37776 Federal Register / Vol. 74, No. 144 / Wednesday, July 29, 2009 / Rules and Regulations 

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. 

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

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 Operating Reserve Shortages in Organized Markets ............................. 13 

1. Ancillary Services Provided by Demand Response Providers .......................................................................................... 13 

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 Periods of Operating Reserve Shortage ............................................ 72 

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 Other Stakeholders ............................................................................ 171 

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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Federal Register / Vol. 74, No. 144 / Wednesday, July 29, 2009 / Rules and Regulations 37777 

1Wholesale 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). 

2Organized 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). 

4Order No. 719, FERC Stats. & Regs. ¶ 31,281 at 

P 4, 15. 

5 Id. P 274. 

6The 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. 

7Order No. 719, FERC Stats. & Regs. ¶ 31,281 at 

P 2. 

8 Id. P 14. 

9 Id. P 8, 578–83. 

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) marketmonitoring 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. 

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 dayahead 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 marketclearing 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

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

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. 

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

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

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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10Additionally, Monitoring Analytics, LLC filed 

an out-of-time motion to intervene in this 

proceeding, but did not seek rehearing. 

11 16 U.S.C 825l. 

12See, 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.’’). 

13See, 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). 

14Order No. 719, FERC Stats. & Regs. ¶ 31,281 at 

P 47. 

15 Id. P 56. 

16Pennsylvania PUC at 4. 

17Order No. 719, FERC Stats. & Regs. ¶ 31,281 at 

P 276. 

18 Id. P 154. 

19 Id. P 163. 

20See, 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. 

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

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 FPA11 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

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 marketclearing 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 marketclearing price.14 The Commission 

determined that these requirements 

would remove barriers to the 

comparable treatment of demand-side 

and supply-side resources. 

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

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

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

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

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 

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Federal Register / Vol. 74, No. 144 / Wednesday, July 29, 2009 / Rules and Regulations 37779 

21 16 U.S.C. 824(a). 22TAPS 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. 24TAPS 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)). 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)). 

26Section 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 * * * nonjurisdictional 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)). 

29Ohio 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. 

31 Joint Petitioners at 15–16. 

32Specifically, 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. 

33 Id. at 31. TAPS notes that under Order No. 890, 

network customers must attest, for each network 

Continued 

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

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. 

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 nonconsumption). 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 nonregulated 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

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

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 optin 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. 

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 

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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). 

34AEP at 1. 

35 Id. at 2. 

36 Id. at 2–3. 

37NARUC states that it incorporates by reference 

the arguments presented on this issue by Joint 

Petitioners’ request for rehearing. NARUC at 5. 

38TAPS at 25–26. 

39For 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. 

40TAPS 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. 

41 5 U.S.C. 601–12. 

42 Joint Petitioners at 23. 

43TAPS at 26–27. 

44American 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). 

45TAPS 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. 

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. 

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 commissionapproved tariff provisions that prohibit 

sales for resale.’’ 34

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

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

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. 

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. 

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 

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46 Id. at 29. 

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. 

49TAPS at 30. 

50 Id. at 14 (citing TAPS NOPR Comments at 13– 

17). 

51 Id. at 14–15. 

52 Id. 

53 Joint Petitioners at 14–15. 54 Id. at 15. 55TAPS at 17. 56 Id. at 18. 57TAPS provides the following example to 

explain ‘‘phantom energy’’: 

Continued 

burdening hundreds of municipal 

entities.46

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

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. 

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 loadserving 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-servingentity-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

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 loadserving-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

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 notfor-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 cherrypicking 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

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 loadserving entity’s ability to plan for its 

load and harness that demand response 

to reduce the costs of serving all of its 

customers. 

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 thirdparty ARCs to sell demand response 

into wholesale markets may be subject 

to phantom energy charges,57 based on 

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37782 Federal Register / Vol. 74, No. 144 / Wednesday, July 29, 2009 / Rules and Regulations 

[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). 

60 Id. 

61 Id. at 22–23. 

62Order No. 719, FERC Stats. & Regs. ¶ 31,281 at 

P 594; NOPR, FERC Stats. & Regs. ¶ 32,628 at P 83. 

63 16 U.S.C. 824(b). 

64Section 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). 

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). 

66See, 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.’’). 

67Connecticut 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 

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 loadserving 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, marketprice driven demand response, could 

impose over- and under-scheduling 

charges on a load-serving entity under 

the SPP’s tariff.59

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

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 loadserving-entity-administered demand 

response programs, and to implement 

them only if that evaluation 

demonstrates that the benefits outweigh 

the costs.61

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. 

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. 

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. 

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

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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. 

69See, 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). 

70See, 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). 

71See, 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). 

72ANOPR, FERC Stats. & Regs. ¶ 32,617 at P 37. 

73NOPR, 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). 

75NOPR, FERC Stats. & Regs. ¶ 32,628 at P 31. 

76For 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). 

77Where 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). 

78Order No. 719, FERC Stats. & Regs. ¶ 31,281 at 

P 3; NOPR, FERC Stats. & Regs. ¶ 32,628 at P 282. 

79The 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). 

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 dayahead 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

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

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. 

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 

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80Open 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). 

81See Wolverine Power Supply Coop., 127 FERC 

¶ 61,159, at P 15 (2009). 

82See 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. 

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

87Order No. 719, FERC Stats. & Regs. ¶ 31,281 at 

P 155. 

88NOPR, FERC Stats. & Regs. ¶ 32,628 at P 291. 

89Order No. 719, FERC Stats. & Regs. ¶ 31,281 at 

P 155, 602. 

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

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

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 narrowlyfocused 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

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 

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90See discussion supra P 51. 

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’’). 

93American 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’’). 

95Order No. 719, FERC Stats. & Regs. ¶ 31,281 at 

P 154. 

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

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. 

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. 

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. 

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 

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96The 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. 

97TAPS 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. 

98Order No. 719, FERC Stats. & Regs. ¶ 31,281 at 

P 159. 

99 Id. P 192. 

100 Id. 

101 Id. P 194. 

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. 

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. 

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 loadserving 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

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

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 

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102The 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 agreedupon 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. 

103The 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. 

104 Joint Petitioners at 32–33. 

105 Id. at 44 (citing NRECA Affidavit at P 20–55). 

106TAPS at 33 (citing TAPS NOPR Comments at 

24–27). 

107 Id. at 39. 

108For 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)). 

110 Joint Petitioners at 41. 

111 Industrial Coalition at 7–8. 

112Pennsylvania PUC at 5. 

113 Joint Petitioners at 48–49. 

114Old Dominion at 4. 

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. 

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

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

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 caps109 and the Final 

Rule fails to demonstrate how 

circumstances are sufficiently different 

to warrant a change in Commission 

policy. 

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

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

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 

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115 Id. at 5–6. 

116Ohio PUC at 7. 

117They 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). 

118Order No. 719, FERC Stats. & Regs. ¶ 31,281 

at P 251. 

119TAPS at 54–56. 

120 Id. at 42–45. 

121 Joint Petitioners at 35 (citing Order No. 719, 

FERC Stats. & Regs. ¶ 31,281 at P 235). 

122 Id. at 41. 

123 Id. at 49–50 (citing NRECA NOPR Comments 

at 29). 

124TAPS 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 marketclearing 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). 

125 Joint Petitioners at 42. 

126 Id. at 51–52. 

127 Id. at 53. 

128 Id. at 49. 

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

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

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

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

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

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

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. 

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. 

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

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

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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)). 

130 Joint Petitioners at 54. 

131The 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. 

132Order No. 719, FERC Stats. & Regs. ¶ 31,281 

at P 192; NOPR, FERC Stats. & Regs. ¶ 32,628 at P 

107. 133Order No. 719, FERC Stats. & Regs. ¶ 31,281 

at P 192. 

134 Id. P 195. 

135 Id. P 235. 

136 Id. P 187 (citing PJM Power Providers NOPR 

Comments at 3). 

137For 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. 

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

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

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

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

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. 

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. 

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 

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138Order No. 719, FERC Stats. & Regs. ¶ 31,281 

at P 196. 

139 Id. P 251. 140 Id. P 247. 

141 Id. P 235. 142Order No. 719, FERC Stats. & Regs. ¶ 31,281 

at P 194–95. 143 Id. P 195. 144Order No. 719, FERC Stats. & Regs. ¶ 31,281 

at P 239, 249–50. 145 Id. P 249. 

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. 

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. 

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 caseby-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. 

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. 

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 

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146 Id. P 244. 

147 Id. P 196. 

148 Id. P 307. 

149 Id. 

150SMUD at 7. 

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). 

152Order No. 681–A, 117 FERC ¶ 61,201 at P 105. 

153Cal. Indep. Sys. Operator Corp., 120 FERC 

¶ 61,023, at P 229 (2007), reh’g denied, 124 FERC 

¶ 61,094 (2008). 

154 Id. 

155Order No. 681–A, 117 FERC ¶ 61,201 at P 106. 

156Supplemental Notice of Technical Conference, 

Capacity Markets in Regions with Organized 

Electric Markets, Docket No. AD08–4–000 (April 25, 

2008). 

157APPA–CMUA at 3. 

other issues raised by petitioners. 

Therefore, we disagree that the Final 

Rule ignored proposals for additional 

criteria. 

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. 

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. 

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 longterm contracting. In the Final Rule, 

however, the Commission declined to 

take any action on hedging 

instruments.149

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 longterm 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

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

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. 

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

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 

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158 Id. at 21. 

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). 

162APPA–CMUA at 28. 

163 Id. at 32 (citing 2008 GAO Report). See supra 

note 129. 

164 Id. at 34–36. 

165See Chevron U.S.A. Inc. v. NRDC, 467 U.S. 

837, 842–845 (1984). 

166See Massachusetts v. EPA, 549 U.S. at 527. 

167 Id. at 530. 

168See Order No. 719, FERC Stats. & Regs. 

¶ 31,281 at P 13. 

169 Id. P 2; NOPR, FERC Stats. & Regs. ¶ 32,628 

at P 4, 282. 

technical conference held on May 7, 

2008, but that there has been no further 

activity in that docket.158

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

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

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 longterm 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. 

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

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. 

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 

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170See Order No. 719, FERC Stats. & Regs. 

¶ 31,281 at P 280. 171For 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). 

172NOPR, FERC Stats. & Regs. ¶ 32,628 at P 16– 

25. 

173Public Law 109–58, 119 Stat. 594. 

174Order No. 719, FERC Stats. & Regs. ¶ 31,281 

at P 317 et seq. 

175 Id. P 395 et seq. 

176A 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. 

177Old Dominion at 6–7. 

178Pennsylvania PUC at 5–6. 

179 Id. at 3. 

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. 

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. 

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

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

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. 

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

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

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 

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180 Industrial Coalitions at 12–14. 

181Ohio PUC at 14–15; Wisconsin PSC at 2–3. 

182Ohio PUC at 15. 

183Order No. 719, FERC Stats. & Regs. ¶ 31,281 

at P 370–79. 

184Pennsylvania PUC at 3. 

185Order No. 719, FERC Stats. & Regs. ¶ 31,281 

at P 374. 

186Ohio 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. 

190Wisconsin PSC at 2–3. 

191Order No. 719, FERC Stats. & Regs. ¶ 31,281 

at P 327. 

preference for unmitigated outcomes, 

and therefore should not be given total 

responsibility for identifying and 

rectifying abuses of market power.180

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

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 wellknown 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

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. 

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

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

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

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 

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192 Id. P 446–59. 

193 Illinois Commerce Commission at 4–5. 194 Id. 195 Id. at 2–4. 196Minnesota PUC at 1. 197Order No. 719, FERC Stats. & Regs. ¶ 31,281 

at P 446–59. 

198State commissions have the further safety 

valve of seeking otherwise proscribed information 

by filing a request with the Commission. Id. P 458. 

199 Id. P 452. 

200 Id. P 450. 

referrals to the Commission. This reform 

was instituted precisely to bolster the 

independence of the MMU performing 

the core MMU functions. 

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. 

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

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

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 

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201 Id. P 465. 

202Most RTOs and ISOs have a six-month release 

policy. 

203TAPS at 56. 

204 Id. at 57. 

205 Id. at 58. 

206 Id. at 59. 

207 Id. at 60. 

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. 

213 Illinois Commerce Commission at 8. 

214 Id. at 7. 

215Minnesota PUC at 1. 

216Order No. 719, FERC Stats. & Regs. ¶ 31,281 

at P 424. 

217The 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). 

218Order No. 719, FERC Stats. & Regs. ¶ 31,281 

at P 423. 

expressed concern that the MMU not be 

diverted from its primary MMU duties 

by requests for information and analysis 

from State actors. 

149. In the Final Rule, the 

Commission declined to change its longstanding policy of maintaining the 

confidentiality of MMU referrals to 

Commission staff. Illinois Commerce 

Commission contends there would be 

no disincentive to companies to selfreport 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

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. 

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

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

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 fourmonth 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

155. Minnesota PUC supports the 

request for rehearing by the Illinois 

Commerce Commission in its 

entirety.215

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

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

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 

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219 Id. P 383–87. 

220 Id. P 385. 

221Potomac Economics at 1. 

222 Id. 

223 Id. at 6–7. 

224 Id. at 2. 

225 Id. at 3. 

226 Id. at 5. 

227 Id. 

228The 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. 

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. 

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

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

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

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

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

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 

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229Market Monitoring Units in Regional 

Transmission Organizations and Independent 

System Operators, 111 FERC ¶ 61,267 (2005). 

230Order No. 719, FERC Stats. & Regs. ¶ 31,281 

at P 556–57. 

231 Id. P 515. 

232APPA–CMUA at 41 (citing APPA NOPR 

Comments at 97–103). 

233 Id. at 40–43. 

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. 

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. 

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: 

• 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. 

• 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. 

• 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. 

• 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, costbenefit 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. 

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 costbenefit 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

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 

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234TAPS at 67 (citing 2008 GAO Report). See 

supra note 129. 

235TAPS at 67. 

236SMUD at 9. 

237 Id. at 11. 

238Pennsylvania PUC at 7. 

239Order No. 719, FERC Stats. & Regs. ¶ 31,281 

at P 505. 

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). 

241See infra, note 254. 

242See Cal. Indep. Sys. Operator Corp. v. FERC, 

372 F.3d 395 (D.C. Cir. 2004). 

243Order No. 719, FERC Stats. & Regs. ¶ 31,281 

at P 534. 

244Regional 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). 

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

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

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

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

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. 

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

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

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-fitsall 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

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 

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245Order 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. 

247 Illinois Commerce Commission at 9. 

248Promoting 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). 

249Pennsylvania PUC at 9. 

250 Industrial Coalitions at 17. 

251Ohio PUC at 19; Wisconsin PSC at 3. 

252Order No. 719, FERC Stats. & Regs. ¶ 31,281 

at P 534–37. 

253 Id. P 537. 

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. 

255Order No. 719, FERC Stats. & Regs. ¶ 31,281 

at P 556. 

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

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

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

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

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. 

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. 

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. 

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

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 

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Federal Register / Vol. 74, No. 144 / Wednesday, July 29, 2009 / Rules and Regulations 37801 

256APPA at 44–45. 

257TAPS at 60–62. 

1See 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). 

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

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 

ferconlinesupport@ferc.gov, or the 

Public Reference Room at (202) 502– 

8371, TTY (202) 502–8659. E-mail the 

Public Reference Room at 

public.referenceroom@ferc.gov. 

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. 

■ 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 

■ 1. The authority citation for part 35 

continues to read as follows: 

Authority: 16 U.S.C. 791a–825r, 2601– 

2645; 31 U.S.C. 9701; 42 U.S.C. 7101–7352. 

■ 2. In § 35.28, paragraph (g)(1)(iii) is 

revised as follows: 

§ 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. 

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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