128 FERC ¶ 61,059 

UNITED STATES OF AMERICA 

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 

(Issued July 16, 2009) 

AGENCY: Federal Energy Regulatory Commission. 

ACTION: 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, 73 FR 61,400 (Oct. 28, 2008), FERC Stats. 

& Regs. ¶ 31,281 (2008), which amended Commission regulations to improve the 

operation of organized wholesale electric markets in four areas: (1) demand response, 

including pricing during periods of operating reserve shortage; (2) long-term power 

contracting; (3) market-monitoring policies; and (4) the responsiveness of RTOs and 

ISOs to their customers and other stakeholders. This order denies in part and grants in 

part rehearing and clarification regarding certain provisions of Order No. 719. 

EFFECTIVE DATE: This order on rehearing will become effective on [Insert date 30 

days after publication in the Federal Register].
Docket No. RM07-19-001 - 2 - 

FOR FURTHER INFORMATION CONTACT: 

Russell Profozich (Technical Information) 

Office of Energy Market Regulation 

Federal Energy Regulatory Commission 

888 First Street, N.E. 

Washington, D.C. 20426 

Russell.Profozich@ferc.gov

(202) 502-6478 

Tina Ham (Legal Information) 

Office of the General Counsel 

Federal Energy Regulatory Commission 

888 First Street, N.E. 

Washington, D.C. 20426 

Tina.Ham@ferc.gov

(202) 502-6224 

SUPPLEMENTARY INFORMATION:
UNITED STATES OF AMERICA 

FEDERAL ENERGY REGULATORY COMMISSION 

Wholesale Competition in Regions with Organized 

Electric Markets 

Docket No. RM07-19-001 

ORDER NO. 719-A 

ORDER ON REHEARING 

TABLE OF CONTENTS

Paragraph Numbers

I. Introduction .................................................................................................................... 1.

A. Summary of Order No. 719...................................................................................... 2.

B. Requests for Rehearing .......................................................................................... 10.

II. Discussion................................................................................................................... 13.

A. Demand Response and Pricing during Periods of 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.
Docket No. RM07-19-001 ii 

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 
128 FERC ¶ 61,059 

UNITED STATES OF AMERICA 

FEDERAL ENERGY REGULATORY COMMISSION 

Before Commissioners: Jon Wellinghoff, Chairman; 

 Suedeen G. Kelly, Marc Spitzer, 

 and Philip D. Moeller. 

Wholesale Competition in Regions with Organized 

Electric Markets 

Docket No. RM07-19-001 

ORDER NO. 719-A 

ORDER ON REHEARING 

(Issued July 16, 2009) 

I. Introduction

1. On October 17, 2008, the Commission issued a Final Rule1

 establishing reforms to 

improve the operation of organized wholesale electric power markets2

 and amended its 

regulations under the Federal Power Act (FPA) in the areas of: (1) demand response, 

including pricing during periods of operating reserve shortage; (2) long-term power 

contracting; (3) market-monitoring policies; and (4) the responsiveness of RTOs and 

 1 Wholesale Competition in Regions with Organized Electric Markets, Order 

No. 719, 73 FR 64,100 (Oct. 28, 2008), FERC Stats. & Regs. ¶ 31,281 (2008) (Order 

No. 719 or Final Rule). 

2

 Organized market regions are areas of the country in which a regional 

transmission organization (RTO) or independent system operator (ISO) operates dayahead and/or real-time energy markets. The following Commission-approved RTOs and 

ISOs have organized markets: PJM Interconnection, L.L.C. (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). 
Docket No. RM07-19-001 2 

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 day-ahead market; (3) in certain circumstances, permit an aggregator 

of retail customers (ARC) to bid demand response on behalf of retail customers directly 

into the organized energy market; and (4) modify their market rules, as necessary, to 

allow the market-clearing price, during periods of operating reserve shortage, to reach a 

 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). 
Docket No. RM07-19-001 3 

 

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 

4

 Order No. 719, FERC Stats. & Regs. ¶ 31,281 at P 4, 15. 

5 Id. P 274. 

6

 The use of the phrase “board of directors” herein also includes the board of 

managers, board of governors, and similar entities. An internal MMU in a hybrid 

structure may report to management so long as it does not perform any of the core MMU 

functions. 
Docket No. RM07-19-001 4 

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. 
Docket No. RM07-19-001 5 

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 Commission; Coalition of 

Midwest Transmission Customers, NEPOOL Industrial Customer Coalition, and PJM 

Industrial Customers Coalition (collectively, Industrial Coalitions); Minnesota Public 

 7

 Order No. 719, FERC Stats. & Regs. ¶ 31,281 at P 2. 

8 Id. P 14. 

9 Id. P 8, 578-83. 
Docket No. RM07-19-001 6 

 

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 

10 Additionally, 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. 

12 See, e.g., City of Campbell v. FERC, 770 F.2d 1180, 1183 (D.C. Cir. 1985)

(“The 30-day time requirement of [the FPA] is as much a part of the jurisdictional 

threshold as the mandate to file for a rehearing.”); Boston Gas Co. v. FERC, 575 F.2d 

975, 977-98, 979 (1st Cir. 1978) (describing identical rehearing provision of the Natural 

Gas Act as “a tightly structured and formal provision. Neither the Commission nor the 

courts are given any form of jurisdictional discretion.”). 
Docket No. RM07-19-001 7 

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 C.F.R. 

§ 385.713(d)(1) (2008), prohibits answers to requests for rehearing. Accordingly, we 

reject PJM’s motion to respond to requests for rehearing and Joint Petitioners’ answer to 

PJM’s motion. 

II. Discussion

A. Demand Response and Pricing during Periods of Operating Reserve 

Shortages in Organized Markets

1. Ancillary Services Provided by Demand Response Providers

13. The Final Rule required each RTO or ISO to accept bids from demand response 

resources, on a basis comparable to any other resources, for ancillary services that are 

acquired in a competitive bidding process, if the demand response resources: (1) are 

technically capable of providing the ancillary service and meet the necessary technical 

requirements; and (2) submit a bid under the generally-applicable bidding rules at or 

below the market-clearing price, unless the laws or regulations of the relevant electric 

retail regulatory authority do not permit a retail customer to participate. All accepted 

 13 See, e.g., Arkansas Power & Light Co., 19 FERC ¶ 61,115 at 61,217-18, reh'g 

denied, 20 FERC ¶ 61,013, at 61,034 (1982). See also Public Serv. Co. of New 

Hampshire, 56 FERC ¶ 61,105, at 61,403 (1991); CMS Midland, Inc., 56 FERC ¶ 61,177, 

at 61,623 (1991). 
Docket No. RM07-19-001 8 

bids would receive the market-clearing price.14 The Commission determined that these 

requirements would remove barriers to the comparable treatment of demand-side and 

supply-side resources. 

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 

 14 Order No. 719, FERC Stats. & Regs. ¶ 31,281 at P 47. 

15 Id. P 56. 
Docket No. RM07-19-001 9 

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 

 16 Pennsylvania PUC at 4. 

17 Order No. 719, FERC Stats. & Regs. ¶ 31,281 at P 276. 

18 Id. P 154. 
Docket No. RM07-19-001 10 

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 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 

 19 Id. P 163. 

20 See, e.g., TAPS at 9-13; Joint Petitioners at 18-23; NARUC at 3. NARUC 

states that it incorporates by reference the arguments presented on this issue by Joint 

Petitioners’ request for rehearing. NARUC at 5. 

21 16 U.S.C. 824(a). 

22 TAPS at 11-12; Joint Petitioners at 18-19 (citing United States v. Public Utils. 

Comm’n of California, 345 U.S. 295, 303 (1953); Federal Power Comm’n v. Southern 

California Edison Co., 376 U.S. 202, 216 (1964)). 

23 Joint Petitioners at 19. 
Docket No. RM07-19-001 11 

ion 

A. 

 

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 Commiss

has no jurisdiction to require such affirmative action because it is beyond the scope of its

legal authority set out in the FP

20. Additionally, TAPS argues that states’ and relevant electric retail regulatory 

authorities’ laws and regulations do not grant retail customers either the title or a contract 

right to resell retail electricity (or any such non-consumption). In that respect, TAPS 

argues that the Final Rule intrudes into retail electric service rates by requiring RTOs and 

ISOs to accept demand response bids that may be prohibited by state law, without first 

obtaining confirmation that such transactions are permitted by the relevant electric retail 

24 TAPS at 12-13 (citing N.Y. v. FERC, 535 U.S. 1, 20 (2002); FPC v. Conway 

Corp., 426 U.S. 271, 276-77 (1976)). 

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)). 
Docket No. RM07-19-001 12 

 

regulatory authority. Joint Petitioners also note that Congress acknowledged that state 

and local regulation extends to such consumption decisions when it directed state 

regulators and non-regulated utilities to consider implementing demand response 

programs at the state and local level in 2007 amendments to the Public Utility Regulatory 

Policies Act (PURPA).26 Further, they argue that the Commission failed to explain how 

it has jurisdiction over the demand response programs of public power systems and 

cooperatives that are not public utilities, and are therefore exempt, under FPA section 

201(f), from the Commission’s FPA section 206 authority27 Joint Petitioners contend 

that the Commission cannot “indirectly” claim jurisdiction over non-jurisdictional 

entities.28

26 Section 532 of the Energy Independence and Security Act of 2007 amended 

PURPA section 111(d) by adding a new standard that requires consideration of rate 

design modifications to promote energy efficiency investments. 16 U.S.C. 2621(d). To 

assist in this effort, Joint Petitioners note that APPA and NRECA commissioned a 

reference manual regarding the new requirements. Reference Manual and Procedures for 

Implementation of the PURPA Standards in the Energy Independence and Security Act 

of 2007, Dr. Ken Rose and Michael Murphy, available at 

http://www.naruc.org/Publications/EISAStandardsManualFINAL.pdf. Joint Petitioners 

argue that efforts to have distribution cooperatives or public power distribution systems 

invest in a demand response program after considering these new federal PURPA 

standards could be undermined by the activities of third-party ARCs seeking to take the 

demand response of the public power or cooperative system’s retail customers directly to 

the wholesale market. Joint Petitioners at 21. 

27 16 U.S.C. 824(f). Joint Petitioners at 21 (citing Bonneville Power 

Administration, et al. v. FERC, 422 F.3d 908, 915 (9th Cir. 2005). 

28 Joint Petitioners state that the “Commission cannot bootstrap jurisdiction over . . 

. . non-jurisdictional entities simply by pointing to jurisdiction over their retail 

customers” and that the Commission “cannot do indirectly what it cannot do directly.” 

Joint Petitioners at 21 (citing Richmond Power & Light v. FERC, 574 F.2d 610, 620 

(continued) 
Docket No. RM07-19-001 13 

 

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 

(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)). 

29 Ohio PUC at 6-7 (stating that “it is the prerogative of each individual state 

commission to decide to what extent it will expose its retail customers to the wholesale 

market, and what, if any, advanced technology (i.e., smart meters) its retail customers 

desire and wish to purchase”). 

30 Id. at 6. The Wisconsin PSC states that it adopts Ohio PUC’s arguments on this 

issue. Wisconsin PSC at 2. NARUC states that it incorporates by reference the 

arguments presented on this issue by Ohio PUC’s request for rehearing. NARUC at 5. 

31 Joint Petitioners at 15-16. 
Docket No. RM07-19-001 14 

 

response while still respecting the state and local retail regulatory authorities. Similarly, 

TAPS urges the Commission to modify the opt-out structure of the ARC requirements by 

changing it to an opt-in structure to remedy the jurisdictional defect and to avoid undue 

burden to small relevant electric retail regulatory authorities.32 TAPS argues that such 

modifications would invite relevant electric retail regulatory authorities to contact the 

RTO or ISO to provide the necessary notification. Joint Petitioners and TAPS state that 

absent a notification that permission has been granted, the RTO or ISO should presume 

that sales of demand response in RTO or ISO markets are not permitted. 

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 customers and ARCs should be required 

32 Specifically, TAPS suggests that the Commission modify the regulatory text to 

replace: (1) the “unless” clause of 18 C.F.R. § 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 C.F.R. § 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, 

(continued) 
Docket No. RM07-19-001 15 

 

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 commission-approved 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 

for each network resource identified for designation, that: (1) the transmission customer 

owns or has committed to purchase the designated network resource; and (2) the 

designated network resource meets the requirements for designated network resources. 

Preventing Undue Discrimination and Preference in Transmission Service, Order 

No. 890, FERC Stats. & Regs. ¶ 31,241, order on reh’g, Order No. 890-A, FERC Stats. & 

Regs. ¶ 31,261 (2007), order on reh’g, Order No. 890-B, 123 FERC ¶ 61,299 (2008).

34 AEP at 1. 
Docket No. RM07-19-001 16 

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 

 35 Id. at 2. 

36 Id. at 2-3. 

37 NARUC states that it incorporates by reference the arguments presented on this 

issue by Joint Petitioners’ request for rehearing. NARUC at 5. 
Docket No. RM07-19-001 17 

 

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 

38 TAPS at 25-26. 

39 For example, Joint Petitioners note that CMUA explained in its NOPR 

comments that the presumption of implicit authority to allow ARCs to aggregate bids 

makes no sense in California because direct access was suspended following the 2000-01 

market crisis. Accordingly, California no longer has laws or regulations dealing with 

new direct access, and CMUA has not restructured its retail rules and ordinances with 

retail choice as an option. Therefore, Joint Petitioners state that to now require an 

affirmative action would be a substantial undertaking. Joint Petitioners at 16-17. 

40 TAPS notes that its members include: (1) AMP-Ohio, serving 123 municipal 

electric systems in Midwest ISO and PJM; (2) Indiana Municipal Power Agency, serving 

51 municipal electric systems in Midwest ISO and PJM; and (3) Wisconsin Public Power, 

serving 50 municipal electric systems in Midwest ISO. TAPS at 26. 
Docket No. RM07-19-001 18 

(RFA).41 Joint Petitioners assert that the reasoning underlying this certification is invalid 

and therefore seeks 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 

 41 5 U.S.C. 601-12. 

42 Joint Petitioners at 23. 

43 TAPS at 26-27. 

44 American Trucking Ass’ns v. EPA, 175 F.3d 1027, 1044 (D.C. Cir. 1999), aff’d 

in part and rev’d in part sub nom. Whitman v. American Trucking Ass’ns, 531 U.S. 457 

(2001). 
Docket No. RM07-19-001 19 

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 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 

 45 TAPS at 28. TAPS states that the Final Rule “requires [load-serving entities] to 

either: (1) invest in the legislative and/or regulatory procedures necessary to obtain an 

explicit ‘out’ and enforce it; . . . . or (2) undertake the implementation burdens necessary 

to accommodate ARCs and retail customers directly bidding retail demand response into 

wholesale markets.” Id.

46 Id. at 29. 

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. 
Docket No. RM07-19-001 20 

 

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. 

48 Joint Petitioners at 28-29. 

49 TAPS at 30. 
Docket No. RM07-19-001 21 

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-serving-entity-administered demand response 

programs. It asks the Commission to clarify that the Final Rule’s ARC requirement 

would not undermine or require any changes to existing aggregation programs that 

already function well.51

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 

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

51 Id. at 14-15. 
Docket No. RM07-19-001 22 

 

planning and aggregation and average cost rates when they do not want to lower their 

consumption while wholesale prices are high. 

35. TAPS argues that the Commission’s attempt to direct demand response into the 

RTO’s or ISO’s wholesale energy and ancillary services markets will cause load-serving 

entities to lose the planning benefits that a load-serving-entity-administered demand 

response program would normally provide. The load-serving entity would need to 

include in its planning for firm power supply the full loads of its retail customers who sell 

into wholesale markets or contract with ARCs, as well as carry full planning reserves to 

meet that load. Thus, TAPS asserts, the value to the load-serving entity and its other 

customers of avoiding peak block generation investments and additional reserves would 

be lost.52

36. Similarly, Joint Petitioners note that many public power systems and cooperatives 

have effectively acted as ARCs for their retail customers. This benefits customers 

because these not-for-profit entities pass on any savings from demand response measures 

to their customers in the form of lower rates. Joint Petitioners conclude that ARCs’ 

activities would undercut the demand response regimes their public power systems and 

cooperatives already have in place or are developing by cherry-picking the demand 

response potential of specific retail customers, and reducing the savings to the customers 

of the public power system accruing from such programs.53 Also, they contend that 

52 Id.

53 Joint Petitioners at 14-15. 
Docket No. RM07-19-001 23 

 

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 nonconsumption at high spot prices, the Final Rule changes the financial calculation for retail 

customers considering demand response. TAPS claims that this reduces load-serving 

entities’ or customers’ incentives to make the capital investments necessary to achieve 

significant, permanent reductions in electricity usage, in favor of short-term, peak-hour 

reductions that garner premium payments from ARCs and the wholesale market.55 TAPS 

argues that the load-serving entity’s loss of control over its retail customers’ demand 

response could impair the load-serving entity’s ability to plan for its load and harness that 

demand response to reduce the costs of serving all of its customers. 

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 

54 Id. at 15. 

55 TAPS at 17. 
Docket No. RM07-19-001 24 

 

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 the amount of energy that those retail demand responders 

would otherwise have consumed. Consequently, this could result in deviation charges for 

load-serving entities for failure to accurately schedule their load. TAPS argues that, if 

ARC-aggregated load causes an unexpected drop in a load-serving entity’s load, the loadserving 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, 

56 Id. at 18. 

57 TAPS provides the following example to explain “phantom energy”: 

[I]f a [transmission-dependent entity] with 100 MW of 

metered load in a given hour has a retail customer that has 

sold 5 MW of demand response energy into the RTO’s 

energy imbalance market in that same hour, then to avoid 

double-counting the demand response that is already reflected 

in the [load-serving entity’s] metered load, the RTO would 

charge the [load-serving entity] for 105 MWh of energy – i.e.

as if the 5 MWh of demand response energy had been 

purchased by the [load-serving entity], delivered to the retail 

customer, and then re-sold. 

Id. at 19-20. 

58 Id. at 22. TAPS notes that such a deviation charge may not apply during an 

emergency, as provided elsewhere in Order No. 719. 
Docket No. RM07-19-001 25 

 

triggered by unexpected, market-price driven demand response, could impose over- and 

under-scheduling charges on a load-serving entity under the SPP’s tariff.59

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 loadserving 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 

59 Id. (citing Southwest Power Pool, FERC Electric Tariff, Fifth Revised Volume 

No. 1, Attachment AE, sections 5.3 and 5.4). 

60 Id.
Docket No. RM07-19-001 26 

incur significant costs to design brand-new systems to accommodate, track, and verify 

demand response. Therefore, it asks that the Commission require RTOs and ISOs to 

evaluate the efficacy of ARC-based demand response programs, especially given the 

adverse impacts on load-serving-entity-administered demand response programs, and to 

implement them only if that evaluation demonstrates that the benefits outweigh the 

costs.61

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 

 61 Id. at 22-23. 

62 Order No. 719, FERC Stats. & Regs. ¶ 31,281 at P 594; NOPR, FERC Stats. & 

Regs. ¶ 32,628 at P 83. 
Docket No. RM07-19-001 27 

 

activities (and we will answer these arguments in turn), they all include the same basic 

issue: whether the Commission has jurisdiction to make rules requiring the RTOs and 

ISOs to accept demand response bids. 

43. Section 201(b) of the FPA confers jurisdiction on the Commission over the 

transmission of electric energy in interstate commerce, and sales of electric energy at 

wholesale in interstate commerce.63 Sections 205 and 206 of the FPA confer upon the 

Commission the responsibility to ensure that rates and charges for transmission and 

wholesale power sales by public utilities, including any rule, regulation, practice or 

contract affecting them, are just and reasonable and not unduly discriminatory or 

preferential.64 While FPA sections 201(f) and 201(b)(2) make clear that the 

Commission’s authorities under Part II of the FPA do not apply to governmental entities 

and certain electric cooperatives, except as specifically provided, the Commission’s 

regulation of the organized markets operated by RTOs and ISOs (which are public 

utilities) nevertheless affects governmental and cooperative entities that participate in 

those markets. 

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

64 Section 205(a) of the FPA charges the Commission with ensuring that rates and 

charges for jurisdictional sales by public utilities and “all rules and regulations affecting 

or pertaining to such rates or charges” are just and reasonable. Id. 824d(a). Section 

206(a) gives the Commission authority over rate and charges by public utilities for 

jurisdictional sales as well as “any rule, regulation, practice or contract affecting such 

rates and charges” to make sure that they are just and reasonable and not unduly 

discriminatory or preferential. Id. 824e(a). 
Docket No. RM07-19-001 28 

 

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 D.C. 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] 

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). 

66 See, e.g., City of Cleveland v. FERC, 773 F.2d 1368, 1376 (D.C. Cir. 1985) 

(“[T]here is an infinitude of practices affecting rates and service . . . . It is obviously left 

to the Commission, within broad bounds of discretion, to give concrete application to this 

amorphous directive.”). 

67 Connecticut Dep’t of Public Util. Control v. FERC, No. 07-1375, slip op. at 

14-15 (D.C. Cir. June 23, 2009). 
Docket No. RM07-19-001 29 

 

did was help to find the right price, it would still amount to a ‘practice ... affecting 

rates’” for purposes of Commission authority.68 

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 resource69 and as a resource during system emergencies,70 to allow 

wholesale buyers and qualifying large retail buyers to bid demand response directly into 

the day-ahead and real-time energy markets and certain ancillary services markets, 

particularly as a provider of operating reserves, as well as programs to accept bids from 

ARCs.71 

68 Id. at 15. The court further stated that “[w]here capacity decisions about an 

interconnected bulk power system affect [Commission]-jurisdictional transmission rates 

for that system . . . they come within the Commission’s authority,” adding that “there is 

nothing special about capacity decisions that places them beyond the Commission’s 

jurisdiction”. Id. at 14-15. 

69 See, e.g., PJM Interconnection, L.L.C., 117 FERC ¶ 61,331 (2006); Devon 

Power L.L.C., 115 FERC ¶ 61,340, order on reh’g, 117 FERC ¶ 61,133 (2006). 

70 See, e.g., New York Indep. Sys. Operator, Inc., 95 FERC ¶ 61,136 (2001); 

NSTAR Services Co. v. New England Power Pool, 95 FERC ¶ 61,250 (2001); New 

England Power Pool and ISO New England, Inc., 100 FERC ¶ 61,287, order on reh’g,

101 FERC ¶ 61,344 (2002), order on reh'g, 103 FERC ¶ 61,304, order on reh'g, 

105 FERC ¶ 61,211 (2003); PJM Interconnection, L.L.C., 99 FERC ¶ 61,139 (2002). 

71 See, e.g., New York Indep. Sys. Operator, Inc., 95 FERC ¶ 61,223 (2001); New 

England Power Pool and ISO New England, Inc., 100 FERC ¶ 61,287, order on reh'g,

101 FERC ¶ 61,344 (2002), order on reh'g, 103 FERC ¶ 61,304, order on reh'g, 

105 FERC ¶ 61,211 (2003); PJM Interconnection, L.L.C., 99 FERC ¶ 61,227 (2002). 
Docket No. RM07-19-001 30 

 

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 

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

73 NOPR, FERC Stats. & Regs. ¶ 32,628 at P 29. 

74 Id. P 30. Increasing the presence of demand response also provides market 

participants with better information about where they should and should not construct 

upgrades. “In current market contexts, constructing new generation facilities in response 

to a higher [installed capacity requirement] may even feel like an imperative. But 

petitioners have posited no source for that feeling other than internalization of the true 

costs of the alternatives, which is not only a requirement for efficient market outcomes, 

but, again, something the Commission may concededly pursue.” Connecticut Dep’t of 

Public Util. Control v. FERC, No. 07-1375, slip op. at 11 (D.C. Cir. June 23, 2009). 

75 NOPR, FERC Stats. & Regs. ¶ 32,628 at P 31. 
Docket No. RM07-19-001 31 

 

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 

76 For example, “[b]y reducing electricity demand at critical times (e.g., when a 

generator or a transmission line unexpectedly fails), demand response that is dispatched 

by the system operator on short notice can help return electric system (or localized) 

reserves to pre-contingency levels.” Federal Energy Regulatory Commission, 

Assessment of Demand Response and Advanced Metering: Staff Report, Docket 

No. AD06-2-000, at 11 (Aug. 2006) (2006 FERC Staff Demand Response Assessment); 

see also Federal Energy Regulatory Commission, Assessment of Demand Response and 

Advanced Metering: Staff Report, at 50-53 (Dec. 2008) (describing the use of demand 

response during system emergencies in 2007 to ensure system reliability). 

77 Where a provision or term directly affects a wholesale rate, it is within the 

Commission’s jurisdiction. See, e.g., Connecticut Dep’t of Public Util. Control v. FERC, 

No. 07-1375, slip op. at 10 (D.C. Cir. June 23, 2009) (finding that the Commission has 

jurisdiction to directly or indirectly establish prices for capacity even for the purposes of 

incentivizing construction of new generation facilities); Mississippi Industries v. FERC, 

808 F.2d 1525 (D.C. Cir. 1987), vacated in part on other grounds, 822 F.2d 1103 (D.C. 

Cir. 1987) (holding that the Commission had jurisdiction over the allocation of a nuclear 

plant’s capacity and costs because it “directly affects costs and, consequently, wholesale 

rates.”); Municipalities of Groton v. FERC, 587 F.2d 1296, (D.C. Cir. 1978); Cal. Indep. 

Sys. Operator Corp., 119 FERC ¶ 61,076, at P 540-56 (2007) (finding that maintaining 

adequate resources falls within Commission jurisdiction because it has a direct and 

significant effect on wholesale rates and services); ISO New England, Inc., 119 FERC 

¶ 61,161, at P 18-30 (2007) (same). 
Docket No. RM07-19-001 32 

 

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 

78 Order No. 719, FERC Stats. & Regs. ¶ 31,281 at P 3; NOPR, FERC Stats. 

& Regs. ¶ 32,628 at P 282. 
Docket No. RM07-19-001 33 

 

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 million MWh cutoff for purposes of granting 

waivers from Order No. 889’s80 standards of conduct for transmission providers81 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 

79 The RFA definition of “small entity” refers to the definition provided in the 

Small Business Act, which defines a “small business concern” as a business that is 

independently owned and operated and that is not dominant in its field of operation. See

5 U.S.C. 601(3), citing to Section 3 of the Small Business Act, 15 U.S.C. 632. The Small 

Business Size Standards component of the North American Industry Classification 

system defines a small utility as one that, including its affiliates is primarily engaged in 

the generation, transmission, or distribution of electric energy for sale, and whose total 

electric output for the preceding fiscal year did not exceed 4 million MWh. 13 CFR 

121.202 (Sector 22, Utilities, North American Industry Classification System (NAICS)) 

(2004). 

80 Open Access Same-Time Information System and Standards of Conduct, Order 

No. 889, FERC Stats. & Regs. ¶ 31,035, clarified, 77 FERC ¶ 61,253 (1996), order on 

reh’g, Order No. 889-A, FERC Stats. & Regs. ¶ 31,049, reh’g denied, Order No. 889-B, 

81 FERC ¶ 61,253 (1997), aff’d in relevant part sub nom. Transmission Access Policy 

Study Group v. FERC, 225 F.3d 667 (D.C. Cir. 2006). 

81 See Wolverine Power Supply Coop., 127 FERC ¶ 61,159, at P 15 (2009). 

82 See San Diego Gas & Elec. Co. v. Sellers of Energy and Ancillary Services in 

Markets Operated by the CAISO, 125 FERC ¶ 61,297, at P 24 (2008). 
Docket No. RM07-19-001 34 

and 

s that 

 

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 

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 ARC

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 

(continued) 

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 
Docket No. RM07-19-001 35 

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] 

 

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. 

86 EPAct 2005, section 1252(f) (emphasis added). 
Docket No. RM07-19-001 36 

54. We recognize that demand response is a complex matter that is subject to the 

confluence of state and federal jurisdiction. The Final Rule’s intent and effect are neither 

to encourage or require actions that would violate state laws or regulations nor to classify 

retail customers and their representatives as wholesale customers, as Ohio PUC asserts. 

The Final Rule also does not make findings about retail customers’ eligibility, under state 

or local laws, to bid demand response into the organized markets, either independently or 

through an ARC. The Commission also does not intend to make findings as to whether 

ARCs may do business under state or local laws, or whether ARCs’ contracts with their 

retail customers are subject to state and local law. Nothing in the Final Rule authorizes a 

retail customer to violate existing state laws or regulations or contract rights. In that 

regard, we leave it to the appropriate state or local authorities to set and enforce their own 

requirements. 

55. Finally, with regard to AEP’s request for clarification, we note that this proceeding 

is a very narrowly-focused rule, as discussed above. The clarification that AEP is 

seeking involves state laws and regulations, and how they are interpreted in relation to 

the policies contained in this proceeding. It is not within the scope of this rulemaking to 

interpret individual state laws and regulations. 

ii. Burden on Small Entities and Regulatory 

Flexibility Analysis

56. In regard to arguments concerning the burden of this rule on small entities and the 

need for RFA analysis, we reiterate that the Final Rule does not require a relevant electric 

retail regulatory authority to make any showing or to take any action in compliance with 
Docket No. RM07-19-001 37 

s 

at RTOs 

nd 

ew 

he 

 

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 RTO

and ISOs.89 

57. TAPS and Joint Petitioners contend that the Commission’s requirement th

and ISOs accept bids from ARCs makes it imperative for relevant electric retail 

regulatory authorities to decide whether ARCs within their jurisdiction may offer dema

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 n

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 t

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 

87 Order No. 719, FERC Stats. & Regs. ¶ 31,281 at P 155. 

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

89 Order No. 719, FERC Stats. & Regs. ¶ 31,281 at P 155, 602. 
Docket No. RM07-19-001 38 

lack 

rs of 

is 

 presumption would be reversed: the RTO or ISO would 

 version of 

e 

 

require the RTO or ISO to impose on retail regulators the task of communicating this 

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 regulato

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 th

size requirement, however, the

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

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) th

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 

90 See discussion supra P 51. 
Docket No. RM07-19-001 39 

pt 

t 

bid 

il 

d 

ll utilities 

 to 

e state and local laws and 

 

response to be bid into organized markets by an ARC. RTOs and ISOs may not acce

bids from ARCs that aggregate the demand response of: (1) the customers of utilities tha

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 

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 reta

regulatory authority permits such customers’ demand response to be bid into organize

markets by an ARC. Our adoption of a modified version of APPA’s alternative 

proposale provides that relevant electric retail regulatory authorities of sma

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

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 Whil

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”). 
Docket No. RM07-19-001 40 

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 

because the states, not EPA, had direct authority to impose regulations on small 

EPA’s rule did not have a direct impact on small entities. Accordingly, based on it

holding in 

that 

entities, 

s 

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. 

 

American Trucking Associations 93 , 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”). 
Docket No. RM07-19-001 41 

iled 

proposal. 

r 

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 deta

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 

64. Each RTO or ISO is required to submit, within 90 days of the date that this orde

on rehearing is published in the Federal Register, a compliance filing with the 

Commission, proposing am

existing tariffs and market design complies with the revisions adopted herein. 

iii. Effect on Existing Demand Response Programs and 

endments to its tariffs or otherwise demonstrating how its 

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 Petition

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 pric

ers 

es for all customers and maintaining reliability at a lower cost then would 

 95 Order No. 719, FERC Stats. & Regs. ¶ 31,281 at P 154. 
Docket No. RM07-19-001 42 

d a 

n 

il 

ers 

nd that petitioners’ arguments are speculative; they 

f 

 

have been the case if the RTO or ISO had instead dispatched a resource that submitte

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 Commissio

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 reta

customers are permitted to participate in wholesale markets via ARCs. Also, petition

have not shown why the issues they raise cannot be adequately addressed by each RTO 

and ISO through the stakeholder process and included as part of the RTO’s or ISO’s 

compliance filing.96 As a result, we fi

have not persuaded us that the policy decisions made in the Final Rule were the result o

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 

96 The Final Rule provided regional flexibility for each RTO and ISO to work with 

its stakeholders in proposing market rules appropriate for its region. Id. P 155. Interested 

parties could participate in that stakeholder process. By filing comments on the RTO’s or 

ISO’s subsequent compliance filing, interested parties had an additional opportunity to 

address the Commission directly on any remaining concerns with the RTO’s or ISO’s 

implementation proposal. The Commission will address the merits of such 

implementation issues on a case-by-case basis. 
Docket No. RM07-19-001 43 

 

ely 

isting 

s 

re for the 

ic 

 in 

y 

 so, whether and how to permit such participation. 

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 affirmativ

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 ex

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’

ARC requirement. This is not the proper forum to address these issues, which a

relevant electric retail regulatory authority to consider. It is up to the relevant electr

retail regulatory authorities, if they so choose, to decide whether existing retail 

aggregation programs provide benefits and whether retail customer participation

wholesale demand response programs, individually or through an ARC, would adversel

affect those programs and, if

Therefore, TAPS and Joint Petitioners may raise these issues with the relevant electric

retail regulatory authority. 
Docket No. RM07-19-001 44 

, 

y 

he 

o 

lled 

urce in 

, we direct each RTO and ISO to submit a 

 

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 entit

may buy too much power if its retail customer bids in demand response and the loadserving entity is unaware of the bid, creating an over-scheduling penalty for the loadserving 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 t

like. We will require each RTO or ISO, through the stakeholder process, to develop 

appropriate mechanisms for sharing information about demand response resources t

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 enro

to participate, either individually or through an ARC, as a demand response reso

an RTO or ISO market and the expected level of that participation for each enrolled 

demand response resource.97 Finally

97 TAPS requested, among other things, that we direct the RTO or ISO to provide 

certain detailed information in real-time to affected load-serving entities. TAPS has 

failed to demonstrate the need for such data in real-time. 
Docket No. RM07-19-001 45 

ed 

ead 

. In 

ork 

ders to discuss and resolve concerns, including demonstrating net 

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 organiz

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-ah

market, as well as metering, billing, settlement, information sharing and verification 

measures to be submitted in an RTO’s or ISO’s compliance filing ordered above. 

71. We again reject the argument that the Commission should require RTOs and ISOs 

to evaluate the efficacy of ARC-based demand response programs given the costs 

involved in modifying systems to accommodate bids by retail customers and the adverse

impact on load-serving entity administered programs. As stated above, RTOs and ISOs, 

in conjunction with their stakeholders, including ARCs and load-serving entities, are in 

the best position to decide whether to incur the costs of conducting such an analysis

recognition of regional differences, the Final Rule directed each RTO and ISO to w

with its stakehol
Docket No. RM07-19-001 46 

Commission.

3. Market Rules Governing Price Formation during Periods of Operating 

benefits of its program and to address these issues in its compliance filing with the 

98

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, 

by 

ng 

ts 

 

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 

requiring RTOs and ISOs to reform their market rules in such a way that prices duri

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 reflec

the value of energy during an operating reserve shortage.101 Each RTO or ISO may 

98 Order No. 719, FERC Stats. & Regs. ¶ 31,281 at P 159. 

99 Id. P 192. 

100 Id. 

101 Id. P 194. 
Docket No. RM07-19-001 47 

ents 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

 

propose in its compliance filing one of four suggested approaches 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 requirem

 is not protracted. 

102 The four approaches are: (1) RTOs and ISOs would increase the energy supply 

and demand bid caps above the current levels only during an emergency; (2) RTOs and 

ISOs would increase bid caps above the current level during an emergency only for 

demand bids while keeping generation bid caps in place; (3) RTOs and ISOs would 

establish a demand curve for operating reserves, which has the effect of raising prices in a 

previously agreed-upon way as operating reserves grow short; and (4) RTOs and ISOs 

would set the market-clearing price during an emergency for all supply and demand 

response resources dispatched equal to the payment made to participants in an emergency 

demand response program. Id. P 208. 

103 The six criteria are: (1) improve reliability by reducing demand and increasing 

supply during periods of operating reserve shortages; (2) make it more worthwhile for 

customers to invest in demand response technologies; (3) encourage existing generation 

and demand resources to continue to be relied upon during an operating reserve shortage; 

(4) encourage entry of new generation and demand resources; (5) ensure that the 

principle of comparability in treatment of and compensation to all resources is not 

discarded during periods of operating reserve shortage; and (6) ensure market power is 

mitigated and gaming behavior is deterred during periods of operating reserve shortages 

including, but not limited to, showing how demand resources discipline bidding behavior 

to competitive levels. Id. P 246-47. 
Docket No. RM07-19-001 48 

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 perio

when bidders could exercise market power; that customers do not yet have in place 

tools to respond to price; that there is not sufficient market m

ds 

the 

itigation in place to ensure a 

 state 

not 

They state that given the existing market power problems in 

 Joint 

 

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

that any higher prices during operating reserve shortages would reflect market power, 

efficient shortage pricing.104 

organized markets, raising price caps can result in prices that are inefficiently high. 

Petitioners note that, in concluding that market power will be adequately mitigated 

through the shortage pricing requirement, the Commission ignored contrary evidence 

from APPA and NRECA.105

 104 Joint Petitioners at 32-33. 

105 Id. at 44 (citing NRECA Affidavit at P 20-55). 
Docket No. RM07-19-001 49 

r 

s from high prices.106 In light of 

 response 

ort-run 

nstitutes 

plained departure from its precedent.108 It states that the 

Commission has previously established that demand response technologies are 

 

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 offe

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 themselve

contrary evidence, TAPS contends that the Commission must provide evidence that 

consumers will be able to protect themselves from high prices through demand

programs. For instance, TAPS states that existing evidence indicates that the sh

demand curve for electricity is highly inelastic.107 

77. SMUD argues that the Commission’s decision to lift price and bid caps co

an arbitrary and unex

106 TAPS at 33 (citing TAPS NOPR Comments at 24-27). 

107 Id. at 39.

108 For example, SMUD explains that in NYISO, the Commission imposed a bid 

cap based on its finding that the NYISO market lacks demand-side responsiveness to 

prices and that it has tight supplies. Id. at 5. (citing New York Indep. System Operator, 

97 FERC ¶ 61,154, at 61,673 (2001)). SMUD also adds that the Commission previously 

found that price caps are necessary to prevent opportunistic pricing during periods of 

capacity shortages and that bid caps provide a safety net to contain prices in peak periods 

when supply is short. SMUD at 4. (citing ISO New England, Inc., 97 FERC ¶ 61,090, at 

62,469, 61,470-471 (2001)). 
Docket No. RM07-19-001 50 

higher and 

ns. In 

 Joint Petitioners 

ct as a 

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 

more volatile prices actually become a key factor in capital deployment decisio

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 onesided markets cannot be protected from the exercise of market power.112

also argue that the Final Rule wrongly concluded that demand response itself will a

 109 Id. at 4. (citing Nstar Serv. Co. v. New England Power Pool, 92 FERC 

¶ 61,06

8. 

5, at 62,198-99 (2000)). 

110 Joint Petitioners at 41. 

111 Industrial Coalition at 7-

112 Pennsylvania PUC at 5. 
Docket No. RM07-19-001 51 

s 

kett; 

e Commission take up the issue of 

 

market power mitigation measure based on a faulty assumption that end-use customer

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 mar

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 construc

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 th

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 

oners at 48-49. 

 4. 

113 Joint Petiti

114 Old Dominion at
Docket No. RM07-19-001 52 

g 

ds until market power concerns are alleviated and the market 

er 

d ISO 

. 

n 

ine an operating reserve shortage as falling short of meeting the operating 

reserve requirements under the reliability standards approved by the Commission under 

 

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 raisin

bid caps only for demand bi

for demand response is more fully developed.116

82. Joint Petitioners note that if the Commission is serious about including consum

protections, including meaningful market power mitigation mechanisms in RTO an

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 Commissio

intended to def

115 Id. at 5-6. 

116 Ohio PUC at 7. 

117 They note that the Commission never addressed APPA’s request for full 

evidentiary hearings. Id. at 49 (citing APPA NOPR Comments at 54-55, 62, 64). 
Docket No. RM07-19-001 53 

FPA section 215, e 

 to 

s

118

 yet the regulatory text provides a definition without referring to thes

reliability standards. Therefore, it suggests that the Commission revise the definition

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 Requirement

mmission failed to consider evidence presented by 

rding the defects 

r; 

 

84. Several petitioners requested rehearing of the Commission’s shortage pricing

approaches on grounds that the Co

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 rega

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 powe

(2) are premised on unsupported assumptions about bidding behavior and consumers; 

118 Order No. 719, FERC Stats. & Regs. ¶ 31,281 at P 251. 

9

 TAPS at 54-56. 11
Docket No. RM07-19-001 54 

m NOPR comments, including those provided by 

ity 

erits of 

es to 

ing 

price bid by demand response resources; however, generators would receive the highest 

capped p generating resources needed to clear the market.123 TAPS states that 

 

(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 fro

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 reliabil

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 realtime or long-term markets.122

87. Joint Petitioners and TAPS argue that the Final Rule failed to discuss the m

NRECA’s alternative approach, which was to allow only demand response resourc

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 clear

rice bid by 

 

120 Id. at 42-45. 

121 Joint Petitioners at 35 (citing Order No. 719, FERC Stats. & Regs. ¶ 31,2

P 235). 

81 at 

122 Id. at 41. 

123 Id. at 49-50 (citing NRECA NOPR Comments at 29). 
Docket No. RM07-19-001 55 

ate this approach.124 Joint Petitioners argue that the Commission acted 

sult in 

ule 

re 

nt 

nce 

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 accommod

arbitrarily and capriciously in failing to consider NRECA’s detailed arguments and 

evidence which they claim show that the four shortage pricing approaches will re

unjust and unreasonable rates and charges, not the beneficial results that the Final R

anticipates. 

88. Joint Petitioners assert that generator resources and demand response resources a

not similarly situated and, therefore, it is not unjust and unreasonable or unduly 

discriminatory under the FPA to compensate them differently. According to Joi

Petitioners, during generation scarcity, generators already make all of their generation 

resources available to the market; hence, they can take no additional actions to bala

supply and demand. However, they assert that demand response resources are able to 

 

 TAPS states that the Final Rule’s regulatory text language in section 

35.28(g)(1)(iv)(A) would preclude an RTO or ISO from proposing the NRECA appro

or any other beneficial demand response program. Thus, it requests the following 

modifications: 

124

ach 

Commission-approved ISOs and RTOs must modify their market rules to allow 

(1) the market-clearing price during periods of operating reserve shortage to reach 

a level that rebalances supply and demand or (2) payments to demand response 

resources. In either case, the rules must so as tomaintain reliability while 

ions for mitigating market power. 

TAPS at 48 (citing TAPS NOPR Comments at 3). 

providing sufficient provis
Docket No. RM07-19-001 56 

same price to be paid to 

ket 

o contend that the Commission 

and provide accountability.128

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 Co not provide a reasoned basis for rejecting PG&E’s proposed criteria. 

 

take further action to balance supply and demand by reducing their demand.125 

Therefore, the comparability principle does not require that the

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 mar

power and unjust and unreasonable rates.126 They als

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 

mmission did

ioners at 42. 125 Joint Petit

126 Id. at 51-52. 

127 Id. at 53. 

128 Id. at 49. 
Docket No. RM07-19-001 57 

sed 

92. sion vacate the relevant criteria and 

It adds that the Commission’s failure to require any accountability for the costs impo

by the Final Rule’s shortage pricing requirements is contrary to the GAO Report’s 

recommendations.129 

Joint Petitioners request that the Commis

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 th

Final Rule were the result of error. We therefore affirm our finding in the Final Rule th

existing RTO and ISO market rules that do not allow for prices to rise sufficiently durin

an operating reserve shortage to allow supply to meet deman

e 

at 

g 

d 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 

 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. 
Docket No. RM07-19-001 58 

es. 

esponse, deter new entry of demand response and generation 

may be 

nt 

igate 

technical conferences 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 shortag

The Commission determined that such inaccurate prices during an emergency may harm

reliability, inhibit demand r

131

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 

unduly discriminatory.133

95. We disagree with the arguments that the Final Rule’s shortage pricing requireme

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 mit

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 

 

 The Commission held three technical conferences in 2007 to gather informatio

and address issues on competition at the wholesale level and other related issues. 

131 n 

See

NOPR, FERC Stats. & Regs. ¶ 32,628 at P 2. 

132 Order No. 719, FERC Stats. & Regs. ¶ 31,281 at P 192; NOPR, FERC Stats. 

& Regs. ¶ 32,628 at P 107. 

133 Order No. 719, FERC Stats. & Regs. ¶ 31,281 at P 192. 
Docket No. RM07-19-001 59 

RTO or ISO also is free to propose other pricing 

on by 

inate 

y and 

generation by providing opportunities for a higher return on investment – and the entry of 

 

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 

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 exploitati

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 elim

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 technolog

134 Id. P 195. 

135 Id. P 235. 
Docket No. RM07-19-001 60 

for measuring demand elasticity or for evaluating the impact 

s 

es,

ortage can 

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 

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 barrier

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 pric

137 and second that even a relatively small amount of demand response in a sh

lower market prices significantly for all customers. 

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

137 For example, a critical peak pricing experiment in California in 2004 

determined that small residential and commercial customers are price responsive and will 

produce significant demand reductions. Participants in the California peak pricing 

experiment reduced demand by 13 percent on average and by as much as 27 percent 

when price signals were coupled with automated controls, such as controllable 

thermostats. 2006 FERC Staff Demand Response Assessment at 13. 
Docket No. RM07-19-001 61 

 realourage development of demand 

s 

s 

ating shortage 

ill approve 

 

98. Several petitioners assert that customers are not able to respond to prices in

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 enc

response infrastructure. With improved price 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 i

not needed to help cope with operating reserve shortages. Demand response program

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 mand

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 w

the proposals only if they meet the criteria established in the Final Rule. 

138 Order No. 719, FERC Stats. & Regs. ¶ 31,281 at P 196. 
Docket No. RM07-19-001 62 

e 

ngle number that applies to every system, the Commission found that it 

r 

f 

ring 

to determine the justness and reasonableness of each RTO’s and ISO’s shortage pricing 

 

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 th

reliability standards depend on the characteristic of each system and cannot be correctly 

reduced to a si

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 fo

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 o

this request. 

101. We reject Joint Petitioners’ request that we require by rule an evidentiary hea

139 Id. P 251. 
Docket No. RM07-19-001 63 

s have now had an opportunity to comment on 

the RTOs’ and ISOs’ compliance filings, and the Commission will determine on a caseents

proposal. We find that at this stage it is premature to establish a requirement for such 

evidentiary hearings. All concerned partie

by-case basis whether evidentiary hearings are warranted.. We reject Joint Petitioners’ 

request to vacate the rulemaking provisions on shortage pricing and institute a new 

rulemaking. We find that the Joint Petitioners have not provided any new arguments or 

evidence that would warrant such action. 

ii. Four Shortage Pricing Approaches and Criteria Requirem

e 

Final 

 with their 

uring 

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 

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 advers

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 

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

customers and other stakeholders, to establish an approach to shortage pricing d

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 
Docket No. RM07-19-001 64 

ach that the 

o 

that 

d 

four approaches will 

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 appro

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 t

the Commission, provided it satisfies the requirements in the Final Rule. 

104. With regard to NRECA’s alternative approach for pricing reform, we reiterate 

the Final Rule did not mandate any specific approach to shortage pricing. It presente

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 

result in unreasonable rates and charges. Such analysis is most appropriately left to the 

 140 Id. P 247. 

141 Id. P 235. 

142 Order No. 719, FERC Stats. & Regs. ¶ 31,281 at P 194-95. 

143 Id. P 195. 
Docket No. RM07-19-001 65 

g 

teria. 

he need to adopt an additional 

 for 

ity, 

coordi e readiness of 

 

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 revisin

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 cri

For example, the Commission noted that the criteria already included an analysis of 

market power mitigation and, therefore, did not see t

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

designing a shortage pricing approach that addresses market power, accountabil

gaming behavior, and 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 

nated with other key market mechanisms; and (3) an assessment of th

719, FERC Stats. & Regs. ¶ 31,281 at P 239, 249-50. 144 Order No. 

145 Id. P 249. 
Docket No. RM07-19-001 66 

 of 

 of these 

 that the 

xist for 

arket power and deterring gaming behavior . . . [, which] could include, but 

havior to 

the demand response programs that will be called on to reduce the number and severity

shortage pricing requirements and help to mitigate market power.146 While each

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

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 e

mitigating m

is not limited to, the use of demand resources to discipline bidding be

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 

electric energy on a long-term basis. The Commission noted that this requirement w

designed to improve 

sell 

as 

transparency in the contracting process so as to encourage long-term 

 146 Id. P 244. 

147 Id. P 196. 
Docket No. RM07-19-001 67 

contracting for electric power. uests for rehearing were timely filed with respect to 148 Req

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 long-term 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 intereste

in long-term bilateral contracts. The absence of a hedging mechanism for marg

losses, SMUD states, is a significant risk factor in

d 

inal 

 long-term contracting. SMUD notes 

tha uire, RTOs and ISOs to develop such 

 

t the Commission encouraged, but did not req

hedging mechanisms. It argues that this encouragement is not sufficient, and that the 

148 Id. P 307. 

149 Id.
Docket No. RM07-19-001 68 

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 requireme

marginal loss hedging instrument in Order No. 681.

nt for a 

uest in 

 in 

n 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, 

 

151

152

153

154

 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. The Commission again addressed SMUD’s req

the order conditionally approving revisions to CAISO’s Market Redesign and 

Technology Upgrade Tariff provisions involving congestion revenue rights. 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

workable form elsewhere. I

150

rm Firm Transmission Rights in Organized Electricity Markets

 SMUD at 7. 

151 Long-Te , Order 

No. 681, FERC Stats. & Regs. ¶ 31,226, order on reh'g, Or

(2006). 

der No. 681-A, 117 FERC 

¶ 61,201 

 Indep. Sys. Operator Corp.

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

153 Cal. , 120 FERC ¶ 61,023, at P 229 (2007), reh’g 

denied, 124 FERC ¶ 61,094 (2008). 

154 Id.
Docket No. RM07-19-001 69 

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 & 

Pa sociation.156 per Association and Portland Cement As 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 

st and 

 

of this proceeding to investigate the issue of whether RTO markets are producing ju

 Supplemental Notice of Technical Conference, Capacity Markets in Regions 

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

156

with Organized Electric Markets, Docket No. AD08-4-000 (April 25, 2008). 
Docket No. RM07-19-001 70 

ower 

ceeding was limited to four 

t 

s 

 

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 p

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 pro

“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 technical conference held on May 7, 2008, but tha

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 rate

UA at 3. 157 APPA-CM

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)). 
Docket No. RM07-19-001 71 

ent 

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 rec

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 

t 

and 

ce in the record from wholesale 

le 

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 a

the many comments, statements, studies and affidavits in the docket alleging unjust 

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 eviden

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 demonstrab

benefits to wholesale customers and consumers.163

 160 Id. at 26 (citing Order No. 2000, FERC Stats & Regs at 31,043 n.163). 

161 549 U.S. 497 (2008). 

162 APPA-CMUA at 28. 

163 Id. at 32 (citing 2008 GAO Report). See supra note 129. 
Docket No. RM07-19-001 72 

e 

at these 

A 

t the 

s it is going to be difficult to finance new generation facilities in the future 

wi

requires. 

 

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 th

RTO system. However, the Commission declined to order any of the broader measures 

commenters suggested. APPA-CMUA argue that the Commission’s statement th

structural issues were beyond the scope of the proceeding was a non sequitur, since the 

Commission itself had set the scope of the proceeding. They note the Commission’s 

apparent belief that there is no fundamental problem with long-term contracts, that 

contracts are merely available at higher prices than in the past. However APPA-CMU

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 tha

current turmoil in the credit markets should cause the Commission to reconsider its 

decision, a

thout 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 

164 Id. at 34-36. 
Docket No. RM07-19-001 73 

b. Commission Determination

117. We find that the Commission did not violate the standards of due process or shirk 

f 

 on 

this 

its duty under the FPA in confining the scope of this proceeding to four specific areas o

reform related to the operation of competitive wholesale markets. We deny rehearing

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 

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 E

on greenhouse gases, and did not overturn the general rule that agencies have discretion

over how to act to carry out their responsibilities.

PA action 

that the 

 

166 The Supreme Court found 

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 

 165 See Chevron U.S.A. Inc. v. NRDC, 467 U.S. 837, 842-845 (1984). 

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

167 Id. at 530. 
Docket No. RM07-19-001 74 

 

holesale electric 

f the proceeding that the Commission itself set. 

t 

as 

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 w

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 o

If the Commission was obligated to frame every investigation to satisfy commenters’ 

requests, individual commenters would have the power to delay or derail nascent marke

rules with which they disagreed merely by arguing that the scope of the proceeding w

 168 See 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. 
Docket No. RM07-19-001 75 

t 

g-term 

n 

ve. 

etermining 

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. 

 

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 no

indicate that the Commission refuses to act in other areas to ensure just and reasonable 

rates. For example, the Commission has acted on 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 lon

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 o

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 abo

Contrary to the claims of APPA-CMUA, the Commission considered all of the 

comments, statements, studies and affidavits received in this docket when d

170 See Order No. 719, FERC Stats. & Regs. ¶ 31,281 at P 280. 

171 For instance, the Commission recently held a technical conference on credit 

issues affecting the electric power industry. Technical Conference on Credit and Capital 

Issues D09-2-000 (Jan. 13, 2009). 

28 at P 16-25. 

Affecting the Electricity Power Industry, Docket No. A

172 NOPR, FERC Stats. & Regs. ¶ 32,6
Docket No. RM07-19-001 76 

to promote competition in wholesale 

s 

122. The Commission’s policy continues to be 

electric power markets. This policy is in keeping with Commission practice and wa

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 

f 

ed 

s of the 

ff by 

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 o

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 need

to perform its duties; required the RTO or ISO to set out the expanded function

MMU in its tariff; removed the MMU from tariff administration and modified MMU 

market mitigation functions; prescribed protocols for the referral to Commission sta

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

 173 Pub. L. No. 109-58, 119 Stat. 594. 

174 Order No. 719, FERC Stats. & Regs. ¶ 31,281 at P 317 et seq. 
Docket No. RM07-19-001 77 

e 

 in addition to the annual state of the market report, to expand the 

U and 

l 

e 

rification were timely filed with respect to the 

nt in market mitigation, the relationship between the 

125. Within the area of information sharing, the Final Rule required the MMU to mak

quarterly reports

recipients for the reports, and to hold regular telephone conferences among the MM

Commission staff, RTO or ISO staff, interested state commissions, state attorneys genera

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 th

RTO or ISO.175

126. Requests for rehearing or cla

following issues: MMU involveme

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 NOP

MMUs should be removed from market mitigation. That proposal had been desi

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 influe

the market by conducting mitigation. However, a number of commenters objected that 

there might be a greater conf

R that 

gned to 

ncing 

lict of interest in having the RTO or ISO administer 

 175 Id. P 395 et seq.
Docket No. RM07-19-001 78 

MU 

long as 

nal Rule provided that if the RTO or ISO does not have 

a h to perform retrospective mitigation, while 

U 

mitigation, as it has a vested interest in accommodating its market participants. 

Commenters raised a number of other objections, including the arguments that the M

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 structure176 may permit its internal MMU to conduct mitigation, so 

its external MMU is assigned the task of monitoring the quality and appropriateness of 

that mitigation. In addition, the Fi

ybrid structure, it may still allow its MMU

relegating prospective mitigation to itself. The Final Rule further provided that the MM

could provide the inputs required by the RTO or ISO for prospective mitigation, 

including the determination of reference levels, the identification of system constraints, 

calculation of costs, and the like. 

 176 A hybrid MMU structure is one with both an internal and an external market 

monitor. An internal market monitor is one that is composed of RTO or ISO employees, 

an external market monitor is an independent entity that conducts market monitoring for 

the RTO or ISO pursuant to a contract. 
Docket No. RM07-19-001 79 

a. Requests for Rehearing 

129. Old Dominion objects to the removal of prospective mitigation from non-hybr

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

from the RTOs conducting

id 

 arising 

 mitigation on what are, in effect, their own customers.177 

 should not have removed tariff 

t. 

 rectifying abuses of market power.180 

 

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

administration and mitigation from the duties of the MMU, arguing that although the 

Commission intended to strengthen market monitoring, it achieved the opposite effec

They advance the opinion that RTOs and ISOs have demonstrated a preference for 

unmitigated outcomes, and therefore should not be given total responsibility for 

identifying and

 177 Old Dominion at 6-7. 

178 Pennsylvania PUC at 5-6. 

179 Id. at 3. 

180 Industrial Coalitions at 12-14. 
Docket No. RM07-19-001 80 

132. t to what they see as the internal MMU 

essary 

The Ohio PUC and Wisconsin PSC objec

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 nec

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 MM

must opine on the quality of its own mitigation when it reports on the health and state o

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

U 

f 

 on the well-known tendency of human nature to see one’s own actions 

 

in a favorable light. Furthermore, contrary to that same petitioner’s assertion, the 

Commission did take into account the argument that RTOs and ISOs have conflicts of 

their own in conducting mitigation. That consideration was, in fact, part of the basis for 

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

182 Ohio PUC at 15. 
Docket No. RM07-19-001 81 

nal 

ere 

ission is of the view that the more objective the criteria for mitigation become, 

nce. 

e, 

he 

ISO 

permitting a substantial degree of mitigation to be performed by the MMUs, both inter

and external.183 

134. Pennsylvania PUC claims that mitigation is non-discretionary, and concludes th

is no danger of a conflict of interest influencing the MMU in conducting mitigation.184 

The Comm

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 evide

Other factors can have the opposite effect on an RTO’s or ISO’s decision to mitigat

such as achieving price moderation, ensuring the orderly and fair administration of t

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 

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. 

 183

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

184 Pennsylvania PUC at 3. 
Docket No. RM07-19-001 82 

 Rule’s mitigation provisions provide that the 

te the performance 

bly 

e 

e 

U 

market mitigation. 

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

external MMU in a hybrid MMU structure must independently evalua

of the internal MMU, if the latter conducts mitigation. Thus, the external MMU argua

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 balanc

between unfettered MMU mitigation and no mitigation by the MMU. Therefore, w

affirm the Final Rule in this regard and decline to grant rehearing on the issue of MM

involvement in 

2. Relationship Between Internal and External MMU

ht 

mitigation.185 

 

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 lig

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 

 

9, FERC Stats. & Regs. ¶ 31,281 at P 374. 185 Order No. 71
Docket No. RM07-19-001 83 

a. Requests for Rehearing

139. Ohio PUC questions the efficacy of a hybrid MMU, and proposes that an ex

market monitor’s evaluations and recommendations should prevail over those of 

internal MMU. It proposes that mitigation authority not be vested in the internal MMU,

presumably because

ternal 

the 

 it believes that the internal MMU lacks independence.186 Ohio PUC 

e 

Ohio PUC argues that the Final Rule results in a dysfunctional MMU 

hie rdinate to any new internal MMU and 

s that 

a 

 

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 th

effective operation of the MMU, and delegate them to the external or independent 

MMU.188 

rarchy that will make the existing MMU subo

the RTO or ISO.189

140. Wisconsin PSC supports in their entirety the requests of Ohio PUC. It assert

the Commission erred in supposedly vesting more authority in the internal MMU in 

hybrid structure than in the external MMU, and in failing to clarify that all MMU rules 

13. 186 Ohio PUC at 

187 Id. at 13-16. 

188 Id. at 16-17. 

189 Id. at 14. We assume here that “existing MMU” means an external MMU. 
Docket No. RM07-19-001 84 

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 predicat

the notion that an internal MMU necessarily lacks independence. However, as we 

observed in the Final Rule, we have not detected any deficiency in

ed on 

 performance by 

t 

formance of the markets, and 

internal MMUs that is attributable to their structure.191 Furthermore, the proposition tha

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 per

making 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 

 190 Wisconsin PSC at 2-3. 

191 Order No. 719, FERC Stats. & Regs. ¶ 31,281 at P 327. 
Docket No. RM07-19-001 85 

n the external MMU. As 

rnal MMU within a hybrid structure 

ly 

t 

sue 

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 tha

noted above, mitigation may be assigned to the inte

only if the external MMU is given the tools and responsibility to monitor it, thus arguab

giving the external MMU greater authority than the internal MMU. As to other marke

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 is

of the relationship between external and internal MMUs. 

3. State Access to MMU Information

 of 

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 

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

providing a means by which state commissions can request tailored information from the
Docket No. RM07-19-001 86 

fidentiality 

l. 

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 con

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 confidentia

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 wou

time consuming and burdensome. Illinois Commerce Commission also arg

Commission should not restrict the dissemination of raw data, or for

ld be 

ues that the 

bid state 

co ement activities, as 

atter 

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 

 

193

mmissions from obtaining information from MMUs for state enforc

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 m

concerning market conduct to the Commission. Illinois Commerce Commission argues 

192 Id. P 446-59. 

mmission at 4-5. 193 Illinois Commerce Co

194 Id. 
Docket No. RM07-19-001 87 

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. ile 

t 

tion violates confidentiality restrictions 

ts 

ill be at 

he 

197 Wh

the information sought in tailored requests for information should relate to general marke

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 informa

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 i

core functions. Subject to these limitations, granting or refusing such requests w

the MMU’s discretion, based on agreements worked out between the RTO or ISO and t

 195 Id. at 2-4. 

196 Minnesota PUC at 1. 

197 Order No. 719, FERC Stats. & Regs. ¶ 31,281 at P 446-59. 
Docket No. RM07-19-001 88 

mission respectfully disagrees that the confidentiality provisions of the 

f the 

oses, 

ffect, citing the agency’s own 

aching 

l 

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 Com

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 o

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 purp

the Commission provided evidence in the record to that e

long experience with investigations.199 Furthermore, it would be difficult if not 

impossible to provide information tailored for enforcement purposes without bre

confidentiality, as such information would be directed toward the activities of individua

market participants. As to raw data, the Commission did not forbid an MMU from 

 198 State 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. 
Docket No. RM07-19-001 89 

uming, 

l Rule, the Commission declined to change its long-standing policy of 

elfublic, because MMU referrals do not occur as a result 

in the 

ith an 

investigation.

 

providing raw data (properly redacted for confidentiality purposes), but stated that if the

gathering, organizing, reviewing, and explaining of such data would be too cons

the MMU was not required to provide it.200 This is a subset of the Commission’s 

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 Fina

maintaining the confidentiality of MMU referrals to Commission staff. Illinois 

Commerce Commission contends there would be no disincentive to companies to s

report if such referrals were made p

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 

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 w

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. 

200 Id. P 450. 

201 Id. P 465. 
Docket No. RM07-19-001 90 

4. Offer and Bid Data

151. In the Final Rule, the Commission shortened the period for release of offer and b

data to three months, while retaining the policy of masking the identity of the 

participants. The Final Rule also incorporated flexibility by allowing RTOs and ISOs 

propose a shorter release time or, if they could demonstrate a danger of collusion, a fou

month instead of a three-month release, or some alternative mechanism if release of a 

id 

to 

r202

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, 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, and 

contends that information transparency can play a role in the potential mitigation of 

collusion. TAPS theorizes that the early release of data levels the playing field for 

 

203

204

205

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

203 TAPS at 56. 

204 Id. at 57. 

205 Id. at 58. 
Docket No. RM07-19-001 91 

6

 and 

f the identity of bidders, and disclosure of system 

g of 

ill not 

 that requiring the filing of system lambdas would allow 

di in comparison to the relevant underlying 

smaller market participants and enables them to assist with market monitoring,

207

153. APPA-CMUA, in a joint filing, support the immediate and full disclosure of offer 

and bid data, the unmasking o

20

argues that greater transparency may help expose attempts to manipulate the market.

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 unmaskin

identities, APPA-CMUA argue that although the Commission provided that RTOs and 

ISOs may propose a period when such unmasking might be permitted, this w

happen because generators will argue against such disclosure in the stakeholder 

process.

211 They further argue

rect analysis of RTO and ISO real-time prices

variable generation costs.212

 206 Id. at 59. 

Id. 207 at 60. 

mbda” is defined as the variable cost of the last kilowatt produced 

over a particular hour. APPA-CMUA at 39. 

209

208 “System la

Id. at 15-16. 

210 Id. at 37-38. 

211 Id. at 38. 

212 Id. at 39. 
Docket No. RM07-19-001 92 

e 

four-month lag, asserting that this time lag would eliminate 

154. Illinois Commerce Commission objects to the Commission’s continuation of th

policy of masking the identities of market participants, and proposes as an alternative that

identities be unmasked after a 

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 be

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.

st for 

d 

t implicitly suggests, 

 

216

157. APPA-CMUA contend that generators would object to such a proposal, and woul

be able to sway the stakeholder process against it. This argumen

213

214

 Illinois Commerce Commission at 8. 

Id. at 7. 

215 Minnesota PUC at 1. 

216 Order No. 719 ̧ FERC Stats. & Regs. ¶ 31,281 at P 424. 
Docket No. RM07-19-001 93 

f 

tion in the stakeholder 

rds flexibility in the area of the masking of identities 

r and bid data, by providing that RTOs and ISOs may 

 for 

s flexibility 

egional 

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 o

another entity. Since the various stakeholders have different concerns and interests, 

balancing those concerns is more suited to exploration and resolu

process than in this proceeding, at least in the first instance.217 

158. Likewise, the Final Rule affo

of market participants placing offe

propose a period for the eventual unmasking of such identities.218 Again, this allows

a balancing of interests in the stakeholder process. The Commission built thi

into its determinations in the area of offer and bid data both to take into account r

 

 The fact that ISO-NE proposed reducing the lag time for release of offer and

bid data from six months to three months is evidence of the fact that the stakeholder 

217

process is not necessarily geared toward less disclosure. See ISO New England Inc. and 

New England Power Pool, 121 FERC ¶ 61,035 (2007). 

218 Order No. 719, FERC Stats. & Regs. ¶ 31,281 at P 423. 
Docket No. RM07-19-001 94 

 in 

f 

aring 

f offer and bid data. 

differences, and to give the industry a chance to work with the release period mandated

the Final Rule before deciding whether to propose an even shorter period. Certainly, i

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 rehe

on the issue o

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.

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 

 

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 

 219 Id. P 383-87. 
Docket No. RM07-19-001 95 

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 suc

monitoring does not create a conflict of interest.

h 

e 

 otherwise result from such monitoring.222 Alternatively, Potomac Economics 

 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-

 

221 Potomac Economics contends that th

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

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

220 Id. P 385. 

221 Potomac Economics at 1. 

222 Id. 

223 Id. at 6-7. 

224 Id. at 2. 
Docket No. RM07-19-001 96 

RTO or IS tracts filed with the Commission, which 

d ISOs, and 

TO or 

O monitoring is done pursuant to con

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 an

the monitored entities,226 and would eliminate the improved understanding of the R

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 market participant operating in the 

same RTO or ISO for activity in that RTO or ISO may raise a conflict of interest becaus

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 for

 

e 

th 

225 Id. at 3. 

226 Id. at 5. 

227 Id.
Docket No. RM07-19-001 97 

ng in the 

on 

nt 

g 

oval, and the contract contains 

sion of any intention to terminate 

 for 

t 

or all these reasons, the Commission grants rehearing on this issue and clarifies 

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 operati

same RTO or ISO with our concern over potential conflicts of interest, the Commissi

will permit an RTO or ISO MMU to enter into contracts to monitor a market participa

operating in the same RTO or ISO for activity in that RTO or ISO, under the followin

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 appr

a provision that the entity must notify the Commis

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

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 i

unnecessary to amend the regulatory text promulgated in the Final Rule to reach this 

result. F

 

wh

228 The purpose of this holding is to prevent potential conflicts of interest that arise 

ct 

to oversee the activities of a market participant that operates wholly outside of the RTO 

en the MMU oversees its own actions. Thus, if an MMU wants to enter into a contra

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. 
Docket No. RM07-19-001 98 

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 interpretati

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. Althou

NYISO’s request has been rejected for untimeliness, the Commission finds that it woul

be useful to provide certain clarifications as to when an MMU is to make referrals, 

whether the referral is for suspected wrongdoing or for th

on of 

gh 

d 

e identification of market design 

; 

itoring 

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 Mon

Unit has 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 

 229 Market Monitoring Units in Regional Transmission Organizations and 

Independent System Operators, 111 FERC ¶ 61,267 (2005). 
Docket No. RM07-19-001 99 

aff. If the RTO or 

 of 

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 st

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

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 th

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 F

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.

e 

inal 

Responsiveness of RTOs and ISOs to Customers and Other Stakeholders

uired RTOs and ISOs to establish a means 

ness to these entities. 

The Co ling demonstrating 

that it has in place, or will adopt, practices and procedures to ensure that its board of 

170. In the Final Rule, the Commission req

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’ responsive

mmission required each RTO or ISO to submit a compliance fi
Docket No. RM07-19-001 100 

 will 

y 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

directors is responsive to customers and other stakeholders. The compliance filings

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 timel

171. In the Final Rule, the Commission adopted four criteria from the NOPR for 

s to the RTO’s or ISO’s board 

of directors. 

liberation and consideration of RTO and ISO issues are not 

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 view

• 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 de

dominated by any single stakeholder category. 

 230 Order No. 719, FERC Stats. & Regs. ¶ 31,281 at P 556-57. 
Docket No. RM07-19-001 101 

must 

 on a 

e communicated to the RTO’s or ISO’s board 

• Ongoing Responsiveness - The business practices and procedures must provide for 

stakeholder input into 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. 

re 

• Representation of Minority Positions - The business practices and procedures 

ensure that, in instances where stakeholders are not in total agreement

particular issue, minority positions ar

of directors at the same time as majority positions. 

The Commission found that additional criteria for responsiveness as proposed by 

commenters – for example, cost-benefit analyses or cost-containment procedures – we

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 t

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. APPA suggested 

hat 

 

232

231 Id. P 515. 

232 APPA-CMUA at 41 (citing APPA NOPR Comments at 97-103). 
Docket No. RM07-19-001 102 

ints 

eholder advisory committees and hybrid 

a 

233

ents 

reporting of RTO performance measurements, requiring RTO management compensation 

to be ti budget review 

 

several concrete measures that the Commission should adopt to ensure responsiveness, 

including: direct stakeholder access to RTO boards, presentation of minority viewpo

directly to the board, consideration of stak

boards, open RTO board meetings with agendas disclosed in advance, board member 

attendance at working group/technical meetings where appropriate, elimination of “selfperpetuating” RTO boards, administration of customer satisfaction surveys, development

of cost oversight benchmarking for RTOs, and a moratorium on the establishment of new 

RTO-run markets unless accompanied by an independent cost-benefit analysis or 

affirmative vote of all RTO stakeholder classes. APPA-CMUA argues that because the 

Commission declined to adopt additional measures, customers seeking greater RTO 

responsiveness and accountability will have to participate in RTO stakeholder processes 

with no clear guidance as to what specific measures will satisfy the four general criteri

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.

173. TAPS also notes that the Commission failed to implement specific requirem

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 

ed to consumer-focused performance measures, and an improved

233 Id. at 40-43. 
Docket No. RM07-19-001 103 

ld 

akeholder process mandated in the Final Rule 

Os 

rofit 

he 

175. n erred in failing to require RTOs and 

s 

, 

 

process with advance stakeholder review. TAPS also argued that RTOs should be he

accountable for fulfilling obligations to plan and expand the transmission system to meet 

customers’ needs. TAPS argues that the st

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 RT

for results is distinct from RTO responsiveness. Since RTOs and ISOs are not-for-p

entities, SMUD argues, they cannot be penalized for imprudence. Accordingly, t

Commission should address the need for RTOs and ISOs to adopt performance penalties 

for imprudent decisions by managers.236 

SMUD further argues that the Commissio

ISOs to conduct cost-benefit analyses before implementing major initiatives. It believe

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

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

7. 235 TAPS at 6

236 SMUD at 9. 
Docket No. RM07-19-001 104 

TO 

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 R

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

issue. 

178. The criteria established for responsiveness were intended to balance the need to 

improve RTO

 on this 

s’ and ISOs’ responsiveness to their stakeholders with the development of 

e 

still 

practices that best suit the needs of the individual RTO or ISO.239 We continue to believ

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 

evolving institutions; they and their stakeholders may want to add, remove, or improve 

 237 Id. at 11. 

238 Pennsylvania PUC at 7. 

239 Order No. 719, FERC Stats. & Regs. ¶ 31,281 at P 505. 
Docket No. RM07-19-001 105 

re better 

s 

ion 

cture 

ge each RTO’s and ISO’s 

. 

, we 

w 

d should be the result of a dialogue between RTOs and 

ISOs and their stakeholders rather than Commission mandate. We are interested here in 

 

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 a

addressed through the stakeholder process, where RTOs and ISOs can tailor these idea

to the needs of their regions, and amend them as needed without a change in Commiss

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 stru

their board policies, without being so specific as to micromana

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 costbenefit 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

encouraged interested parties to raise this idea with individual RTOs or ISOs, and allo

the RTO or ISO to work out a policy that is tailored to their needs.240 

180. The specific requirements raised by APPA, TAPS and others represent the end 

point of the policy process, an

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). 
Docket No. RM07-19-001 106 

 or 

l RTOs and ISOs, and does 

ission mandate is necessary or appropriate. Pennsylvania 

or 

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 ma

 

making sure that stakeholders are able to have a productive dialogue with their RTO

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 al

not make the case that a Comm

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 f

performance penalties for managers, we continue to encourage, but not require, that 

executive compensation programs give appropriate weight to responsiveness. As we 

y also be outside the Commission’s jurisdiction.242

 241 See infra, note 254. 

242 See Cal. Indep. Sys. Operator Corp. v. FERC, 372 F.3d 395 (D.C. Cir. 2004). 
Docket No. RM07-19-001 107 

2. Hybrid Boards

183. In the Final Rule, the Commission did not require RTOs or ISOs to adopt 

specific form of board structure, whether board advisory committee, hybrid board

other. The Commission found that a one-size-fits-all approach was not warranted. The 

Commission did note that it viewed the board advisory committee as a particularl

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 ne

a 

, or 

y strong 

eds.243

184. mmission followed its ruling in Order 

ividual 

 

With respect to hybrid boards, the Co

No. 2000,244 in which it noted that RTOs and ISOs take many different forms to reflect

the various needs of 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 ind

market participant is given undue influence over the decisions of the board. The 

 31,281 at P 534. 243 Order No. 719, FERC Stats. & Regs. ¶

244 Regional Transmission Organizations, Order No. 2000, FERC Stats. & Regs. 

¶ 31,089 (1999), order on reh’g, Order No. 2000-A, FERC Stats. & Regs. ¶ 31,092 

(2000), aff’d sub nom. Pub. Util. Dist. No. 1 of Snohomish County, Washington v. 

FERC, 272 F.3d 607 (D.C. Cir. 2001). 

245 Order No. 719, FERC Stats. & Regs. ¶ 31,281 at P 537 (citing Order No. 2000, 

FERC Stats. & Regs. 31,089 at 31,073-75). 
Docket No. RM07-19-001 108 

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 

000. 

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. 888248 and 2

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

 246 Id. 

scriminatory 

247 Illinois Commerce Commission at 9. 

248 Promoting Wholesale Competition Through Open Access Non-Di

Transmission Services by Public Utilities; Recovery of Stranded Costs by Public Utilities 

and Transmitting Utilities, Order No. 888, FERC Stats. & Regs. ¶ 31,036 (1996), order 

on reh’g, Order No. 888-A, FERC Stats. & Regs. ¶ 31,048, order on reh’g, Order 

No. 888-B, 81 FERC ¶ 61,248 (1997), order on reh’g, Order No. 888-C, 82 FERC 

¶ 61,046 (1998), aff’d in relevant part sub nom. Transmission Access Policy Study Group

v. FERC, 225 F.3d 667 (D.C. Cir. 2000), aff’d sub nom. New York v. FERC, 535 U.S. 1 

(2002). 

249 Pennsylvania PUC at 9. 
Docket No. RM07-19-001 109 

nce 

an e independence of its board members, and 

s 

, 

rs 

1

 Determination

186. Industrial Coalitions state that the Commission failed to present adequate evide

that hybrid boards could be appropriately independent and responsive. They argue that 

 RTO’s or ISO’s independence depends on th

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 i

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 stakeholde

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.25

b. Commission

eeting 

 

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 m

250 Industrial Coalitions at 17. 

251 Ohio PUC at 19; Wisconsin PSC at 3. 
Docket No. RM07-19-001 110 

e 

lder members on an RTO or ISO board of 

 for 

e to 

 a 

rough 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 

the four criteria, including through a board advisory committee or a hybrid board.252 Th

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 stakeho

directors. We emphasize that the Final Rule did not repeal any of the requirements

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 acceptabl

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

decision reached by the rest of the board, and that no two classes could force th

result of a thorough stakeholder process. 

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

253 Id. P 537. 
Docket No. RM07-19-001 111 

 require that RTO and ISO boards include one 

ndating 

sta d to all circumstances, and therefore we 

ir 

190. We also deny the requests to

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 ma

te regulatory membership would be suite

prefer to allow RTOs and ISOs the flexibility to propose for Commission approval the

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 

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.

to 

 

255

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 req ate 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. 

ERC Stats. & Regs. ¶ 31,281 at P 556. 

uiring that any particular class of stakeholders, including st

255 Order No. 719, F
Docket No. RM07-19-001 112 

a. Requests for Rehearing

192. Both APPA and TAPS argue that the Commission erred in failing to mand

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 ISOs to provid

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 A

unless it redefines the RTOs’ and ISOs’ mission to include provision of reliable service a

the lowest possible reasonable rates, and requires RTOs and ISOs to meet these go

b.

ate 

e 

ct 

t 

als.257

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, 

ent should explain the mission of an RTO or ISO, as 

an 

existing 

 

that a successful mission statem

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, 

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 

 256 APPA at 44-45.

257 TAPS at 60-62. 
Docket No. RM07-19-001 113 

during the stakeholder process or in response to the RTO or ISO 

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 

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

contents of this document via the 

 and/or print the 

Internet through FERC's Home Page 

(http://www.ferc.gov) and in FERC's Public Reference Room during normal business 

95. From FERC's Home Page on the Internet, this information is available on 

ment is available on eLibrary in PDF and Microsoft 

iewing, printing, and/or downloading. To access this document in 

eLibrary, type the docket number excluding the last three digits of this document in the 

96. User assistance is available for eLibrary and the FERC’s web site during normal 

usiness hours from FERC Online Support at 202-502-6652 (toll free at 1-866-208-3676) 

r email at ferconlinesupport@ferc.gov

hours (8:30 a.m. to 5:00 p.m. Eastern time) at 888 First Street, N.E., Room 2A, 

Washington D.C. 20426. 

1

eLibrary. The full text of this docu

Word format for v

docket number field. 

1

b

o , or the Public Reference Room at (202) 502-

8371, TTY (202)502-8659. E-mail the Public R

ublic.referenceroom@ferc.gov

eference Room at 

p . 
Docket No. RM07-19-001 114 

IV. Effective Date

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

List of

[insert 30 days after publication in the Federal Register]. 

 subjects in 18 CFR Part 35

Electri

Electric power rates 

c Utilities 

Reporting and record keeping requirements 

By the Comm art 

with a separate statement attached. 

 ) 

Nathaniel J. Davis, Sr., 

Deputy Secretary. 

ission. Commissioner Kelly is concurring in part and dissenting in p

( S E A L

 
Docket No. RM07-19-001 115 

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 revis

-

ed as follows: 

, (b)(7), and (b)(8). 

§ 35.28 Non-discriminatory open access transmission tariff

(a) Amend paragraph (b) to add (b)(4), (b)(5), (b)(6)

.

 * * * * * 

(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: (1) the customers 

of utilities that distributed more than 4 million megawatt-hours in the previous fiscal 

year, and (2) 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 
Docket No. RM07-19-001 116 

response of: (1) ion megawatte uthority 

arkets by an 

ggregator of retail customers, or lities that distributed 4 million 

gulat

 the customers of utilities that distributed more than 4 mill

hours in the previous fiscal year, where the relevant electric r tail regulatory a

prohibits such customers’ demand response to be bid into organized m

a (2) the customers of uti

megawatt-hours or less in the previous fiscal year, unless the relevant electric retail 

re ory authority permits such customers’ demand response to be bid into organized 

markets by an aggregator of retail customers. 

* * * * * 
UNITED STATES OF AMERICA 

FEDERAL ENERGY REGULATORY COMMISSION 

Wholesale Competition in Regions with Docket No. RM07-19-001 

 Organized Electric Markets 

(Issued July 16, 2009) 

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.F

1

F 

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 

 

 1 USeeU UWholesale Competition in Regions with Organized Electric MarketsU, 

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).