Wholesale Competition in Regions With Organized Electric Markets, 37776-37801 [E9-17364]

Agencies

• DEPARTMENT OF ENERGY
• Federal Energy Regulatory Commission

[Federal Register Volume 74, Number 144 (Wednesday, July 29, 2009)]
[Rules and Regulations]
[Pages 37776-37801]
From the Federal Register Online via the Government Printing 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. Russell.Profozich@ferc.gov. (202) 502-6478.
Tina Ham (Legal Information), Office of the General Counsel, Federal 
Energy Regulatory Commission, 888 First Street, NE., Washington, DC 
20426. Tina.Ham@ferc.gov. (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

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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 https://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\
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    \36\ Id. at 2-3.
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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.
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    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 syst