, ARCs may aggregate retail customers only if affirmatively 
permitted to do so by the relevant electric retail regulatory 
authority. Each RTO or ISO is required to work with its stakeholders to 
propose methods of implementing this requirement in its region. The 
intent of the Final Rule is not to interfere with, undermine, or change 
existing demand response programs. Nothing in the Final Rule would 
require a State or local regulator to take any action or prevent them 
from: (1) Preserving existing aggregation programs, in whatever fashion 
is appropriate for its jurisdictional area; or (2) authorizing retail 
customers, via an ARC, to participate in wholesale markets.
    68. TAPS and Joint Petitioners emphasize that existing retail 
aggregation programs provide significant benefits that would be 
adversely impacted or lost by the Final Rule's ARC requirement. This is 
not the proper forum to address these issues, which are for the 
relevant electric retail regulatory authority to consider. It is up to 
the relevant electric retail regulatory authorities, if they so choose, 
to decide whether existing retail aggregation programs provide benefits 
and whether retail customer participation in wholesale demand response 
programs, individually or through an ARC, would adversely affect those 
programs and, if so, whether and how to permit such participation. 
Therefore, TAPS and Joint Petitioners may raise these issues with the 
relevant electric retail regulatory authority.
    69. TAPS also contends that the Final Rule's ARC requirement will 
affect billing, metering, and settlement protocols at both the 
wholesale and retail level because major system modifications are 
needed to address double counting, phantom energy, and verification 
measures. TAPS and others also express concern that a load-serving 
entity may buy too much power if its retail customer bids in demand 
response and the load-serving entity is unaware of the bid, creating an 
over-scheduling penalty for the load-serving entity. We note that 
several RTOs and ISOs currently have demand response programs where 
demand response resources participate either individually or through an 
ARC. Some of these RTOs and ISOs have addressed the type of concerns 
raised by TAPS with regard to double counting, verification procedures, 
deviation charges and the like. We will require each RTO or ISO, 
through the stakeholder process, to develop appropriate mechanisms for 
sharing information about demand response resources to address the 
concerns raised by TAPS and others. We direct each RTO and ISO, through 
the stakeholder process, to develop, at a minimum, a mechanism through 
which an affected load-serving entity would be notified when load 
served by that entity is enrolled to participate, either individually 
or through an ARC, as a demand response resource in an RTO or ISO 
market and the expected level of that participation for each enrolled 
demand response resource.\97\ Finally, we direct each RTO and ISO to 
submit a compliance filing no later than 180 days from the date of this 
order indicating how it has complied with these requirements.
---------------------------------------------------------------------------

    \97\ TAPS requested, among other things, that we direct the RTO 
or ISO to provide certain detailed information in real-time to 
affected load-serving entities. TAPS has failed to demonstrate the 
need for such data in real-time.
---------------------------------------------------------------------------

    70. Therefore, as stated in the Final Rule, we require each RTO or 
ISO to work with its stakeholders, including load-serving entities and 
ARCs, to develop and implement protocols that will address those issues 
and allow ARCs to operate within the organized market. Those protocols 
should address those issues raised by petitioners, including double-
counting, concerns regarding deviation, underscheduling, and uplift or 
other charges that may be incurred if real-time load is below that 
scheduled in the day-ahead market, as well as metering, billing, 
settlement, information sharing and verification measures to be 
submitted in an RTO's or ISO's compliance filing ordered above.
    71. We again reject the argument that the Commission should require 
RTOs and ISOs to evaluate the efficacy of ARC-based demand response 
programs given the costs involved in modifying systems to accommodate 
bids by retail customers and the adverse impact on load-serving entity 
administered programs. As stated above, RTOs and ISOs, in conjunction 
with their stakeholders, including ARCs and load-serving entities, are 
in the best position to decide whether to incur the costs of conducting 
such an analysis. In recognition of regional differences, the Final 
Rule directed each RTO and ISO to work with its stakeholders to discuss 
and resolve concerns, including demonstrating net benefits of its 
program and to address these issues in its compliance filing with the 
Commission.\98\
---------------------------------------------------------------------------

    \98\ Order No. 719, FERC Stats. & Regs. ] 31,281 at P 159.
---------------------------------------------------------------------------

3. Market Rules Governing Price Formation During Periods of Operating 
Reserve Shortage
    72. In the Final Rule, the Commission found that existing RTO and 
ISO market rules that do not allow prices to rise sufficiently during 
an operating reserve shortage to allow supply to meet demand are unjust 
and unreasonable, and may be unduly discriminatory.\99\ The Commission 
stated that these rules may not produce prices that accurately reflect 
the true value of energy in such an emergency and, by failing to do so, 
may harm reliability, inhibit demand response, deter new entry of 
demand response and generation resources, and thwart innovation.\100\
---------------------------------------------------------------------------

    \99\ Id. P 192.
    \100\ Id.
---------------------------------------------------------------------------

    73. The Commission established reforms to remove barriers to demand 
response by requiring RTOs and ISOs to reform their market rules in 
such a way that prices during operating reserve shortages more 
accurately reflect the value of energy during such shortages. The Final 
Rule required each RTO or ISO to reform or demonstrate the adequacy of 
its existing market rules to ensure that the market price for energy 
reflects the value of energy during an operating reserve shortage.\101\ 
Each RTO or ISO may propose in its compliance filing one of four 
suggested approaches

[[Page 37787]]

to pricing reform during an operating reserve shortage, or develop its 
own alternative approach to achieve the same objectives.\102\ The Final 
Rule also required each RTO or ISO to support its compliance filing 
with adequate factual support. To that end, the Commission outlined six 
criteria it will consider in reviewing whether the factual record 
compiled by the RTO or ISO meets the requirements of the Final 
Rule.\103\ The Final Rule also allowed an RTO or ISO to phase in any 
new pricing rules for a period of a few years, provided that this 
period is not protracted.
---------------------------------------------------------------------------

    \101\ Id. P 194.
    \102\ The four approaches are: (1) RTOs and ISOs would increase 
the energy supply and demand bid caps above the current levels only 
during an emergency; (2) RTOs and ISOs would increase bid caps above 
the current level during an emergency only for demand bids while 
keeping generation bid caps in place; (3) RTOs and ISOs would 
establish a demand curve for operating reserves, which has the 
effect of raising prices in a previously agreed-upon way as 
operating reserves grow short; and (4) RTOs and ISOs would set the 
market-clearing price during an emergency for all supply and demand 
response resources dispatched equal to the payment made to 
participants in an emergency demand response program. Id. P 208.
    \103\ The six criteria are: (1) Improve reliability by reducing 
demand and increasing supply during periods of operating reserve 
shortages; (2) make it more worthwhile for customers to invest in 
demand response technologies; (3) encourage existing generation and 
demand resources to continue to be relied upon during an operating 
reserve shortage; (4) encourage entry of new generation and demand 
resources; (5) ensure that the principle of comparability in 
treatment of and compensation to all resources is not discarded 
during periods of operating reserve shortage; and (6) ensure market 
power is mitigated and gaming behavior is deterred during periods of 
operating reserve shortages including, but not limited to, showing 
how demand resources discipline bidding behavior to competitive 
levels. Id. P 246-47.
---------------------------------------------------------------------------

a. Requests for Rehearing
i. Shortage Pricing Proposal
    74. Several petitioners requested rehearing of the Commission's 
shortage pricing requirement on grounds that the requirement would 
eliminate price caps during periods when bidders could exercise market 
power; that customers do not yet have in place the tools to respond to 
price; that there is not sufficient market mitigation in place to 
ensure a competitive result; that the Commission did not provide 
sufficient evidence that its shortage pricing requirement would achieve 
its stated goals; or that the Commission ignored arguments or evidence 
provided by NOPR commenters indicating that the Commission's proposal 
may not achieve the desired results.
    75. Joint Petitioners argue that the Commission failed to 
substantiate its finding that existing RTO and ISO market rules are 
unjust and unreasonable because they do not allow prices to rise 
sufficiently during operating reserve shortages. Joint Petitioners 
state that any higher prices during operating reserve shortages would 
reflect market power, not efficient shortage pricing.\104\ They state 
that given the existing market power problems in organized markets, 
raising price caps can result in prices that are inefficiently high. 
Joint Petitioners note that, in concluding that market power will be 
adequately mitigated through the shortage pricing requirement, the 
Commission ignored contrary evidence from APPA and NRECA.\105\
---------------------------------------------------------------------------

    \104\ Joint Petitioners at 32-33.
    \105\ Id. at 44 (citing NRECA Affidavit at P 20-55).
---------------------------------------------------------------------------

    76. Similarly, TAPS states that the Commission must have empirical 
proof that existing competition would ensure that the actual price is 
just and reasonable before it permits RTOs and ISOs to remove price 
caps during emergencies. Yet, according to TAPS, the Final Rule's 
shortage pricing requirement lacks evidence that existing offer and bid 
caps actually limit demand response, that lifting such caps will 
attract investment in generation and demand response sufficient to 
protect consumers from market power, and that consumers will be able to 
protect themselves from high prices.\106\ In light of contrary 
evidence, TAPS contends that the Commission must provide evidence that 
consumers will be able to protect themselves from high prices through 
demand response programs. For instance, TAPS states that existing 
evidence indicates that the short-run demand curve for electricity is 
highly inelastic.\107\
---------------------------------------------------------------------------

    \106\ TAPS at 33 (citing TAPS NOPR Comments at 24-27).
    \107\ Id. at 39.
---------------------------------------------------------------------------

    77. SMUD argues that the Commission's decision to lift price and 
bid caps constitutes an arbitrary and unexplained departure from its 
precedent.\108\ It states that the Commission has previously 
established that demand response technologies are insufficiently 
developed to permit the relaxation of bid caps\109\ and the Final Rule 
fails to demonstrate how circumstances are sufficiently different to 
warrant a change in Commission policy.
---------------------------------------------------------------------------

    \108\ For example, SMUD explains that in NYISO, the Commission 
imposed a bid cap based on its finding that the NYISO market lacks 
demand-side responsiveness to prices and that it has tight supplies. 
Id. at 5. (citing New York Indep. System Operator, 97 FERC ] 61,154, 
at 61,673 (2001)). SMUD also adds that the Commission previously 
found that price caps are necessary to prevent opportunistic pricing 
during periods of capacity shortages and that bid caps provide a 
safety net to contain prices in peak periods when supply is short. 
SMUD at 4. (citing ISO New England, Inc., 97 FERC ] 61,090, at 
62,469, 61,470-471 (2001)).
    \109\ Id. at 4. (citing Nstar Serv. Co. v. New England Power 
Pool, 92 FERC ] 61,065, at 62,198-99 (2000)).
---------------------------------------------------------------------------

    78. Joint Petitioners maintain that allowing real-time market-
clearing prices to exceed price caps during periods of shortage will 
increase price volatility, which in turn may increase hedging 
costs.\110\ Industrial Coalitions submit that the Commission should 
develop metrics for measuring demand elasticity and for evaluating 
whether higher and more volatile prices actually become a key factor in 
capital deployment decisions. In support, they argue that demand 
response infrastructure remains underdeveloped, and therefore cannot 
serve as a viable check on the exercise of market power.\111\
---------------------------------------------------------------------------

    \110\ Joint Petitioners at 41.
    \111\ Industrial Coalition at 7-8.
---------------------------------------------------------------------------

    79. Pennsylvania PUC asserts that without real-time demand 
response, the Commission's assumption that shortage pricing will 
represent the true value of supply is false because only supply-side 
resources will be able to respond to prices and such one-sided markets 
cannot be protected from the exercise of market power.\112\ Joint 
Petitioners also argue that the Final Rule wrongly concluded that 
demand response itself will act as a market power mitigation measure 
based on a faulty assumption that end-use customers will be able to 
respond to shortage pricing by reducing their demand.\113\
---------------------------------------------------------------------------

    \112\ Pennsylvania PUC at 5.
    \113\ Joint Petitioners at 48-49.
---------------------------------------------------------------------------

    80. Similarly, Old Dominion asserts that the Commission erred in 
mandating a shortage pricing requirement, without first addressing an 
approach to eliminate non-price barriers. It contends that the 
Commission noted, but did not address, its NOPR comments that consumers 
will face increased prices without the ability to respond to price 
signals. Old Dominion contends that it is difficult to ascertain 
whether legitimate market forces or the exercise of market power is the 
cause of increased prices, and that the solution is not to mandate 
removal of price protections that are necessary for market-based rates 
to be just and reasonable. Old Dominion adds that the capacity auction 
structure under PJM's Reliability Pricing Model is designed to capture 
scarcity rents; that there should not be double collection through an 
aggressive shortage pricing construct; and that there is an existing 
construct that seeks to meet the reliability and incentive goals of the 
Final Rule.\114\ Therefore, it requests that the Commission take up the 
issue of

[[Page 37788]]

whether to mandate shortage pricing only after it has addressed 
proposals on eliminating barriers to demand response. In the 
alternative, Old Dominion renews its request that the Commission adopt 
a presumption that such pricing incentives are not necessary, and 
require RTOs and ISOs that believe otherwise to make a factual 
demonstration in support of their proposal.\115\
---------------------------------------------------------------------------

    \114\ Old Dominion at 4.
    \115\ Id. at 5-6.
---------------------------------------------------------------------------

    81. Ohio PUC states that the Commission adopted a proposal to 
remove bid caps for generation during periods of operating reserve 
shortage, but should also consider raising bid caps only for demand 
bids until market power concerns are alleviated and the market for 
demand response is more fully developed.\116\
---------------------------------------------------------------------------

    \116\ Ohio PUC at 7.
---------------------------------------------------------------------------

    82. Joint Petitioners note that if the Commission is serious about 
including consumer protections, including meaningful market power 
mitigation mechanisms in RTO and ISO shortage pricing filings, the 
Commission should require evidentiary hearings regarding the RTO's and 
ISO's shortage pricing proposals and the sufficiency of their proposed 
mitigation mechanisms.\117\
---------------------------------------------------------------------------

    \117\ They note that the Commission never addressed APPA's 
request for full evidentiary hearings. Id. at 49 (citing APPA NOPR 
Comments at 54-55, 62, 64).
---------------------------------------------------------------------------

    83. TAPS contends that the Commission failed to clarify the 
definition of operating reserve shortage and ignored TAPS's concern 
that the definition may be too broad. TAPS also notes that the preamble 
to the Final Rule suggests that the Commission intended to define an 
operating reserve shortage as falling short of meeting the operating 
reserve requirements under the reliability standards approved by the 
Commission under FPA section 215,\118\ yet the regulatory text provides 
a definition without referring to these reliability standards. 
Therefore, it suggests that the Commission revise the definition to 
restrict shortage pricing to instances where the RTO or ISO risks being 
unable to replenish operating reserves within the period specified in 
applicable reliability standards.\119\
---------------------------------------------------------------------------

    \118\ Order No. 719, FERC Stats. & Regs. ] 31,281 at P 251.
    \119\ TAPS at 54-56.
---------------------------------------------------------------------------

ii. Four Shortage Pricing Approaches and Criteria Requirements
    84. Several petitioners requested rehearing of the Commission's 
shortage pricing approaches on grounds that the Commission failed to 
consider evidence presented by NOPR commenters that one or more of the 
approaches will not achieve the desired results; that the Commission 
did not adequately consider alternative approaches or criteria 
presented by NOPR commenters; and that the Commission needed to provide 
more direction to RTOs and ISOs on how to implement its proposal and to 
provide evidence of its expected benefits.
    85. TAPS states that the Commission ignored NOPR comments regarding 
the defects of the four shortage pricing approaches. TAPS argues that 
the four approaches are not just and reasonable because they: (1) Fail 
to protect consumers from market power; (2) are premised on unsupported 
assumptions about bidding behavior and consumers; (3) require the 
adoption of particular wholesale market structures that have not been 
established in all RTOs and ISOs; and (4) may encourage gaming.\120\
---------------------------------------------------------------------------

    \120\ Id. at 42-45.
---------------------------------------------------------------------------

    86. Joint Petitioners argue that the Commission acted arbitrarily 
and capriciously by failing to consider evidence from NOPR comments, 
including those provided by NRECA, that the four shortage pricing 
approaches will not achieve the Commission's stated goals.\121\ They 
assert that the four approaches will: (1) Fail to protect consumers and 
lead to unjust and unreasonable rates; (2) undermine reliability or 
preserve reliability only by unlawfully shifting rents from consumers 
to generators; (3) encourage behavior by generators that creates 
emergencies; and (4) not attract new supply resources to real-time or 
long-term markets.\122\
---------------------------------------------------------------------------

    \121\ Joint Petitioners at 35 (citing Order No. 719, FERC Stats. 
& Regs. ] 31,281 at P 235).
    \122\ Id. at 41.
---------------------------------------------------------------------------

    87. Joint Petitioners and TAPS argue that the Final Rule failed to 
discuss the merits of NRECA's alternative approach, which was to allow 
only demand response resources to bid prices higher than the current 
bid caps during emergencies. Under this approach, Joint Petitioners 
state that demand response resources would be paid the highest clearing 
price bid by demand response resources; however, generators would 
receive the highest capped price bid by generating resources needed to 
clear the market.\123\ TAPS states that this approach would have 
potential benefits for emergencies, with fewer adverse consequences 
than any of the Final Rule's four approaches. Therefore, it asks the 
Commission to address the merits of NRECA's approach and modify the 
regulatory text to accommodate this approach.\124\ Joint Petitioners 
argue that the Commission acted arbitrarily and capriciously in failing 
to consider NRECA's detailed arguments and evidence which they claim 
show that the four shortage pricing approaches will result in unjust 
and unreasonable rates and charges, not the beneficial results that the 
Final Rule anticipates.
---------------------------------------------------------------------------

    \123\ Id. at 49-50 (citing NRECA NOPR Comments at 29).
    \124\ TAPS states that the Final Rule's regulatory text language 
in section 35.28(g)(1)(iv)(A) would preclude an RTO or ISO from 
proposing the NRECA approach or any other beneficial demand response 
program. Thus, it requests the following modifications:
    Commission-approved ISOs and RTOs must modify their market rules 
to allow (1) the market-clearing price during periods of operating 
reserve shortage to reach a level that rebalances supply and demand 
or (2) payments to demand response resources. In either case, the 
rules must [so as to] maintain reliability while providing 
sufficient provisions for mitigating market power.
    TAPS at 48 (citing TAPS NOPR Comments at 3).
---------------------------------------------------------------------------

    88. Joint Petitioners assert that generator resources and demand 
response resources are not similarly situated and, therefore, it is not 
unjust and unreasonable or unduly discriminatory under the FPA to 
compensate them differently. According to Joint Petitioners, during 
generation scarcity, generators already make all of their generation 
resources available to the market; hence, they can take no additional 
actions to balance supply and demand. However, they assert that demand 
response resources are able to take further action to balance supply 
and demand by reducing their demand.\125\ Therefore, the comparability 
principle does not require that the same price to be paid to both 
generators and demand responders to bring supply and demand into 
balance.
---------------------------------------------------------------------------

    \125\ Joint Petitioners at 42.
---------------------------------------------------------------------------

    89. Joint Petitioners argue that the Commission failed to address 
APPA's proposal for eight additional criteria intended to better 
protect consumers from the exercise of market power and unjust and 
unreasonable rates.\126\ They also contend that the Commission failed 
to address NRECA's request that the Commission require RTOs and ISOs to 
quantify the benefits of proposed changes and to demonstrate that they 
exceed the costs, which should include the expected costs of market 
power.\127\
---------------------------------------------------------------------------

    \126\ Id. at 51-52.
    \127\ Id. at 53.
---------------------------------------------------------------------------

    90. Similarly, TAPS asserts that the Final Rule ignored its NOPR 
comments for additional criteria to strengthen the factual showing 
required for RTOs and ISOs in their shortage pricing compliance 
filings. TAPS believes that its proposed criteria would address market 
power and provide accountability.\128\
---------------------------------------------------------------------------

    \128\ Id. at 49.

---------------------------------------------------------------------------

[[Page 37789]]

    91. TAPS also seeks rehearing of the Commission's rejection of 
Pacific Gas & Electric Corporation's (PG&E) proposed additional 
criteria, especially with regard to the cost effectiveness of the Final 
Rule's shortage pricing requirements. TAPS argues that the Commission 
did not provide a reasoned basis for rejecting PG&E's proposed 
criteria. It adds that the Commission's failure to require any 
accountability for the costs imposed by the Final Rule's shortage 
pricing requirements is contrary to the GAO Report's 
recommendations.\129\
---------------------------------------------------------------------------

    \129\ Id. at 53 (citing United States Government Accountability 
Office, Report to the Committee on Homeland Security and 
Governmental Affairs, U.S. Senate, Electricity Restructuring: FERC 
Could Take Additional Steps to Analyze Regional Transmission 
Organizations' Benefits and Performance (Sept. 2008), available at 
http://www.gao.gov/new.items/d08987.pdf) (2008 GAO Report)).
---------------------------------------------------------------------------

    92. Joint Petitioners request that the Commission vacate the 
relevant criteria and regulations, and undertake a successor rulemaking 
with a new record to develop demand response pricing policies that meet 
the statutory requirements of the FPA.\130\
---------------------------------------------------------------------------

    \130\ Joint Petitioners at 54.
---------------------------------------------------------------------------

b. Commission Determination
    93. The requests for rehearing do not convince us that the policy 
decisions made in the Final Rule were the result of error. We therefore 
affirm our finding in the Final Rule that existing RTO and ISO market 
rules that do not allow for prices to rise sufficiently during an 
operating reserve shortage to allow supply to meet demand are unjust, 
unreasonable, and may be unduly discriminatory. The shortage pricing 
proposal adopted in the Final Rule is intended to correct this issue 
while providing protection against the exercise of market power. 
Therefore, we deny rehearing on this issue.
i. Shortage Pricing Proposal
    94. Several petitioners state that the Commission lacked evidence 
for establishing shortage pricing requirements. We disagree. Based on 
information gathered from three technical conferences \131\ and 
comments in response to the ANOPR and the NOPR, the Commission found 
that today's RTO and ISO market rules may not produce rates that 
accurately reflect the true value of energy during periods of operating 
reserve shortages. The Commission determined that such inaccurate 
prices during an emergency may harm reliability, inhibit demand 
response, deter new entry of demand response and generation resources, 
and thwart innovation.\132\ Therefore, the Commission concluded that 
RTO or ISO market rules that do not allow for prices to rise 
sufficiently during an operating reserve shortage to allow supply to 
meet demand are unjust, unreasonable, and may be unduly 
discriminatory.\133\
---------------------------------------------------------------------------

    \131\ The Commission held three technical conferences in 2007 to 
gather information and address issues on competition at the 
wholesale level and other related issues. See NOPR, FERC Stats. & 
Regs. ] 32,628 at P 2.
    \132\ Order No. 719, FERC Stats. & Regs. ] 31,281 at P 192; 
NOPR, FERC Stats. & Regs. ] 32,628 at P 107.
    \133\ Order No. 719, FERC Stats. & Regs. ] 31,281 at P 192.
---------------------------------------------------------------------------

    95. We disagree with the arguments that the Final Rule's shortage 
pricing requirement will result in the exercise of market power or lead 
to increased price volatility, or that consumers will not be protected 
from high prices, or that it is a departure from Commission precedent 
because it removes bid and price caps that are in place to mitigate 
market power. As stated in the Final Rule, the Commission is not taking 
any action to remove bid caps or to remove market power mitigation in 
regional markets. Rather, the Commission is requiring each RTO and ISO 
to demonstrate that its market rules accurately reflect the value of 
energy during reserve shortage periods or to propose changes in its 
rules to achieve this objective. Each of the Commission's four 
proposals maintains bid and price caps, but would allow price caps to 
rise during shortage periods provided that the RTO or ISO demonstrates 
that adequate market power mitigation provisions are in place. Each RTO 
or ISO also is free to propose other pricing approaches and associated 
market power mitigation that meet the purposes and criteria described 
in the Final Rule.\134\ The RTOs' and ISOs' compliance filings are 
subject to Commission review and approval. Also, to guard the consumer 
against exploitation by sellers, the Commission required each RTO and 
ISO to adequately address market power issues in the compliance filing 
and for MMUs to provide their views to the Commission on any proposed 
reforms.\135\
---------------------------------------------------------------------------

    \134\ Id. P 195.
    \135\ Id. P 235.
---------------------------------------------------------------------------

    96. With regard to arguments that the Final Rule provided no 
evidence that existing shortage pricing rules are inhibiting investment 
in demand response resources, we note that the issue is not whether 
existing market rules remain workable. As we have explained many times, 
one of the Commission's goals in this proceeding is to eliminate 
barriers to demand response resources' participation in organized 
energy markets. If, as petitioners foresee, higher shortage prices 
result from amending market rules, those prices could be expected to 
attract investment in both demand response technology and generation by 
providing opportunities for a higher return on investment--and the 
entry of demand response over time may lead to lower prices in the long 
run. We are concerned that such investments may not occur under 
existing rules because, as at least one commenter observed in response 
to the NOPR ``existing market rules do not accurately reflect the value 
of energy during periods of shortage and, therefore may deter new entry 
of demand response and generation resources.'' \136\ Also, we do not 
find that it is necessary to develop metrics for measuring demand 
elasticity or for evaluating the impact that volatile prices may have 
on capital deployment decisions, as Industrial Coalitions claim. As 
noted above, the Commission's goal in this proceeding is to eliminate 
barriers to demand response participation in RTO and ISO markets, and 
it is reasonable to expect that higher shortage prices will encourage 
investment in additional generation and demand response resources.
---------------------------------------------------------------------------

    \136\ Id. P 187 (citing PJM Power Providers NOPR Comments at 3).
---------------------------------------------------------------------------

    97. In response to TAPS's statement that a highly inelastic demand 
curve means that consumers cannot protect themselves from high prices, 
the Commission notes first that demand is not necessarily inelastic 
when customers have appropriate notice and prices,\137\ and second that 
even a relatively small amount of demand response in a shortage can 
lower market prices significantly for all customers.
---------------------------------------------------------------------------

    \137\ For example, a critical peak pricing experiment in 
California in 2004 determined that small residential and commercial 
customers are price responsive and will produce significant demand 
reductions. Participants in the California peak pricing experiment 
reduced demand by 13 percent on average and by as much as 27 percent 
when price signals were coupled with automated controls, such as 
controllable thermostats. 2006 FERC Staff Demand Response Assessment 
at 13.
---------------------------------------------------------------------------

    98. Several petitioners assert that customers are not able to 
respond to prices in real-time and, therefore, demand response 
mechanisms must be in place before changes to mitigation rules are 
considered. We agree with Pennsylvania PUC, Old Dominion, Industrial 
Coalitions, and others that demand response infrastructures remain 
underdeveloped for many regions. Developing mechanisms to allow prices 
to reflect the true value of energy during an emergency should 
encourage development of demand response infrastructure. With improved 
price

[[Page 37790]]

signals, more buyers would find it worthwhile to invest in technologies 
that allow them to respond to prices. As noted in the Final Rule, full 
deployment of advanced meters and complete participation by all load is 
not needed to help cope with operating reserve shortages. Demand 
response programs that currently allow a fraction of the load to 
respond can have a significant positive effect on system reliability 
and help reduce prices for all.
    99. With regard to Old Dominion's request that the Commission 
address each RTO's or ISO's proposal for eliminating barriers to demand 
response before mandating shortage pricing, and Joint Coalitions' 
concern that existing demand response cannot check the exercise of 
market power, we note that the Final Rule requires each RTO and ISO to 
provide evidence regarding the ability of demand resources to mitigate 
market power and how market power will be monitored.\138\ The 
Commission will examine the shortage pricing proposals submitted in 
each RTO's and ISO's compliance filing and will approve the proposals 
only if they meet the criteria established in the Final Rule.
---------------------------------------------------------------------------

    \138\ Order No. 719, FERC Stats. & Regs. ] 31,281 at P 196.
---------------------------------------------------------------------------

    100. Finally, with regard to TAPS's request for revision of the 
definition of operating reserve shortage in the regulatory text, we 
decline to revise the regulatory text because we do not believe the 
definition is either inadequate or inconsistent with the discussion in 
the preamble of the Final Rule. The regulatory text provided a short 
general definition of an operating reserve shortage and the preamble 
declined to provide a detailed specification of when an operating 
reserve shortage exists, stating that the North American Electric 
Reliability Corporation already specifies procedures for determining 
when a system operator is out of compliance with the reliability 
standard and therefore when it has an operating reserve shortage. These 
standards are well known to RTOs and ISOs and their stakeholders.\139\ 
Given that the level of operating reserves required by the reliability 
standards depend on the characteristic of each system and cannot be 
correctly reduced to a single number that applies to every system, the 
Commission found that it would be best not to adopt in these 
regulations a new and separate specification of when an operating 
reserve shortage exists. The Commission found that if it were to 
duplicate the provisions of the reliability standard in this 
rulemaking, it would be cumbersome for reliability organizations to 
improve their specifications of when such a shortage exists without 
also having to seek a change in our regulations. Therefore, we deny 
rehearing of this request.
---------------------------------------------------------------------------

    \139\ Id. P 251.
---------------------------------------------------------------------------

    101. We reject Joint Petitioners' request that we require by rule 
an evidentiary hearing to determine the justness and reasonableness of 
each RTO's and ISO's shortage pricing proposal. We find that at this 
stage it is premature to establish a requirement for such evidentiary 
hearings. All concerned parties have now had an opportunity to comment 
on the RTOs' and ISOs' compliance filings, and the Commission will 
determine on a case-by-case basis whether evidentiary hearings are 
warranted. We reject Joint Petitioners' request to vacate the 
rulemaking provisions on shortage pricing and institute a new 
rulemaking. We find that the Joint Petitioners have not provided any 
new arguments or evidence that would warrant such action.
ii. Four Shortage Pricing Approaches and Criteria Requirements
    102. Several petitioners find fault with the four shortage pricing 
approaches, stating that they fail to protect customers from the 
exercise of market power and lead to other adverse consequences. We 
find that these petitioners have not raised any new arguments on 
rehearing and deny rehearing on this issue.
    103. We emphasize that the Final Rule did not establish the 
shortage rates to be implemented, or even one particular approach to 
shortage pricing. In particular, the Final Rule did not require the 
first approach of raising bid caps, as some petitioners suggest. 
Rather, it required RTOs and ISOs to make a compliance filing, in 
consultation with their customers and other stakeholders, to establish 
an approach to shortage pricing during periods of operating reserve 
shortage or to show that their existing rules satisfy the Final Rule. 
Further, this compliance filing must make several of the demonstrations 
that petitioners contend are lacking in the Final Rule, such as 
ensuring that market power is mitigated and gaming behavior is deterred 
during periods of operating reserve shortages.\140\ Only after such 
filings have been submitted will the Commission determine, case by case 
for each RTO or ISO, if the existing or proposed pricing rules--which 
could include, but are not required to include, raising bid caps--are 
just and reasonable and sufficient to meet the stated goals of this 
proceeding.\141\ The Commission provided a menu of options through the 
four approaches or any other approach that the RTO or ISO deems 
appropriate. Therefore, an RTO or ISO and its stakeholders are free to 
consider approaches other than the four approaches in the Final Rule 
and propose it to the Commission, provided it satisfies the 
requirements in the Final Rule.
---------------------------------------------------------------------------

    \140\ Id. P 247.
    \141\ Id. P 235.
---------------------------------------------------------------------------

    104. With regard to NRECA's alternative approach for pricing 
reform, we reiterate that the Final Rule did not mandate any specific 
approach to shortage pricing. It presented four approaches to shortage 
pricing, but left the RTOs and ISOs with freedom to develop the 
solutions that best suit their regions.\142\ RTOs and ISOs may consider 
NRECA's alternative proposal, or others not presented in the Final 
Rule, as they see fit.\143\ We therefore disagree with Joint 
Petitioners' contention that the Commission erred in failing to require 
NRECA's proposal and in overlooking evidence that the four approaches 
will result in unreasonable rates and charges. Such analysis is most 
appropriately left to the compliance process, where the Commission can 
examine how the RTO's or ISO's chosen approach or approaches to 
shortage prices will work in its region.
---------------------------------------------------------------------------

    \142\ Order No. 719, FERC Stats. & Regs. ] 31,281 at P 194-95.
    \143\ Id. P 195.
---------------------------------------------------------------------------

    105. Joint Petitioners and TAPS argue that the Final Rule ignored 
some proposals for additional criteria aimed at addressing their 
concerns, including market power and accountability. While the Final 
Rule did not specifically address the merits of each additional 
criterion proposed, the Commission considered them in adopting and 
revising the six criteria from the NOPR.\144\ The Commission found that 
many of the suggestions for additional criteria are already implicitly 
or explicitly addressed in the adopted criteria. For example, the 
Commission noted that the criteria already included an analysis of 
market power mitigation and, therefore, did not see the need to adopt 
an additional criterion to protect consumers against market power.\145\ 
We therefore continue to find that the criteria adopted in the Final 
Rule are sufficient to provide a general guideline for designing a 
shortage pricing approach that addresses market power, accountability, 
gaming behavior, and

[[Page 37791]]

other issues raised by petitioners. Therefore, we disagree that the 
Final Rule ignored proposals for additional criteria.
---------------------------------------------------------------------------

    \144\ Order No. 719, FERC Stats. & Regs. ] 31,281 at P 239, 249-
50.
    \145\ Id. P 249.
---------------------------------------------------------------------------

    106. Similarly, we see no basis to reconsider PG&E's proposed 
criteria which were: (1) A demonstration that any proposed market rule 
changes are cost effective; (2) an evaluation that the operating 
reserve shortage pricing mechanism is adequately coordinated with other 
key market mechanisms; and (3) an assessment of the readiness of the 
demand response programs that will be called on to reduce the number 
and severity of shortage pricing requirements and help to mitigate 
market power.\146\ While each of these is a worthy goal, our intent in 
this proceeding is to establish a set of broad criteria to serve as a 
general guideline for all RTOs and ISOs on designing a shortage pricing 
approach. Nothing will prevent RTOs, ISOs and their stakeholders from 
considering these goals in the process of drafting their compliance 
proposal, and indeed, we encourage them to do so if these items are of 
concern to them. Further, we note that the Final Rule required RTOs and 
ISOs to address market power issues in their compliance filings, and to 
provide ``an adequate factual record demonstrating that provisions 
exist for mitigating market power and deterring gaming behavior * * * 
[, which] could include, but is not limited to, the use of demand 
resources to discipline bidding behavior to competitive levels during 
an operating reserve shortage.'' \147\ Accordingly, we find that the 
Commission did not err in rejecting PG&E's narrower request for a 
readiness assessment.
---------------------------------------------------------------------------

    \146\ Id. P 244.
    \147\ Id. P 196.
---------------------------------------------------------------------------

B. Long-Term Power Contracting in Organized Markets

    107. In the Final Rule, the Commission established a requirement 
that RTOs and ISOs dedicate a portion of their Web sites for market 
participants to post offers to buy and sell electric energy on a long-
term basis. The Commission noted that this requirement was designed to 
improve transparency in the contracting process so as to encourage 
long-term contracting for electric power.\148\ Requests for rehearing 
were timely filed with respect to the need to require development of 
new hedging instruments and to the need for the Commission to address 
the larger structural causes of problems with the long-term contracting 
market.
---------------------------------------------------------------------------

    \148\ Id. P 307.
---------------------------------------------------------------------------

1. Hedging Instruments
    108. Several commenters argued in their NOPR comments that the 
Commission should address the lack of certain financial hedging 
instruments in organized markets. These commenters argued that 
providing such hedging instruments would reduce the risk of marginal 
losses and encourage long-term contracting. In the Final Rule, however, 
the Commission declined to take any action on hedging instruments.\149\
---------------------------------------------------------------------------

    \149\ Id.
---------------------------------------------------------------------------

a. Request for Rehearing
    109. SMUD argues in its request for rehearing that exposure to 
marginal losses, like exposure to congestion charges, poses a 
substantial risk to market participants interested in long-term 
bilateral contracts. The absence of a hedging mechanism for marginal 
losses, SMUD states, is a significant risk factor in long-term 
contracting. SMUD notes that the Commission encouraged, but did not 
require, RTOs and ISOs to develop such hedging mechanisms. It argues 
that this encouragement is not sufficient, and that the Commission 
should address on rehearing the need for a marginal loss hedging 
mechanism or explain why one is not needed.\150\
---------------------------------------------------------------------------

    \150\ SMUD at 7.
---------------------------------------------------------------------------

b. Commission Determination
    110. The Commission addressed previously SMUD's request for a 
requirement for a marginal loss hedging instrument in Order No. 
681.\151\ The Commission found that EPAct 2005 does not require a 
marginal loss hedge, and that due to the nature of marginal losses, it 
is more difficult to design a hedge for marginal losses than it is to 
create one for congestion costs.\152\ The Commission again addressed 
SMUD's request in the order conditionally approving revisions to 
CAISO's Market Redesign and Technology Upgrade Tariff provisions 
involving congestion revenue rights.\153\ In that order, the Commission 
found that it would be unreasonable to direct the CAISO to provide a 
mechanism that is not required by EPAct 2005, and that does not yet 
exist in workable form elsewhere.\154\ In light of the Commission's 
extensive, and recent, consideration of this issue, and SMUD's failure 
to propose new arguments here including evidence of a relevant change 
in circumstances, or a workable hedge for marginal losses, we are not 
persuaded to grant rehearing. We continue to encourage RTOs and ISOs to 
explore methods by which they can assist load-serving entities and 
others to obtain hedges for marginal losses.\155\
---------------------------------------------------------------------------

    \151\ 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).
    \152\ Order No. 681-A, 117 FERC ] 61,201 at P 105.
    \153\ Cal. Indep. Sys. Operator Corp., 120 FERC ] 61,023, at P 
229 (2007), reh'g denied, 124 FERC ] 61,094 (2008).
    \154\ Id.
    \155\ Order No. 681-A, 117 FERC ] 61,201 at P 106.
---------------------------------------------------------------------------

2. Structural Issues
    111. The Commission received comments prior to the Final Rule 
arguing that the structure of organized markets was flawed, and 
advocating that the Commission needed to institute a broader 
investigation of organized markets to protect consumers. In the Final 
Rule, the Commission stated that many of the broader issues commenters 
raised were beyond the scope of the proceeding, and would require 
further development to be ripe for inclusion in a proceeding. The 
Commission noted that these issues had been the subject of a technical 
conference held to discuss the proposals of American Forest & Paper 
Association and Portland Cement Association.\156\ The Commission stated 
that it continues to review the information it received at the 
technical conference for possible action.
---------------------------------------------------------------------------

    \156\ Supplemental Notice of Technical Conference, Capacity 
Markets in Regions with Organized Electric Markets, Docket No. AD08-
4-000 (April 25, 2008).
---------------------------------------------------------------------------

a. Request for Rehearing
    112. APPA-CMUA argue that the Commission erroneously failed to 
expand the scope of this proceeding to investigate the issue of whether 
RTO markets are producing just and reasonable rates. They argue that 
sections 205 and 206 of the Federal Power Act require the Commission to 
act when it finds evidence of unjust and unreasonable rates.\157\
---------------------------------------------------------------------------

    \157\ APPA-CMUA at 3.
---------------------------------------------------------------------------

    113. APPA-CMUA note that they, along with other consumer entities, 
presented evidence to the Commission in this proceeding regarding 
failures in centralized power markets. These failures include fewer and 
higher-priced long-term power supply options, the shifting of financial 
risks to customers, and impediments to construction of new generation 
resources. APPA-CMUA argue that the Commission did not consider this 
evidence, but instead found that the scope of the proceeding was 
limited to four ``discrete'' areas. APPA filed extensive comments 
asking the Commission to expand the scope of the proceeding, which it 
argues were ignored. APPA-CMUA note that APPA also filed comments 
following the

[[Page 37792]]

technical conference held on May 7, 2008, but that there has been no 
further activity in that docket.\158\
---------------------------------------------------------------------------

    \158\ Id. at 21.
---------------------------------------------------------------------------

    114. APPA-CMUA argue that the Commission's failure to act violates 
its obligations under the Federal Power Act, and under administrative 
law generally. They argue that the Commission has a duty to address 
unjust and unreasonable rates that extends to systemic, marketwide 
problems.\159\ They also argue that the Commission has a legal 
obligation to investigate if evidence is presented to it that unjust 
and unreasonable rates are being charged; if the investigation reveals 
unjust and unreasonable rates, contracts or practices, the Commission 
must take remedial action.\160\ APPA-CMUA cite to the recent United 
States Supreme Court case in Massachusetts v. EPA, in which the Court 
found that the EPA possessed not only the statutory authority, but also 
the responsibility, to regulate greenhouse gas emissions.\161\ APPA-
CMUA state that the Court found that the EPA's refusal to institute a 
rulemaking to regulate greenhouse gases contradicted the clear terms of 
the Clean Air Act, and was arbitrary and capricious. Similarly, they 
argue, the Commission in this proceeding has not only failed to act, it 
has failed even to look at the many comments, statements, studies and 
affidavits in the docket alleging unjust and unreasonable rates.\162\
---------------------------------------------------------------------------

    \159\ Id. at 25 (citing Transmission Access Policy Study Group 
v. FERC, 225 F.3d 667, 686-87 (D.C. Cir. 2000); Associated Gas 
Distribs. v. FERC, 824 F.2d 981, 1008 (D.C. Cir. 1987)).
    \160\ Id. at 26 (citing Order No. 2000, FERC Stats & Regs at 
31,043 n.163).
    \161\ 549 U.S. 497 (2008).
    \162\ APPA-CMUA at 28.
---------------------------------------------------------------------------

    115. APPA-CMUA also argue that the Commission erred in finding that 
RTO and ISO markets provide demonstrable benefits to customers. They 
argue that the Commission cites no support for the finding, and point 
to evidence in the record from wholesale customers and others calling 
into question the existence of such benefits. APPA-CMUA cite to the 
2008 GAO Report, which they argue found that the Commission has not 
done the analyses necessary to support its assertions that RTO markets 
provide demonstrable benefits to wholesale customers and 
consumers.\163\
---------------------------------------------------------------------------

    \163\ Id. at 32 (citing 2008 GAO Report). See supra note 129.
---------------------------------------------------------------------------

    116. Finally, APPA-CMUA argue that the Commission failed to address 
the structural causes underlying the lack of long-term contracting in 
RTO and ISO regions. They note that the Commission received several 
comments relating to the over-reliance on spot markets and lack of 
long-term contracts caused by the structure of markets within the RTO 
system. However, the Commission declined to order any of the broader 
measures commenters suggested. APPA-CMUA argue that the Commission's 
statement that these structural issues were beyond the scope of the 
proceeding was a non sequitur, since the Commission itself had set the 
scope of the proceeding. They note the Commission's apparent belief 
that there is no fundamental problem with long-term contracts, that 
contracts are merely available at higher prices than in the past. 
However APPA-CMUA argue that the Commission failed to consider the 
results of the Synapse Study it presented, which found that there were 
structural reasons beyond changes in fuel supply that drove buyer 
reluctance to enter into long-term contracts. They also argue that the 
current turmoil in the credit markets should cause the Commission to 
reconsider its decision, as it is going to be difficult to finance new 
generation facilities in the future without long-term contracts to 
support them.\164\ APPA-CMUA conclude that the Commission effectively 
ignored many comments, statements, studies and affidavits that indicate 
that many load-side interests believe that RTOs are charging unjust and 
unreasonable rates, and that those comments never received the due 
process that the FPA requires.
---------------------------------------------------------------------------

    \164\ Id. at 34-36.
---------------------------------------------------------------------------

b. Commission Determination
    117. We find that the Commission did not violate the standards of 
due process or shirk its duty under the FPA in confining the scope of 
this proceeding to four specific areas of reform related to the 
operation of competitive wholesale markets. We deny rehearing on the 
issue of whether the Commission failed to justify its decision not to 
expand the scope of this proceeding.
    118. APPA-CMUA's argument that the Commission has a legal duty to 
expand this rulemaking proceeding to address whether and how to 
systemically revise organized markets is mistaken. As the Supreme Court 
has ruled, an agency has broad discretion to choose how best to marshal 
its limited resources and personnel to carry out its delegated 
responsibilities.\165\ While APPA-CMUA cite to the Supreme Court's 
decision in Massachusetts v. EPA, this decision was based on a specific 
statute related to EPA action on greenhouse gases, and did not overturn 
the general rule that agencies have discretion over how to act to carry 
out their responsibilities.\166\ The Supreme Court found that the EPA 
had refused to act on a specific statutory requirement to regulate 
greenhouse gases, and that its refusal was not warranted by the 
statutory text.\167\ By contrast, the Commission has not refused its 
responsibility to ensure just and reasonable rates here. Indeed, FPA 
sections 205 and 206 form the legal basis for this proceeding.\168\
---------------------------------------------------------------------------

    \165\ See Chevron U.S.A. Inc. v. NRDC, 467 U.S. 837, 842-845 
(1984).
    \166\ See Massachusetts v. EPA, 549 U.S. at 527.
    \167\ Id. at 530.
    \168\ See Order No. 719, FERC Stats. & Regs. ] 31,281 at P 13.
---------------------------------------------------------------------------

    119. As the Commission stated in the Final Rule, this proceeding 
was not intended to fundamentally redesign organized markets; rather, 
the reforms were intended to be incremental improvements to the ongoing 
operation of organized markets without undoing or upsetting the 
significant efforts that have already been made in providing 
demonstrable benefits to wholesale customers.\169\ The Commission 
focused on four discrete areas with the goal of improving competition 
in organized wholesale electric markets. This determination was based 
in part upon a desire to create a manageable forum for discussing and 
implementing those revisions to organized wholesale markets that could 
be implemented relatively soon. Expanding the scope of the proceeding 
to encompass the wholesale revision of organized RTO or ISO markets 
would delay the immediate and necessary market reforms ordered in the 
Final Rule.
---------------------------------------------------------------------------

    \169\ Id. P 2; NOPR, FERC Stats. & Regs. ] 32,628 at P 4, 282.
---------------------------------------------------------------------------

    120. We disagree with APPA-CMUA's argument that the Commission has 
denied it due process by declining to investigate wholesale market 
operations in general on the basis that doing so is outside the scope 
of the proceeding that the Commission itself set. If the Commission was 
obligated to frame every investigation to satisfy commenters' requests, 
individual commenters would have the power to delay or derail nascent 
market rules with which they disagreed merely by arguing that the scope 
of the proceeding was too narrow or too broad. The Commission's goal 
here is to make improvements to four areas of wholesale market 
operations.
    121. The fact that this proceeding is limited to the four topics 
addressed above does not indicate that the Commission refuses to act in 
other areas to ensure just and reasonable rates. For example, the 
Commission has acted on

[[Page 37793]]

a generic basis and with regard to specific regional markets to, among 
other things, address transmission planning reforms, interconnection 
rules, and reform of capacity markets, all areas that improve long-term 
contracting and organized markets as a whole.\170\ The Commission 
continues to review other proposals for reforms, including additional 
reforms to remove barriers to demand response and reform organized 
markets.\171\ We have received a wealth of information on all sides of 
these issues, from comments in this proceeding and others, testimony at 
technical conferences, and other reports such as the recent GAO Report 
discussed above. Contrary to the claims of APPA-CMUA, the Commission 
considered all of the comments, statements, studies and affidavits 
received in this docket when determining the scope and outcome of this 
proceeding.\172\ We appreciate the time and effort put into those 
submissions, and we remain receptive to the avenues of reform proposed 
therein.
---------------------------------------------------------------------------

    \170\ See Order No. 719, FERC Stats. & Regs. ] 31,281 at P 280.
    \171\ For instance, the Commission recently held a technical 
conference on credit issues affecting the electric power industry. 
Technical Conference on Credit and Capital Issues Affecting the 
Electricity Power Industry, Docket No. AD09-2-000 (Jan. 13, 2009).
    \172\ NOPR, FERC Stats. & Regs. ] 32,628 at P 16-25.
---------------------------------------------------------------------------

    122. The Commission's policy continues to be to promote competition 
in wholesale electric power markets. This policy is in keeping with 
Commission practice and was ratified by Congress in EPAct 2005.\173\ We 
always welcome suggestions for concrete actions that could be taken to 
improve competition in wholesale markets.
---------------------------------------------------------------------------

    \173\ Public Law 109-58, 119 Stat. 594.
---------------------------------------------------------------------------

C. Market-Monitoring Policies

    123. The Commission ordered a number of reforms in the Final Rule 
designed to enhance the market monitoring function and thereby to 
improve the performance and transparency of the organized markets. 
These reforms centered upon two areas: ensuring the independence of 
market monitoring units (MMUs) and expanding their information sharing 
function.
    124. To increase the independence of MMUs, the Final Rule directed 
that MMUs in most instances report directly to the RTO or ISO board of 
directors or to a committee of the board, rather than to management; 
directed tariff inclusion of a duty on the part of the RTO or ISO to 
provide the MMU with access to the data, resources and personnel needed 
to perform its duties; required the RTO or ISO to set out the expanded 
functions of the MMU in its tariff; removed the MMU from tariff 
administration and modified MMU market mitigation functions; prescribed 
protocols for the referral to Commission staff by the MMU both of 
market design flaws and of suspected wrongdoing; and required the RTO 
or ISO to adopt ethics standards for the MMUs and MMU employees.\174\
---------------------------------------------------------------------------

    \174\ Order No. 719, FERC Stats. & Regs. ] 31,281 at P 317 et 
seq.
---------------------------------------------------------------------------

    125. Within the area of information sharing, the Final Rule 
required the MMU to make quarterly reports in addition to the annual 
state of the market report, to expand the recipients for the reports, 
and to hold regular telephone conferences among the MMU and Commission 
staff, RTO or ISO staff, interested State commissions, State attorneys 
general and market participants; established procedures for the MMU to 
share information with State commissions; and reduced the lag time for 
the release of offer and bid data by the RTO or ISO.\175\
---------------------------------------------------------------------------

    \175\ Id. P 395 et seq.
---------------------------------------------------------------------------

    126. Requests for rehearing or clarification were timely filed with 
respect to the following issues: MMU involvement in market mitigation, 
the relationship between the internal and external MMU, State access to 
MMU information, release of offer and bid data, and the scope of the 
ethics provisions. In addition, the Commission on its own motion 
clarifies certain duties of the MMU with respect to the referral of 
market design flaws. These are discussed below.
1. Market Mitigation
    127. In the Final Rule, the Commission modified the proposal made 
in the NOPR that MMUs should be removed from market mitigation. That 
proposal had been designed to remove the MMU from subordination to the 
RTO or ISO, and to eliminate the conflict of interest inherent in an 
MMU opining on the health of the market while itself influencing the 
market by conducting mitigation. However, a number of commenters 
objected that there might be a greater conflict of interest in having 
the RTO or ISO administer mitigation, as it has a vested interest in 
accommodating its market participants. Commenters raised a number of 
other objections, including the arguments that the MMU is better 
equipped than the RTO or ISO to detect the need for mitigation, and 
that removing the MMU from mitigation would distance it from the market 
insights it needs for its monitoring function.
    128. In order to preserve the advantages of allowing the MMU to 
perform mitigation, while avoiding entangling it in a conflict of 
interest, the Final Rule struck a balance between the extremes of 
removing the MMU entirely from mitigation and allowing unfettered MMU 
mitigation. It did this in part by providing that an RTO or ISO with a 
hybrid MMU structure \176\ may permit its internal MMU to conduct 
mitigation, so long as its external MMU is assigned the task of 
monitoring the quality and appropriateness of that mitigation. In 
addition, the Final Rule provided that if the RTO or ISO does not have 
a hybrid structure, it may still allow its MMU to perform retrospective 
mitigation, while relegating prospective mitigation to itself. The 
Final Rule further provided that the MMU could provide the inputs 
required by the RTO or ISO for prospective mitigation, including the 
determination of reference levels, the identification of system 
constraints, calculation of costs, and the like.
---------------------------------------------------------------------------

    \176\ A hybrid MMU structure is one with both an internal and an 
external market monitor. An internal market monitor is one that is 
composed of RTO or ISO employees, an external market monitor is an 
independent entity that conducts market monitoring for the RTO or 
ISO pursuant to a contract.
---------------------------------------------------------------------------

a. Requests for Rehearing
    129. Old Dominion objects to the removal of prospective mitigation 
from non-hybrid MMUs, contending that the Commission failed to 
demonstrate a conflict of interest on the part of MMUs while ignoring 
what Old Dominion sees as a conflict of interest arising from the RTOs 
conducting mitigation on what are, in effect, their own customers.\177\
---------------------------------------------------------------------------

    \177\ Old Dominion at 6-7.
---------------------------------------------------------------------------

    130. Pennsylvania PUC argues that prospective mitigation should not 
be limited to RTOs and ISOs with hybrid MMUs.\178\ It contends that 
mitigation is performed according to objective tariff criteria, 
removing the element of discretion, and argues that the record does not 
establish a need for placing limitations on the performance of 
mitigation by MMUs.\179\
---------------------------------------------------------------------------

    \178\ Pennsylvania PUC at 5-6.
    \179\ Id. at 3.
---------------------------------------------------------------------------

    131. Industrial Coalitions assert that the Commission should not 
have removed tariff administration and mitigation from the duties of 
the MMU, arguing that although the Commission intended to strengthen 
market monitoring, it achieved the opposite effect. They advance the 
opinion that RTOs and ISOs have demonstrated a

[[Page 37794]]

preference for unmitigated outcomes, and therefore should not be given 
total responsibility for identifying and rectifying abuses of market 
power.\180\
---------------------------------------------------------------------------

    \180\ Industrial Coalitions at 12-14.
---------------------------------------------------------------------------

    132. The Ohio PUC and Wisconsin PSC object to what they see as the 
internal MMU within a hybrid MMU structure having greater mitigation 
authority than an external MMU.\181\ The Ohio PUC opines that some 
(internal) MMUs will not have the necessary tools to accomplish their 
job function, which will limit their ability to impose prospective 
mitigation.\182\
---------------------------------------------------------------------------

    \181\ Ohio PUC at 14-15; Wisconsin PSC at 2-3.
    \182\ Ohio PUC at 15.
---------------------------------------------------------------------------

b. Commission Determination
    133. The Commission affirms the determination made in the Final 
Rule as to MMU involvement in mitigation. The arguments raised by 
petitioners were extensively discussed in comments made during the 
rulemaking process, and were taken into account by the Commission in 
reaching its resolution of the issue. The MMU's conflict of interest in 
conducting mitigation, which one petitioner contends has not been 
demonstrated, is inherent in the nature of the MMU's duties: inasmuch 
as the MMU must opine on the quality of its own mitigation when it 
reports on the health and state of the markets, it cannot be expected 
to be entirely objective. Conflict of interest concerns do not 
necessarily rely on historical instances of abuse, but rather on the 
existence of the conflict itself and on the well-known tendency of 
human nature to see one's own actions in a favorable light. 
Furthermore, contrary to that same petitioner's assertion, the 
Commission did take into account the argument that RTOs and ISOs have 
conflicts of their own in conducting mitigation. That consideration 
was, in fact, part of the basis for permitting a substantial degree of 
mitigation to be performed by the MMUs, both internal and 
external.\183\
---------------------------------------------------------------------------

    \183\ Order No. 719, FERC Stats. & Regs. ] 31,281 at P 370-79.
---------------------------------------------------------------------------

    134. Pennsylvania PUC claims that mitigation is non-discretionary, 
and concludes there is no danger of a conflict of interest influencing 
the MMU in conducting mitigation.\184\ The Commission is of the view 
that the more objective the criteria for mitigation become, the better 
and fairer their application will be. However, we realize that there is 
still a degree of judgment involved in determining whether mitigation 
is appropriate. If this were not so, mitigation could be entirely 
automatic, which is not the case. Therefore, conflicts of interest must 
still be a part of the Commission's consideration in fashioning its 
rules.
---------------------------------------------------------------------------

    \184\ Pennsylvania PUC at 3.
---------------------------------------------------------------------------

    135. The assertion of Industrial Coalitions that RTOs and ISOs have 
demonstrated a preference for unmitigated outcomes has not been 
substantiated with record evidence. Other factors can have the opposite 
effect on an RTO's or ISO's decision to mitigate, such as achieving 
price moderation, ensuring the orderly and fair administration of the 
markets, and avoiding MMU referrals to Commission staff due to lax 
administration. In this regard it is important to observe that any 
mitigation performed by the RTO or ISO will be monitored by the MMU, 
and, if the RTO or ISO is not performing its job properly, it will be 
the duty of the MMU to refer the conduct to Commission staff.
    136. Ohio PUC and Wisconsin PSC assume that in an RTO or ISO with a 
hybrid MMU, the internal MMU has been given more authority in the 
mitigation area than the external MMU. However, the Final Rule's 
mitigation provisions provide that the external MMU in a hybrid MMU 
structure must independently evaluate the performance of the internal 
MMU, if the latter conducts mitigation. Thus, the external MMU arguably 
has more authority in the mitigation area than the internal MMU, rather 
than less.
    137. For all the foregoing reasons, the Commission concludes that 
its resolution of the mitigation and tariff administration issues 
raised in the NOPR struck the correct balance between unfettered MMU 
mitigation and no mitigation by the MMU. Therefore, we affirm the Final 
Rule in this regard and decline to grant rehearing on the issue of MMU 
involvement in market mitigation.
2. Relationship Between Internal and External MMU
    138. The Final Rule did not express a preference for a particular 
market monitoring structure, whether internal, external, or hybrid. The 
Commission observed that in light of regional variances and preferences 
in this regard, each RTO and ISO should decide for itself its own MMU 
structural relationship. However, the Final Rule did make certain 
distinctions, depending on the particular MMU structure, as to various 
duties and responsibilities, including reporting to the board of 
directors and conducting market mitigation.\185\
---------------------------------------------------------------------------

    \185\ Order No. 719, FERC Stats. & Regs. ] 31,281 at P 374.
---------------------------------------------------------------------------

a. Requests for Rehearing
    139. Ohio PUC questions the efficacy of a hybrid MMU, and proposes 
that an external market monitor's evaluations and recommendations 
should prevail over those of the internal MMU. It proposes that 
mitigation authority not be vested in the internal MMU, presumably 
because it believes that the internal MMU lacks independence.\186\ Ohio 
PUC also suggests that the responsibilities for data collection, 
analysis, and all market mitigation and referrals should take place at 
the external MMU level.\187\ It argues that RTOs and ISOs should 
identify in their tariffs all MMU functions that are essential to the 
effective operation of the MMU, and delegate them to the external or 
independent MMU.\188\ Ohio PUC argues that the Final Rule results in a 
dysfunctional MMU hierarchy that will make the existing MMU subordinate 
to any new internal MMU and the RTO or ISO.\189\
---------------------------------------------------------------------------

    \186\ Ohio PUC at 13.
    \187\ Id. at 13-16.
    \188\ Id. at 16-17.
    \189\ Id. at 14. We assume here that ``existing MMU'' means an 
external MMU.
---------------------------------------------------------------------------

    140. Wisconsin PSC supports in their entirety the requests of Ohio 
PUC. It asserts that the Commission erred in supposedly vesting more 
authority in the internal MMU in a hybrid structure than in the 
external MMU, and in failing to clarify that all MMU rules and 
enforcement standards identified in the RTO or ISO tariff be entrusted 
to the external MMU.\190\
---------------------------------------------------------------------------

    \190\ Wisconsin PSC at 2-3.
---------------------------------------------------------------------------

b. Commission Determination
    141. The proposals by petitioners favoring an external MMU appear 
to be predicated on the notion that an internal MMU necessarily lacks 
independence. However, as we observed in the Final Rule, we have not 
detected any deficiency in performance by internal MMUs that is 
attributable to their structure.\191\ Furthermore, the proposition that 
internal MMUs lack independence ignores the very reforms directed in 
the Final Rule, one of which provides that an internal MMU that is not 
part of a hybrid structure must report to the board of directors or to 
a committee of the board, rather than to management. An internal MMU 
within a hybrid structure may report to management, but only if it does 
not perform any of the three core MMU functions, those being 
identifying ineffective market rules, reviewing the performance of the 
markets, and making

[[Page 37795]]

referrals to the Commission. This reform was instituted precisely to 
bolster the independence of the MMU performing the core MMU functions.
---------------------------------------------------------------------------

    \191\ Order No. 719, FERC Stats. & Regs. ] 31,281 at P 327.
---------------------------------------------------------------------------

    142. In addition, in a hybrid MMU structure, the internal MMU may 
conduct market mitigation only if the external MMU is assigned the 
responsibility and given the tools to monitor the quality and 
appropriateness of that mitigation. Thus, the external MMU can 
determine whether mitigation is being adequately performed and, if any 
deficiencies persist, refer the situation to the Commission. 
Consequently, the Commission disagrees that a hybrid MMU, with the 
internal MMU conducting mitigation, will be inferior in performance and 
independence to an external MMU.
    143. The Commission also disagrees with Wisconsin PSC's contention 
that the internal MMU in a hybrid structure is vested with more 
authority than the external MMU. As noted above, mitigation may be 
assigned to the internal MMU within a hybrid structure only if the 
external MMU is given the tools and responsibility to monitor it, thus 
arguably giving the external MMU greater authority than the internal 
MMU. As to other market monitoring duties, these are to be allocated 
between an internal and external MMU (in a hybrid structure) by the RTO 
or ISO, with stakeholder approval. Therefore, if petitioners desire 
that the external MMU should be assigned more of the core MMU 
functions, they should raise those concerns in the stakeholder process. 
But whatever allocation results from such process, the Final Rule 
provides for checks and balances to ensure oversight over the internal 
MMU's performance, whether by the external MMU or by the board of 
directors. For all these reasons, we decline to grant the requests for 
rehearing on the issue of the relationship between external and 
internal MMUs.
3. State Access to MMU Information
    144. One of the two principal goals of the Final Rule's MMU reforms 
was to expand the content and dissemination of MMU information. One 
such expansion consists of providing a means by which State commissions 
can request tailored information from the MMUs. The Commission placed 
certain restrictions on this right, such as limiting them to general 
market trends and information, and prohibiting them from being used for 
State enforcement purposes.\192\ This was done so that the MMUs would 
not be overwhelmed by such requests at the expense of doing their 
primary job, and to preserve confidentiality where warranted. Because 
of confidentiality concerns, and also to encourage cooperation by both 
existing and potential subjects of investigations, the Commission 
declined to change its policy providing that MMU referrals to the 
Commission remain confidential.
---------------------------------------------------------------------------

    \192\ Id. P 446-59.
---------------------------------------------------------------------------

a. Requests for Rehearing
    145. Illinois Commerce Commission argues that tailored requests for 
information to the MMU by State commissions should not be restricted to 
general market trends and information, and further contends that there 
is no evidence that other requests would be time consuming and 
burdensome.\193\ Illinois Commerce Commission also argues that the 
Commission should not restrict the dissemination of raw data, or forbid 
State commissions from obtaining information from MMUs for State 
enforcement activities, as this may conflict with Illinois Commerce 
Commission's ability under existing tariffs to request MMU information 
from Midwest ISO or PJM.\194\ Lastly, Illinois Commerce Commission 
proposes that State commissions be informed when an MMU refers a matter 
concerning market conduct to the Commission. Illinois Commerce 
Commission argues that there would be no disincentive to entities to 
self-report if the Commission did so, and contends that State 
commissions have a proven track record of properly handling 
confidential information.\195\ Minnesota PUC supports the Illinois 
Commerce Commission's requests in their entirety.\196\
---------------------------------------------------------------------------

    \193\ Illinois Commerce Commission at 4-5.
    \194\ Id.
    \195\ Id. at 2-4.
    \196\ Minnesota PUC at 1.
---------------------------------------------------------------------------

b. Commission Determination
    146. Contrary to the assertions in the requests for rehearing, the 
new provision granting State commissions the right to make tailored 
requests for information broadens their access to MMU data, rather than 
restricting it. Objections of the type expressed by Illinois Commerce 
Commission were addressed in the Final Rule and rejected.\197\ While 
the information sought in tailored requests for information should 
relate to general market trends and the performance of the wholesale 
market, the Commission pointed out that the type of information to be 
provided by the MMU may vary from region to region, and is governed 
principally by the workload such requests impose on the MMU. Therefore, 
as discussed in the Final Rule, unless the information violates 
confidentiality restrictions regarding commercially sensitive material, 
is designed to aid State enforcement actions, or impinges on the 
confidentiality rules of the Commission with regard to referrals, it 
may be produced, so long as it does not interfere with the MMU's 
ability to carry out its core functions. Subject to these limitations, 
granting or refusing such requests will be at the MMU's discretion, 
based on agreements worked out between the RTO or ISO and the States, 
and subject to the confidentiality provisions in the RTO's or ISO's 
tariff and to the Commission's confidentiality restrictions.\198\
---------------------------------------------------------------------------

    \197\ Order No. 719, FERC Stats. & Regs. ] 31,281 at P 446-59.
    \198\ State commissions have the further safety valve of seeking 
otherwise proscribed information by filing a request with the 
Commission. Id. P 458.
---------------------------------------------------------------------------

    147. The Commission respectfully disagrees that the confidentiality 
provisions of the Commission and of the RTOs and ISOs may be 
overridden, simply because a State asserts it is subject to statutory 
or regulatory provisions regulating the release of information coming 
into its possession. The MMUs should not be placed in the position of 
researching the intricacies of State law on the subject, or predicting 
how a court might rule on the disclosure of material once it enters the 
possession of a State commission. While Illinois Commerce Commission 
contends that the confidentiality provisions of the Final Rule ``may 
conflict'' with existing procedures within Midwest ISO and PJM, it 
fails to explain how. Therefore, no factual basis has been presented 
upon which to address this objection.
    148. As to the time-consuming nature of requests made for State 
enforcement purposes, the Commission provided evidence in the record to 
that effect, citing the agency's own long experience with 
investigations.\199\ Furthermore, it would be difficult if not 
impossible to provide information tailored for enforcement purposes 
without breaching confidentiality, as such information would be 
directed toward the activities of individual market participants. As to 
raw data, the Commission did not forbid an MMU from providing raw data 
(properly redacted for confidentiality purposes), but stated that if 
the gathering, organizing, reviewing, and explaining of such data would 
be too consuming, the MMU was not required to provide it.\200\ This is 
a subset of the Commission's

[[Page 37796]]

expressed concern that the MMU not be diverted from its primary MMU 
duties by requests for information and analysis from State actors.
---------------------------------------------------------------------------

    \199\ Id. P 452.
    \200\ Id. P 450.
---------------------------------------------------------------------------

    149. In the Final Rule, the Commission declined to change its long-
standing policy of maintaining the confidentiality of MMU referrals to 
Commission staff. Illinois Commerce Commission contends there would be 
no disincentive to companies to self-report if such referrals were made 
public, because MMU referrals do not occur as a result of self-reports. 
We disagree. If an entity sees that formerly non-public investigations 
are now being made public, it will be discouraged not only from making 
self-reports in the future, but also from cooperating and providing 
data in existing and any future investigations, regardless of the 
origin of that investigation. Furthermore, as pointed out in the Final 
Rule, such disclosure could also injure innocent persons who might be 
erroneously implicated or adversely affected by simply being associated 
with an investigation.\201\
---------------------------------------------------------------------------

    \201\ Id. P 465.
---------------------------------------------------------------------------

    150. For all these reasons, the Commission declines to grant the 
requests for rehearing on the issue of tailored requests for 
information and referrals to the Commission.
4. Offer and Bid Data
    151. In the Final Rule, the Commission shortened the period for 
release of offer and bid data to three months,\202\ while retaining the 
policy of masking the identity of the participants. The Final Rule also 
incorporated flexibility by allowing RTOs and ISOs to propose a shorter 
release time or, if they could demonstrate a danger of collusion, a 
four-month instead of a three-month release, or some alternative 
mechanism if release of a report were otherwise to occur in the same 
season as reflected in the data.
---------------------------------------------------------------------------

    \202\ Most RTOs and ISOs have a six-month release policy.
---------------------------------------------------------------------------

a. Requests for Rehearing or Clarification
    152. TAPS believes that the reduction of the release period to 
three months is a step in the right direction,\203\ but does not think 
it goes far enough. It requests more rapid release of offer and bid 
data, as well as the unmasking of identities. TAPS cites to Australia, 
England and Wales, all of which it states release data on a near-real-
time basis,\204\ and contends that information transparency can play a 
role in the potential mitigation of collusion.\205\ TAPS theorizes that 
the early release of data levels the playing field for smaller market 
participants and enables them to assist with market monitoring,\206\ 
and argues that greater transparency may help expose attempts to 
manipulate the market.\207\
---------------------------------------------------------------------------

    \203\ TAPS at 56.
    \204\ Id. at 57.
    \205\ Id. at 58.
    \206\ Id. at 59.
    \207\ Id. at 60.
---------------------------------------------------------------------------

    153. APPA-CMUA, in a joint filing, support the immediate and full 
disclosure of offer and bid data, the unmasking of the identity of 
bidders, and disclosure of system lambdas.\208\ They cite the Dunn 
Study,\209\ which the Commission discussed in the Final Rule, for the 
propositions that ``the possible benefits'' of posting offer and bid 
data on the day following the operating day ``appear to far exceed'' 
the risks of collusion, and that such release may help expose market 
manipulation.\210\ With respect to the unmasking of identities, APPA-
CMUA argue that although the Commission provided that RTOs and ISOs may 
propose a period when such unmasking might be permitted, this will not 
happen because generators will argue against such disclosure in the 
stakeholder process.\211\ They further argue that requiring the filing 
of system lambdas would allow direct analysis of RTO and ISO real-time 
prices in comparison to the relevant underlying variable generation 
costs.\212\
---------------------------------------------------------------------------

    \208\ ``System lambda'' is defined as the variable cost of the 
last kilowatt produced over a particular hour. APPA-CMUA at 39.
    \209\ Id. at 15-16.
    \210\ Id. at 37-38.
    \211\ Id. at 38.
    \212\ Id. at 39.
---------------------------------------------------------------------------

    154. Illinois Commerce Commission objects to the Commission's 
continuation of the policy of masking the identities of market 
participants, and proposes as an alternative that identities be 
unmasked after a four-month lag, asserting that this time lag would 
eliminate concerns about participant harm and collusive behavior.\213\ 
The Illinois Commerce Commission contends that an entity's bidding 
strategy is an important piece of market information, useful in 
analyzing the reasonableness of market outcomes.\214\
---------------------------------------------------------------------------

    \213\ Illinois Commerce Commission at 8.
    \214\ Id. at 7.
---------------------------------------------------------------------------

    155. Minnesota PUC supports the request for rehearing by the 
Illinois Commerce Commission in its entirety.\215\
---------------------------------------------------------------------------

    \215\ Minnesota PUC at 1.
---------------------------------------------------------------------------

b. Commission Determination
    156. Petitioners' objections on this issue were addressed in the 
Final Rule, and the Commission sees no reason to revisit its 
determination. The Final Rule provided RTOs and ISOs with a good deal 
of flexibility to propose a lag period that would work best for its 
particular situation, and that would meet the desires of its 
stakeholders. Under the Final Rule, RTOs and ISOs, should they desire, 
are free to propose petitioners' preferred lag period of only one 
day.\216\
---------------------------------------------------------------------------

    \216\ Order No. 719, FERC Stats. & Regs. ] 31,281 at P 424.
---------------------------------------------------------------------------

    157. APPA-CMUA contend that generators would object to such a 
proposal, and would be able to sway the stakeholder process against it. 
This argument implicitly suggests, without evidence, that not only 
would the stakeholder process reach a biased and unjust result, but 
that their proposal is the only correct one. It is also quite possible 
that the stakeholder process will result in a balancing of petitioners' 
concerns against those of market participants who may have perfectly 
rational reasons to prefer delaying the release of offer and bid data, 
and to mask identities. For example, one such reason is the fact that 
trading strategies, which is exactly the information sought by 
petitioners, are trade secrets that have considerable value to market 
participants. While the Illinois Commerce Commission may wish to use 
the data for enforcement purposes, other entities may use it to give 
themselves a competitive advantage, or to eliminate the competitive 
advantage of another entity. Since the various stakeholders have 
different concerns and interests, balancing those concerns is more 
suited to exploration and resolution in the stakeholder process than in 
this proceeding, at least in the first instance.\217\
---------------------------------------------------------------------------

    \217\ The fact that ISO-NE proposed reducing the lag time for 
release of offer and bid data from six months to three months is 
evidence of the fact that the stakeholder process is not necessarily 
geared toward less disclosure. See ISO New England Inc. and New 
England Power Pool, 121 FERC ] 61,035 (2007).
---------------------------------------------------------------------------

    158. Likewise, the Final Rule affords flexibility in the area of 
the masking of identities of market participants placing offer and bid 
data, by providing that RTOs and ISOs may propose a period for the 
eventual unmasking of such identities.\218\ Again, this allows for a 
balancing of interests in the stakeholder process. The Commission built 
this flexibility into its determinations in the area of offer and bid 
data both to take into account regional differences, and to

[[Page 37797]]

give the industry a chance to work with the release period mandated in 
the Final Rule before deciding whether to propose an even shorter 
period. Certainly, if an RTO or ISO believes it desirable to release 
offer and bid data on the day following the operating day, nothing in 
the Final Rule prevents it from making such a proposal to the 
Commission, with appropriate justification; in fact, as indicated in 
the Final Rule, this may be done in the compliance filing to be made in 
this docket.
---------------------------------------------------------------------------

    \218\ Order No. 719, FERC Stats. & Regs. ] 31,281 at P 423.
---------------------------------------------------------------------------

    159. For all these reasons, the Commission declines to grant the 
requests for rehearing on the issue of offer and bid data.
5. Ethics Provisions
    160. In the Final Rule, the Commission enumerated a number of 
minimum ethics standards that the RTOs and ISOs are required to adopt 
for MMUs and their employees.\219\ In response to comments filed by the 
Midwest ISO and Potomac Economics, both of which had requested 
clarification that any adopted ethics standards need not prohibit MMU 
employees from performing monitoring for non-RTO or ISO entities, the 
Commission drew a distinction in the preamble of the Final Rule between 
entities within and without the RTO or ISO monitored by the MMU. The 
Final Rule clarified that a monitoring engagement was permissible if 
the employing entity were not a market participant in the particular 
RTO or ISO for which the MMU performs market monitoring, but if the 
employing entity was a market participant in the RTO or ISO for whom 
the MMU does perform market monitoring, the proposed work would entail 
the same conflict of interest as would any other consulting services, 
and would not be allowed.\220\
---------------------------------------------------------------------------

    \219\ Id. P 383-87.
    \220\ Id. P 385.
---------------------------------------------------------------------------

a. Request for Rehearing or Clarification
    161. Potomac Economics argues that the Commission should allow an 
MMU to perform independent monitoring of an entity other than the RTO 
or ISO it monitors, whether or not such entity is a participant in the 
RTO or ISO markets, arguing that such monitoring does not create a 
conflict of interest.\221\ Potomac Economics contends that the 
interpretation set forth in the Final Rule would harm the MMUs, the 
affected RTOs and ISOs, and the non-RTO or ISO monitored entities, and 
would eliminate synergies that would otherwise result from such 
monitoring.\222\ Alternatively, Potomac Economics requests 
clarification as to which ethics provision is implicated by such 
activity, and whether erecting a ``Chinese Wall'' within the MMU would 
resolve the concern.\223\
---------------------------------------------------------------------------

    \221\ Potomac Economics at 1.
    \222\ Id.
    \223\ Id. at 6-7.
---------------------------------------------------------------------------

    162. In support of its position, Potomac Economics argues that the 
alleged conflict of interest involved in monitoring a non-RTO or ISO 
entity is no greater than that which exists with respect to the RTO or 
ISO itself, inasmuch as in both cases the MMU is compensated by its 
employer.\224\ Potomac Economics further observes that such non-RTO or 
ISO monitoring is done pursuant to contracts filed with the Commission, 
which provide protections against undue influence (such as forbidding 
the entity from using its budget process or the threat of replacing the 
MMU as a means to exert leverage over it).\225\
---------------------------------------------------------------------------

    \224\ Id. at 2.
    \225\ Id. at 3.
---------------------------------------------------------------------------

    163. Potomac Economics also argues that unwinding current 
arrangements providing for such monitoring would impose needless costs 
on the MMUs, the RTOs and ISOs, and the monitored entities,\226\ and 
would eliminate the improved understanding of the RTO or ISO markets 
that the MMU gleans from its knowledge of the activities of the 
monitored entity.\227\
---------------------------------------------------------------------------

    \226\ Id. at 5.
    \227\ Id.
---------------------------------------------------------------------------

b. Commission Determination
    164. After further consideration, the Commission agrees that the 
objections of Potomac Economics are well-taken. To be clear, the 
Commission is concerned that allowing a monitor to oversee both the RTO 
or ISO as well as a market participant operating in the same RTO or ISO 
for activity in that RTO or ISO may raise a conflict of interest 
because the monitor may be called upon to opine on its own oversight. 
However, the Commission is persuaded that the increased insights into 
the RTO or ISO markets provided by such monitoring may give the MMU 
useful information, and results in the synergies that Potomac Economics 
suggests. Therefore, we grant rehearing as set forth below. In an 
effort to balance the potential benefit of synergies resulting from the 
monitor overseeing both the RTO or ISO as well as a market participant 
operating in the same RTO or ISO with our concern over potential 
conflicts of interest, the Commission will permit an RTO or ISO MMU to 
enter into contracts to monitor a market participant operating in the 
same RTO or ISO for activity in that RTO or ISO, under the following 
conditions: The relationship between the entity and the MMU and the 
MMU's scope of work for the entity are both mandated by the Commission 
in an order on the merits, the contract is filed with the Commission 
for review and approval, and the contract contains a provision that the 
entity must notify the Commission of any intention to terminate MMU 
employment, permission for which may be refused by the Commission.\228\
---------------------------------------------------------------------------

    \228\ The purpose of this holding is to prevent potential 
conflicts of interest that arise when the MMU oversees its own 
actions. Thus, if an MMU wants to enter into a contract to oversee 
the activities of a market participant that operates wholly outside 
of the RTO or ISO the MMU oversees, the conditions in this order 
would not apply. Likewise, if an MMU wants to enter into a contract 
with a market participant that has activity inside and outside of an 
RTO or ISO the MMU oversees, and the MMU would only oversee the 
market participant's activity outside of that RTO or ISO, the 
conditions in this order would not apply.
---------------------------------------------------------------------------

    165. In light of this conclusion, it is unnecessary to examine the 
alternative requests for clarification submitted by Potomac Economics. 
Furthermore, inasmuch as the Commission's discussion on this point in 
the Final Rule was advanced as a matter of clarification rather than 
being based on the language of the regulatory text, we find it 
unnecessary to amend the regulatory text promulgated in the Final Rule 
to reach this result. For all these reasons, the Commission grants 
rehearing on this issue and clarifies the circumstances under which an 
MMU may perform monitoring services for non-RTO and ISO entities, as 
set forth in the foregoing discussion.
6. Referral of Market Design Flaws
    166. NYISO filed an out-of-time request for clarification regarding 
the interpretation of certain language contained in the protocols for 
the referral of market design flaws to Commission staff, which are 
included in the regulatory text of the Final Rule. Although NYISO's 
request has been rejected for untimeliness, the Commission finds that 
it would be useful to provide certain clarifications as to when an MMU 
is to make referrals, whether the referral is for suspected wrongdoing 
or for the identification of market design flaws.
    167. The operative language in both the protocols for the referral 
of suspected wrongdoing and the protocols for the identification of 
market design flaws is the same; that is, an MMU is to make such a 
referral ``in all instances where the Market Monitoring Unit has

[[Page 37798]]

reason to believe'' either that a market violation has occurred or 
market design flaws exist that the MMU believes could effectively be 
remedied by rule or tariff changes. This language is identical to the 
language that is contained in the existing protocols for referral of 
suspected wrongdoing, which were promulgated in the 2005 Policy 
Statement on Market Monitoring Units.\229\ The MMUs have had a number 
of years to become accustomed to the interpretation of this language, 
and can apply what they have learned from the operation of the existing 
protocols for suspected wrongdoing to the new protocols for referral of 
market design flaws.
---------------------------------------------------------------------------

    \229\ Market Monitoring Units in Regional Transmission 
Organizations and Independent System Operators, 111 FERC ] 61,267 
(2005).
---------------------------------------------------------------------------

    168. More specifically, this means that the MMUs are to exercise 
judgment and a certain amount of discretion in deciding what to refer 
to Commission staff. If the RTO or ISO is already aware of the 
perceived market design flaw and is timely addressing it, there is no 
need for the MMU to make a referral to the Commission (although the 
Commission expects the MMU to apprise the Commission staff on an 
informal basis of important tariff changes being contemplated by the 
RTO or ISO). Likewise, if the design flaw is de minimis, there may well 
be no need to make a referral. When in doubt, the MMU should simply 
call the appropriate members of Commission staff and discuss the issue. 
This procedure will provide the MMU with any needed guidance as to 
whether a filing needs to be made.
    169. We find that the foregoing clarification does not require an 
alteration to the Final Rule's regulatory text, which as indicated 
simply repeats the language contained in the current protocols for the 
referral of suspected wrongdoing to Commission staff, and which has 
historically been interpreted in the manner indicated above.

D. Responsiveness of RTOs and ISOs to Customers and Other Stakeholders

    170. In the Final Rule, the Commission required RTOs and ISOs to 
establish a means for customers and other stakeholders to have a form 
of direct access to the board of directors, and thereby to increase the 
boards of directors' responsiveness to these entities. The Commission 
required each RTO or ISO to submit a compliance filing demonstrating 
that it has in place, or will adopt, practices and procedures to ensure 
that its board of directors is responsive to customers and other 
stakeholders. The compliance filings will be assessed based on four 
criteria. The Commission also directed each RTO and ISO to post on its 
Web site its mission statement or organizational charter.\230\ Requests 
for rehearing were timely filed with respect to: the criteria for 
responsiveness, including the implementation of cost-benefit analyses 
by RTOs and ISOs and the inclusion of board members with State 
regulatory experience; the potential for use of hybrid boards; and the 
lack of a mandate for specific items in the RTO or ISO mission 
statement.
---------------------------------------------------------------------------

    \230\ Order No. 719, FERC Stats. & Regs. ] 31,281 at P 556-57.
---------------------------------------------------------------------------

1. Criteria for Responsiveness
    171. In the Final Rule, the Commission adopted four criteria from 
the NOPR for assessing the filed practices and procedures of each RTO 
and ISO:
    <bullet> Inclusiveness--The business 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's or ISO's board of directors.
    <bullet> Fairness in Balancing Diverse Interests--The business 
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.
    <bullet> Representation of Minority Positions--The business 
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 RTO's or ISO's board of directors at 
the same time as majority positions.
    <bullet> Ongoing Responsiveness--The business practices and 
procedures must provide for stakeholder input into the RTO's or ISO's 
decisions as well as mechanisms to provide feedback to stakeholders to 
ensure that information exchange and communication continue over time.

The Commission found that additional criteria for responsiveness as 
proposed by commenters--for example, cost-benefit analyses or cost-
containment procedures--were practices and procedures best developed by 
regional entities and their stakeholders, and therefore not necessary 
in our regulations.\231\ However, many of the other proposed criteria 
could be considered and, if appropriate, adopted on a regional basis.
---------------------------------------------------------------------------

    \231\ Id. P 515.
---------------------------------------------------------------------------

a. Requests for Rehearing
    172. APPA-CMUA notes that in APPA's comments to the NOPR, it 
expressed a strong concern that the four criteria proposed by the 
Commission were so general in nature that it would not be difficult for 
RTOs to assert that they already satisfy the requirements, and that 
little change would occur to RTO responsiveness as a result.\232\ APPA 
suggested several concrete measures that the Commission should adopt to 
ensure responsiveness, including: direct stakeholder access to RTO 
boards, presentation of minority viewpoints directly to the board, 
consideration of stakeholder advisory committees and hybrid boards, 
open RTO board meetings with agendas disclosed in advance, board member 
attendance at working group/technical meetings where appropriate, 
elimination of ``self-perpetuating'' RTO boards, administration of 
customer satisfaction surveys, development of cost oversight 
benchmarking for RTOs, and a moratorium on the establishment of new 
RTO-run markets unless accompanied by an independent cost-benefit 
analysis or affirmative vote of all RTO stakeholder classes. APPA-CMUA 
argues that because the Commission declined to adopt additional 
measures, customers seeking greater RTO responsiveness and 
accountability will have to participate in RTO stakeholder processes 
with no clear guidance as to what specific measures will satisfy the 
four general criteria adopted in the Final Rule. They seek rehearing of 
this aspect of the Final Rule, and ask the Commission to implement 
additional measures and criteria to allow for concrete improvements in 
RTO responsiveness.\233\
---------------------------------------------------------------------------

    \232\ APPA-CMUA at 41 (citing APPA NOPR Comments at 97-103).
    \233\ Id. at 40-43.
---------------------------------------------------------------------------

    173. TAPS also notes that the Commission failed to implement 
specific requirements for RTO responsiveness or accountability. TAPS 
points to the suggestions it made in its comments to the NOPR, 
including requirements for cost-benefit analyses, annual public 
reporting of RTO performance measurements, requiring RTO management 
compensation to be tied to consumer-focused performance measures, and 
an improved budget review process with advance stakeholder review. TAPS 
also argued that RTOs should be held accountable for fulfilling 
obligations to plan and expand the transmission system to meet

[[Page 37799]]

customers' needs. TAPS argues that the stakeholder process mandated in 
the Final Rule will not be sufficient to meet the needs it outlined in 
its comments, and it notes that a recently-released GAO Report confirms 
the need for Commission action and oversight.\234\ Accordingly, TAPS 
asks the Commission to implement its suggested requirements, or to 
institute a new NOPR on this topic.\235\
---------------------------------------------------------------------------

    \234\ TAPS at 67 (citing 2008 GAO Report). See supra note 129.
    \235\ TAPS at 67.
---------------------------------------------------------------------------

    174. SMUD also argues that the Commission should require RTOs and 
ISOs to implement performance penalties for managers. It notes that the 
accountability of RTOs for results is distinct from RTO responsiveness. 
Since RTOs and ISOs are not-for-profit entities, SMUD argues, they 
cannot be penalized for imprudence. Accordingly, the Commission should 
address the need for RTOs and ISOs to adopt performance penalties for 
imprudent decisions by managers.\236\
---------------------------------------------------------------------------

    \236\ SMUD at 9.
---------------------------------------------------------------------------

    175. SMUD further argues that the Commission erred in failing to 
require RTOs and ISOs to conduct cost-benefit analyses before 
implementing major initiatives. It believes that such a requirement 
would impose discipline on RTOs and ISOs and improve accountability to 
stakeholders. SMUD also asserts that the Commission must clarify that, 
in specific factual situations, the absence of sector representation or 
procedures for rejecting majority stakeholder positions would violate 
the responsiveness criteria.\237\
---------------------------------------------------------------------------

    \237\ Id. at 11.
---------------------------------------------------------------------------

    176. Pennsylvania PUC states that the Commission failed to address 
its concerns regarding the control of board election procedures by RTO 
or ISO employees or managers. Pennsylvania PUC argues that this issue 
touches on board ``capture'' by RTO or ISO management, and is not 
sufficiently addressed by the Final Rule.\238\
---------------------------------------------------------------------------

    \238\ Pennsylvania PUC at 7.
---------------------------------------------------------------------------

b. Commission Determination
    177. The Commission reviewed the proposals for new criteria and 
board practices in preparing the Final Rule and found that neither more 
specific criteria nor additional criteria from the Commission were 
necessary or appropriate. We deny rehearing on this issue.
    178. The criteria established for responsiveness were intended to 
balance the need to improve RTOs' and ISOs' responsiveness to their 
stakeholders with the development of practices that best suit the needs 
of the individual RTO or ISO.\239\ We continue to believe that this 
process best works through collaboration between the RTO or ISO and its 
stakeholders based on the broad principles laid out by the Commission, 
rather than through the Commission mandating specific outcomes. 
Further, RTOs and ISOs are still evolving institutions; they and their 
stakeholders may want to add, remove, or improve specific 
responsiveness provisions over time, without being prevented from doing 
so by Commission codification of today's practices. Many of the 
specific criteria suggested in the comments prior to the Final Rule and 
in the requests for rehearing are better addressed through the 
stakeholder process, where RTOs and ISOs can tailor these ideas to the 
needs of their regions, and amend them as needed without a change in 
Commission regulations.
---------------------------------------------------------------------------

    \239\ Order No. 719, FERC Stats. & Regs. ] 31,281 at P 505.
---------------------------------------------------------------------------

    179. In establishing the four criteria for board responsiveness, 
the Commission's goal was to be sufficiently prescriptive to give RTOs 
and ISOs a guideline for how to structure their board policies, without 
being so specific as to micromanage each RTO's and ISO's policy. For 
instance, although we believe that cost-benefit analyses can be useful 
in analyzing new projects, we are unconvinced that the Commission 
should mandate cost-benefit analyses in all circumstances where an RTO 
or ISO engages in a major initiative. We do not have enough evidence in 
the record to determine when and how an RTO or ISO should be required 
to perform a cost-benefit analysis. Instead, in the Final Rule, we 
encouraged interested parties to raise this idea with individual RTOs 
or ISOs, and allow the RTO or ISO to work out a policy that is tailored 
to its needs.\240\
---------------------------------------------------------------------------

    \240\ Id. P 515. See also discussion supra P 71 (declining to 
require cost-benefit analysis for ARCs' participation in RTO- and 
ISO-administered markets but encouraging RTOs and ISOs to evaluate 
this option individually).
---------------------------------------------------------------------------

    180. The specific requirements raised by APPA, TAPS and others 
represent the end point of the policy process, and should be the result 
of a dialogue between RTOs and ISOs and their stakeholders rather than 
Commission mandate. We are interested here in making sure that 
stakeholders are able to have a productive dialogue with their RTO or 
ISO, and the criteria the Commission established in the Final Rule were 
designed to require that this be done in a way determined by each 
region.
    181. With respect to Pennsylvania PUC's concern regarding the 
relationship between the RTO or ISO board and the entity's employees, 
we note that Pennsylvania PUC has not presented any evidence that this 
is a generic issue for all RTOs and ISOs, and does not make the case 
that a Commission mandate is necessary or appropriate. Pennsylvania PUC 
should raise any concerns regarding specific RTO or ISO practices 
during the stakeholder process for forming the responsiveness practices 
and procedures for that RTO or ISO. Pennsylvania PUC may raise the 
issue again with the Commission following the RTO and ISO compliance 
filings if it believes that its concerns have not been adequately 
addressed.
    182. Similarly, with respect to SMUD's and TAPS' requests for 
requirements for performance penalties for managers, we continue to 
encourage, but not require, that executive compensation programs give 
appropriate weight to responsiveness. As we discuss further below, the 
Commission mandating specific requirements with respect to board 
structure or board and management compensation could lead to a slippery 
slope,\241\ and may also be outside the Commission's jurisdiction.\242\
---------------------------------------------------------------------------

    \241\ See infra, note 254.
    \242\ See Cal. Indep. Sys. Operator Corp. v. FERC, 372 F.3d 395 
(D.C. Cir. 2004).
---------------------------------------------------------------------------

2. Hybrid Boards
    183. In the Final Rule, the Commission did not require RTOs or ISOs 
to adopt a specific form of board structure, whether board advisory 
committee, hybrid board, or other. The Commission found that a one-
size-fits-all approach was not warranted. The Commission did note that 
it viewed the board advisory committee as a particularly strong 
mechanism for enhancing responsiveness, and that it expected each RTO 
and ISO to work with its stakeholders to develop the mechanism that 
best suits its needs.\243\
---------------------------------------------------------------------------

    \243\ Order No. 719, FERC Stats. & Regs. ] 31,281 at P 534.
---------------------------------------------------------------------------

    184. With respect to hybrid boards, the Commission followed its 
ruling in Order No. 2000,\244\ in which it noted that RTOs and ISOs 
take many different forms to reflect the various needs of

[[Page 37800]]

each region.\245\ The Commission denied requests to disallow hybrid 
boards in this proceeding, reasoning that a hybrid governance structure 
could be constructed in a way that allows for the expertise of various 
groups to inform the decision-making process, while still retaining 
board independence such that no individual market participant is given 
undue influence over the decisions of the board. The Commission noted 
that commenters were free to raise objections to the specific hybrid 
board proposals made by RTOs and ISOs in their compliance filings.\246\
---------------------------------------------------------------------------

    \244\ Regional Transmission Organizations, Order No. 2000, FERC 
Stats. & Regs. ] 31,089 (1999), order on reh'g, Order No. 2000-A, 
FERC Stats. & Regs. ] 31,092 (2000), aff'd sub nom. Pub. Util. Dist. 
No. 1 of Snohomish County, Washington v. FERC, 272 F.3d 607 (D.C. 
Cir. 2001).
    \245\ Order No. 719, FERC Stats. & Regs. ] 31,281 at P 537 
(citing Order No. 2000, FERC Stats. & Regs. 31,089 at 31,073-75).
    \246\ Id.
---------------------------------------------------------------------------

a. Requests for Rehearing
    185. Several parties argue that the Commission erred in allowing 
RTOs and ISOs to choose to create hybrid boards. For instance, Illinois 
Commerce Commission argues that board advisory committees are a 
superior method of promoting responsiveness, and that the Commission 
should remove the option of hybrid boards based on their many 
flaws.\247\ Pennsylvania PUC argues that allowing hybrid boards would 
be at odds with the principle of independence established by the 
Commission in Orders No. 888 \248\ and 2000. Pennsylvania PUC argues 
that hybrid boards are a bad idea for several reasons, including the 
difficulty hybrid board members would have in fulfilling their 
fiduciary duties, the potential for confrontation among members of a 
sector, and the inability to protect confidential information from 
disclosure or misuse.\249\
---------------------------------------------------------------------------

    \247\ Illinois Commerce Commission at 9.
    \248\ 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 (D.C. 
Cir. 2000), aff'd sub nom. New York v. FERC, 535 U.S. 1 (2002).
    \249\ Pennsylvania PUC at 9.
---------------------------------------------------------------------------

    186. Industrial Coalitions state that the Commission failed to 
present adequate evidence that hybrid boards could be appropriately 
independent and responsive. They argue that an RTO's or ISO's 
independence depends on the independence of its board members, and that 
a hybrid board would, by definition, violate this independence 
requirement. Additionally, Industrial Coalitions argue that a hybrid 
board structure would expose independent board members to undue 
influence from stakeholder interests on the board, which could lead to 
a divisive atmosphere and suspicion. Finally, they note that it is 
unlikely that a hybrid board would provide adequate representation to 
end-use customers, and would likely actually diminish customers' 
voice.\250\
---------------------------------------------------------------------------

    \250\ Industrial Coalitions at 17.
---------------------------------------------------------------------------

    187. The Ohio PUC argues that the Commission erred in not 
preventing stakeholders from participating in RTO or ISO boards, and 
that this decision will erode confidence in RTO or ISO boards because 
they will be perceived to be biased and to lack independence. Both the 
Ohio PUC and the Wisconsin PSC also argue that the Commission erred in 
not ensuring that States' interests are adequately represented on RTO 
or ISO boards, through seating a board member with State regulatory 
experience.\251\
---------------------------------------------------------------------------

    \251\ Ohio PUC at 19; Wisconsin PSC at 3.
---------------------------------------------------------------------------

b. Commission Determination
    188. In the Final Rule, the Commission did not mandate a specific 
form of board structure, but instead allowed RTOs and ISOs to propose 
their own methods of meeting the four criteria, including through a 
board advisory committee or a hybrid board.\252\ The Commission heard 
many of the same arguments against hybrid boards made in the requests 
for rehearing in comments received prior to the Final Rule. We are 
aware that this is an issue of some controversy, and we take seriously 
the potential independence issues that may arise from having 
stakeholder members on an RTO or ISO board of directors. We emphasize 
that the Final Rule did not repeal any of the requirements for RTO 
independence in Order No. 2000 or for ISO independence in Order No. 
888. However, we are not convinced that it is impossible to structure a 
hybrid board so as both to meet the board independence requirements of 
prior orders and to provide for limited stakeholder membership without 
compromising board independence. Accordingly, we deny rehearing on this 
issue.
---------------------------------------------------------------------------

    \252\ Order No. 719, FERC Stats. & Regs. ] 31,281 at P 534-37.
---------------------------------------------------------------------------

    189. Our ruling does not imply that every form of hybrid board 
would be acceptable to the Commission. As we stated in the Final Rule, 
any board that includes market participants should be structured to 
ensure that no one class would be allowed to veto a decision reached by 
the rest of the board, and that no two classes could force through a 
decision opposed by the rest of the board.\253\ We continue to view the 
board advisory committee as a particularly strong mechanism for 
enhancing responsiveness, and we will closely review any RTO or ISO 
proposal to ensure that it is just and reasonable and the result of a 
thorough stakeholder process.
---------------------------------------------------------------------------

    \253\ Id. P 537.
---------------------------------------------------------------------------

    190. We also deny the requests to require that RTO and ISO boards 
include one member with State regulatory experience. While we believe 
that a variety of backgrounds and experiences may be useful for an RTO 
or ISO board, we do not see a reason for the Commission to set generic 
board membership requirements for all RTOs and ISOs regarding any 
particular specific experience or qualification. The Ohio Commission 
and the Wisconsin PSC have not convinced us, in their requests for 
rehearing, that mandating State regulatory membership would be suited 
to all circumstances, and therefore we prefer to allow RTOs and ISOs 
the flexibility to propose for Commission approval their own choices 
regarding board membership.\254\ As previously stated, we will evaluate 
those proposals in light of the four responsiveness criteria enumerated 
above.
---------------------------------------------------------------------------

    \254\ Indeed, some state regulators may be prohibited by state 
law from serving on the boards of public utilities, and an RTO or 
ISO covering one state or a small number of states may be unable to 
meet such a generic membership requirement. We further note that 
requiring that any particular class of stakeholders, including state 
regulators, have membership on RTO and ISO boards is a slippery 
slope; we do not wish to impose any affirmative requirements for 
category of board members.
---------------------------------------------------------------------------

3. Mission Statements
    191. The Final Rule required each RTO and ISO to post on its Web 
site a mission statement or organizational charter. The Commission 
encouraged each RTO and ISO to include in its mission statement, among 
other things, 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.\255\
---------------------------------------------------------------------------

    \255\ Order No. 719, FERC Stats. & Regs. ] 31,281 at P 556.
---------------------------------------------------------------------------

a. Requests for Rehearing
    192. Both APPA and TAPS argue that the Commission erred in failing 
to mandate specific statements in the proposed mission statement posted 
by the RTO or ISO. APPA notes that the FPA requires that rates be just 
and reasonable, and thus RTO and ISO mission statements should include 
explicit language requiring RTOs and

[[Page 37801]]

ISOs to provide cost reductions and net benefits to the ultimate 
consumers they serve.\256\ TAPS agrees that the required mission 
statement should be specific and consumer-focused. TAPS argues that the 
Commission will not fulfill its obligation under the Federal Power Act 
unless it redefines the RTOs' and ISOs' mission to include provision of 
reliable service at the lowest possible reasonable rates, and requires 
RTOs and ISOs to meet these goals.\257\
---------------------------------------------------------------------------

    \256\ APPA at 44-45.
    \257\ TAPS at 60-62.
---------------------------------------------------------------------------

b. Commission Determination
    193. We deny rehearing of the Commission's decision not to mandate 
specific statements in the mission statements required of each RTO and 
ISO. We find, however, that a successful mission statement should 
explain the mission of an RTO or ISO, as developed in a collaborative 
process with stakeholders, and we do not wish to interfere with this 
process by mandating specific elements of the mission statement. 
Indeed, an RTO's or ISO's mission may evolve over time, and it should 
be able to update its mission statements to reflect new mission 
elements. (We note in this regard, as discussed elsewhere in this 
order, that some petitioners would have us reconsider now the existing 
mission of some RTOs and ISOs.) If parties believe that an RTO or ISO 
mission statement is not sufficiently consumer-focused, or is otherwise 
deficient, they should raise those objections during the stakeholder 
process or in response to the RTO or ISO compliance filing.

III. Document Availability

    194. 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) 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.
    195. 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.
    196. 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 
<a href="/cdn-cgi/l/email-protection#6b0d0e190804050702050e181e1b1b04191f2b0d0e1908450c041d"><span class="__cf_email__" data-cfemail="80e6e5f2e3efeeece9eee5f3f5f0f0eff2f4c0e6e5f2e3aee7eff6">[email protected]</span></a>, or the Public Reference Room at (202) 502-
8371, TTY (202) 502-8659. E-mail the Public Reference Room at 
<a href="/cdn-cgi/l/email-protection#a5d5d0c7c9ccc68bd7c0c3c0d7c0cbc6c0d7cacac8e5c3c0d7c68bc2cad3"><span class="__cf_email__" data-cfemail="87f7f2e5ebeee4a9f5e2e1e2f5e2e9e4e2f5e8e8eac7e1e2f5e4a9e0e8f1">[email protected]</span></a>.

IV. Effective Date

    197. Changes to Order No. 719 made in this order on rehearing will 
be effective on August 28, 2009.

List of Subjects in 18 CFR Part 35

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

    By the Commission. Commissioner Kelly is concurring in part and 
dissenting in part with a separate statement attached.
Nathaniel J. Davis, Sr.,
Deputy Secretary.


0
In consideration of the foregoing, the Commission amends part 35, 
Chapter I, Title 18, of the Code of Federal Regulations, as follows:

PART 35--FILING OF RATE SCHEDULES AND TARIFFS

0
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.


0
2. In Sec.  35.28, paragraph (g)(1)(iii) is revised as follows:


Sec.  35.28  Non-discriminatory open access transmission tariff.

* * * * *
    (g) * * *
    (1) * * *
    (iii) Aggregation of retail customers. Each Commission-approved 
independent system operator and regional transmission organization must 
accept bids from an aggregator of retail customers that aggregates the 
demand response of the customers of utilities that distributed more 
than 4 million megawatt-hours in the previous fiscal year, and the 
customers of utilities that distributed 4 million megawatt-hours or 
less in the previous fiscal year, where the relevant electric retail 
regulatory authority permits such customers' demand response to be bid 
into organized markets by an aggregator of retail customers. An 
independent system operator or regional transmission organization must 
not accept bids from an aggregator of retail customers that aggregates 
the demand response of the customers of utilities that distributed more 
than 4 million megawatt-hours in the previous fiscal year, where the 
relevant electric retail regulatory authority prohibits such customers' 
demand response to be bid into organized markets by an aggregator of 
retail customers, or the customers of utilities that distributed 4 
million megawatt-hours or less in the previous fiscal year, unless the 
relevant electric retail regulatory authority permits such customers' 
demand response to be bid into organized markets by an aggregator of 
retail customers.
* * * * *

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

KELLY, Commissioner, concurring in part and dissenting in part:

    As I have noted in my separate statements at each phase of this 
proceeding, I continue to have misgivings about the potential impacts 
of several of Order No. 719's directives, including (1) the scarcity 
pricing measures; (2) the issue of promoting responsiveness of RTOs/
ISOs by allowing them to adopt hybrid boards with stakeholder members; 
and (3) MMUs being removed from tariff administration and 
mitigation.\1\ Despite my ongoing concerns, I believe that some of 
these proposals have positively evolved over the course of this 
proceeding. A good deal of that evolution is due to the commenters who 
have taken the time to participate in our process, thereby moving the 
debate in a positive direction. I also want to commend Commission staff 
who have worked tirelessly on these efforts. I believe that the 
Commission has appropriately used Order No. 719 as a vehicle to move 
the issue of competition in organized markets in a generally positive 
direction. Further, as the order states, the Commission will continue 
to look for ways to strengthen organized markets.
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    \1\ See Wholesale Competition in Regions with Organized Electric 
Markets, Advance Notice of Proposed Rulemaking, FERC Stats. & Regs. 
] 32,617 (2007), Notice of Proposed Rulemaking, FERC Stats. & Regs. 
] 32,628 (2008), Order No. 719, 73 FR 61,400 (Oct. 28, 2008), FERC 
Stats. & Regs. ] 31,281 (2008) (Comm'r Kelly concurring in part and 
dissenting in part).
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    Accordingly, I respectfully concur in part and dissent in part.

Suedeen G. Kelly

[FR Doc. E9-17364 Filed 7-28-09; 8:45 am]
BILLING CODE 6717-01-P


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