125 FERC ¶ 61,071 

UNITED STATES OF AMERICA 

FEDERAL ENERGY REGULATORY COMMISSION 

18 CFR Part 35 

(Docket Nos. RM07-19-000 and AD07-7-000) 

Wholesale Competition in Regions with Organized Electric Markets 

(Issued October 17, 2008) 

AGENCY: Federal Energy Regulatory Commission. 

ACTION: Final Rule. 

SUMMARY: In this Final Rule, the Federal Energy Regulatory Commission 

(Commission) is amending its regulations under the Federal Power Act to improve the 

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

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

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

transmission organizations (RTOs) and independent system operators (ISOs) to their 

customers and other stakeholders, and ultimately to the consumers who benefit from and 

pay for electricity services. Each RTO and ISO will be required to make certain filings 

that propose amendments to its tariff to comply with the requirements in each area, or 

that demonstrate that its existing tariff and market design already satisfy the 

requirements. 

EFFECTIVE DATE: This Final Rule will become effective [insert date 60 days after 

publication in the FEDERAL REGISTER]. 
Docket Nos. RM07-19-000 and AD07-7-000 - 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: 
125 FERC ¶ 61,071 

UNITED STATES OF AMERICA 

FEDERAL ENERGY REGULATORY COMMISSION 

Wholesale Competition in Regions with Organized 

Electric Markets 

Docket Nos. RM07-19-000 

AD07-7-000 

FINAL RULE 

Order No. 719 

(Issued October 17, 2008) 

TABLE OF CONTENTS

 Paragraph Numbers

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

II. Background................................................................................................................. 10.

III. Discussion.................................................................................................................. 15.

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

Organized Markets....................................................................................................... 15.

1. Background......................................................................................................... 16.

2. Ancillary Services Provided by Demand Response Resources.......................... 20.

a. Ancillary Services Market.............................................................................. 21.

b. New Bidding Parameters................................................................................ 64.

c. Small Demand Response Resource Assessment............................................ 90.

3. Eliminating Deviation Charges During System Emergencies.......................... 100.

a. Deviation Charges ........................................................................................ 100.

b. Virtual Purchasers ........................................................................................ 122.

4. Aggregation of Retail Customers ..................................................................... 128.

a. Commission Proposal................................................................................... 128.

b. Comments..................................................................................................... 132.

c. Commission Determination.......................................................................... 154.

5. Market Rules Governing Price Formation During Periods of Operating Reserve 

Shortage ................................................................................................................. 165.

a. Price Formation During Periods of Operating Reserve Shortage ................ 169.

b. Four Approaches .......................................................................................... 208.

c. The Commission’s Proposed Criteria........................................................... 238.
Docket Nos. RM07-19-000 and AD07-7-000 ii 

d. Phase-In of New Rules................................................................................. 254.

6. Reporting on Remaining Barriers to Comparable Treatment of Demand 

Response Resources............................................................................................... 259.

a. Comments..................................................................................................... 263.

b. Commission Determination ......................................................................... 274.

B. Long-Term Power Contracting in Organized Markets ........................................ 277.

1. Background....................................................................................................... 278.

2. Commission Proposal ....................................................................................... 283.

3. Comments......................................................................................................... 286.

4. Commission Determination.............................................................................. 301.

C. Market-Monitoring Policies ................................................................................. 310.

1. Background....................................................................................................... 314.

2. Independence and Function .............................................................................. 317.

a. Structure and Tools....................................................................................... 318.

b. Oversight ...................................................................................................... 333.

c. Functions ...................................................................................................... 345.

d. Mitigation and Operations............................................................................ 361.

e. Ethics ............................................................................................................ 380.

f. Tariff Provisions ........................................................................................... 388.

3. Information Sharing.......................................................................................... 395.

a. Enhanced Information Dissemination.......................................................... 395.

b. Tailored Requests for Information............................................................... 425.

c. Commission Referrals .................................................................................. 460.

4. Pro Forma Tariff............................................................................................... 470.

a. Commission Proposal................................................................................... 470.

b. Comments..................................................................................................... 471.

c. Commission Determination.......................................................................... 473.

D. Responsiveness of RTOs and ISOs to Customers and Other Stakeholders......... 477.

1. Background....................................................................................................... 479.

2. Commission Proposal ....................................................................................... 481.

a. Responsiveness Obligation and Proposed Criteria....................................... 481.

3. Comments......................................................................................................... 484.

4. Commission Determination.............................................................................. 501.

5. Board Advisory Committee and Hybrid Board................................................ 516.

a. Comments..................................................................................................... 517.

b. Commission Determination ......................................................................... 534.

6. Supermajority Requirement.............................................................................. 538.

a. Comments..................................................................................................... 539.

b. Commission Determination ......................................................................... 546.

7. Posting Mission Statement or Organizational Charter on Web Site ................ 547.

a. Comments..................................................................................................... 548.
Docket Nos. RM07-19-000 and AD07-7-000 iii 

b. Commission Determination ......................................................................... 556.

8. Executive Compensation .................................................................................. 558.

a. Comments..................................................................................................... 559.

b. Commission Determination ......................................................................... 561.

9. Compliance Filing Requirement....................................................................... 562.

a. Comments..................................................................................................... 563.

b. Commission Determination ......................................................................... 565.

E. Other Comments................................................................................................... 568.

1. Comments......................................................................................................... 568.

2. Commission Determination.............................................................................. 573.

IV. Applicability of the Final Rule and Compliance Procedures.................................. 574.

A. NOPR Proposal .................................................................................................... 574.

B. Comments............................................................................................................. 575.

C. Commission Determination.................................................................................. 578.

V. Information Collection Statement ........................................................................... 584.

VI. Environmental Analysis .......................................................................................... 587.

VII. Regulatory Flexibility Act Certification ................................................................ 588.

A. NOPR Proposal .................................................................................................... 593.

1. Comments......................................................................................................... 596.

2. Commission Determination.............................................................................. 602.

VIII. Document Availability ......................................................................................... 606.

IX. Effective Date and Congressional Notification....................................................... 609.

Regulatory Text 

APPENDIX: Abbreviated Names of Commenters 
UNITED STATES OF AMERICA 

FEDERAL ENERGY REGULATORY COMMISSION 

Before Commissioners: Joseph T. Kelliher, Chairman; 

 Suedeen G. Kelly, Marc Spitzer, 

 Philip D. Moeller, and Jon Wellinghoff. 

Wholesale Competition in Regions with Organized 

Electric Markets 

Docket Nos. RM07-19-000 

AD07-7-000 

FINAL RULE 

Order No. 719 

(Issued October 17, 2008) 

I. Introduction

1. This Final Rule addresses reforms to improve the operation of organized 

wholesale electric power markets.1

 Improving the competitiveness of organized 

wholesale markets is integral to the Commission fulfilling its statutory mandate to ensure 

supplies of electric energy at just, reasonable and not unduly discriminatory or 

preferential rates. Effective wholesale competition protects consumers by providing 

more supply options, encouraging new entry and innovation, spurring deployment of new 

 1

 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 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 Service Operator 

Corp. (CAISO), and Southwest Power Pool, Inc. (SPP). 
Docket Nos. RM07-19-000 and AD07-7-000 - 2 - 

technologies, promoting demand response and energy efficiency, improving operating 

performance, exerting downward pressure on costs, and shifting risk away from 

consumers. National policy has been, and continues to be, to foster competition in 

wholesale electric power markets. This policy was embraced in the Energy Policy Act of 

2005 (EPAct 2005),2

 and is reflected in Commission policy and practice. The 

Commission balances the mix of regulation and competition based on changing 

circumstances, taking into account such factors as the opportunities for competition to 

control market power, advances in technology, changes in economies of scale, and new 

state and federal laws that affect the energy industry. 

2. The Commission has a duty to improve the operation of wholesale power markets. 

To that end, in this Final Rule, the Commission is making reforms to improve the 

operation of organized wholesale electric markets in the areas of demand response, longterm power contracting, market monitoring policies, and RTO and ISO responsiveness. 

By making these reforms, the Commission is not seeking to fundamentally redesign 

organized markets; rather, these reforms are intended to be incremental improvements to 

the operation of organized markets without undoing or upsetting the significant efforts 

that have already been made in providing demonstrable benefits to wholesale customers. 

3. In the areas of demand response and the use of market prices to elicit demand 

response, the Commission is requiring RTOs and ISOs to: (1) accept bids from demand 

response resources in RTOs’ and ISOs’ markets for certain ancillary services on a basis 

 2

 Pub. L. No. 109-58, 119 Stat. 594 (2005). 
Docket Nos. RM07-19-000 and AD07-7-000 - 3 - 

comparable to other resources; (2) eliminate, during a system emergency, a charge to a 

buyer that takes less electric energy in the real-time market than it purchased in the dayahead market; (3) in certain circumstances, permit an aggregator of retail customers 

(ARC)3

 to bid demand response on behalf of retail customers directly into the organized 

energy market; (4) modify their market rules, as necessary, to allow the market-clearing 

price, during periods of operating reserve shortage, to reach a level that rebalances supply 

and demand so as to maintain reliability while providing sufficient provisions for 

mitigating market power; and (5) study whether further reforms are necessary to 

eliminate barriers to demand response in organized markets. 

4. With regard to long-term power contracting, the Commission is requiring RTOs 

and ISOs to dedicate a portion of their web sites for market participants to post offers to 

buy or sell power on a long-term basis. This requirement will promote greater use of 

long-term contracts by improving transparency among market participants. 

5. To improve market monitoring, the Commission is requiring that RTOs and ISOs 

provide their Market Monitoring Units (MMU) with access to market data, resources and 

personnel sufficient to carry out their duties, and that the MMU (or the external MMU in 

a hybrid structure) report directly to the RTO or ISO board of directors.4

 In addition, the 

Commission is requiring that the MMU’s functions include: (1) identifying ineffective 

 3

 We will use the phrase “aggregator of retail customers,” or ARC, to refer to an 

entity that aggregates demand response bids (which are mostly from retail loads). 

4

 Our use of the phrase “board of directors” also includes the board of managers, 

board of governors, and similar entities. 
Docket Nos. RM07-19-000 and AD07-7-000 - 4 - 

market rules and recommending proposed rules and tariff changes; (2) reviewing and 

reporting on the performance of the wholesale markets to the RTO or ISO, the 

Commission, and other interested entities; and (3) notifying appropriate Commission 

staff of instances in which a market participant’s behavior may require investigation. The 

Commission is also expanding the list of recipients of MMU recommendations regarding 

rule and tariff changes, and broadening the scope of behavior to be reported to the 

Commission. 

6. The Commission is also modifying MMU participation in tariff administration and 

market mitigation, requiring each RTO and ISO to include ethics standards for MMU 

employees in its tariff, and requiring each RTO and ISO to consolidate all its MMU 

provisions in one section of its tariff. The Commission is expanding the dissemination of 

MMU market information to a broader constituency, with reports made on a more 

frequent basis than they are now, and reducing the time period before energy market bid 

and offer data are released to the public. 

7. Finally, the Commission establishes an obligation for each RTO and ISO to make 

reforms, as necessary, to increase its responsiveness to customers and other stakeholders 

and will assess each RTO’s or ISO’s compliance using four responsiveness criteria: 

(1) inclusiveness; (2) fairness in balancing diverse interests; (3) representation of 

minority positions; and (4) ongoing responsiveness. 

8. In each of these four areas, the Commission is requiring 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 in this proceeding, or its plans to attain compliance. 
Docket Nos. RM07-19-000 and AD07-7-000 - 5 - 

9. Significant differences exist between regions, including differences in industry 

structure, mix of ownership, sources of electric generation, population densities, and 

weather patterns. Some regions have organized spot markets administered by an RTO or 

ISO, and others rely solely on bilateral contracting between wholesale sellers and buyers. 

We recognize and respect these differences across various regions. At the same time, 

wholesale competition can serve customers well in all regions. The focus of this Final 

Rule is to further improve the operation of wholesale competitive markets in organized 

market regions. 

II. Background

10. The Commission has acted over the last few decades to implement Congressional 

policy to expand the wholesale electric power markets to facilitate entry of new 

generators and to support competitive markets. Absent a single national power market, 

the development of regional markets is the best method of facilitating competition within 

the power industry, and the Commission has made sustained efforts to recognize and 

foster such markets. 

11. In 2007, the Commission held several public conferences to gather information 

and address issues on competition at the wholesale level and other related issues.5

 At 

these conferences, the Commission examined issues affecting competition in the RTO 

and ISO regions, including the levels of wholesale prices, the need for long-term power 

 5

 Three technical conferences were held on February 27, 2007, April 5, 2007, and 

May 8, 2007. 
Docket Nos. RM07-19-000 and AD07-7-000 - 6 - 

contracts, the effectiveness of market monitoring, and the lack of adequate demand 

response. The Commission also addressed concerns related to the RTO and ISO board of 

directors’ responsiveness to their customers and other stakeholders. 

12. On June 22, 2007, the Commission issued an Advance Notice of Proposed 

Rulemaking (ANOPR),6

 identifying four specific issues in organized market regions that 

were not being adequately addressed or were not under consideration in other 

proceedings. These areas were: (1) the role of demand response in organized markets 

and greater use of market prices to elicit demand response during periods of operating 

reserve shortage; (2) increasing opportunities for long-term power contracting; (3) 

strengthening market monitoring; and (4) enhancing the responsiveness of RTOs and 

ISOs to customers and other stakeholders, and ultimately to the consumers who benefit 

from and pay for electricity services. The Commission presented preliminary views on 

proposed reforms for these areas and sought comment on them. 

13. After receiving and considering over a hundred comments on the ANOPR, on 

February 22, 2008, the Commission issued a Notice of Proposed Rulemaking (NOPR).7

 

In the NOPR, pursuant to the Commission’s responsibility under sections 205 and 206 of 

 6

 Wholesale Competition in Regions with Organized Electric Markets, Advance 

Notice of Proposed Rulemaking, FERC Stats. & Regs. ¶ 32,617 (2007). 

7

 Wholesale Competition in Regions with Organized Electric Markets, Notice of 

Proposed Rulemaking, 73 FR 12,576 (March 7, 2008), FERC Stats. & Regs. 

¶ 32,628 (2008). 
Docket Nos. RM07-19-000 and AD07-7-000 - 7 - 

the Federal Power Act (FPA),8

 the Commission proposed reforms in the four specific 

areas identified above that were designed to ensure just and reasonable rates, to remedy 

undue discrimination and preference, and to improve wholesale competition in regions 

with organized markets. As noted in the NOPR, these proposed reforms are intended to 

improve the operation of wholesale competition in organized markets.9

14. In the NOPR, the Commission also noted that the reforms proposed in this 

proceeding do not represent its final effort to improve the functioning of competitive 

organized markets for the benefit of consumers; rather, the Commission will continue to 

evaluate specific proposals that may strengthen organized markets.10 To that end, for 

example, the Commission proposed to require each RTO or ISO to study whether further 

reforms are necessary to eliminate barriers to demand response in organized markets. 

Any reforms must ensure that demand response resources are treated on a basis 

comparable to other resources. The Commission also ordered two staff technical 

conferences: (1) one to investigate proposals by American Forest and the Portland 

Cement Association, et al. to modify the design of organized markets;11 and (2) a separate 

conference to consider several issues related to demand response participation in 

 8

 16 U.S.C. 824d - 824e. 

9

 NOPR, FERC Stats. & Regs. ¶ 32,628 at P 11. 

10 Id. P 1. 

11 The technical conference was held on May 7, 2008. See Supplemental Notice 

of Technical Conference, Capacity Markets in Regions with Organized Electric Markets, 

Docket No. AD08-4-000 (April 25, 2008). 
Docket Nos. RM07-19-000 and AD07-7-000 - 8 - 

wholesale markets.12 Further, the Commission directed each RTO or ISO to provide a 

forum for affected consumers to voice specific concerns (and to propose regional 

solutions) on how to improve the efficient operation of competitive markets.13 

III. Discussion

A. Demand Response and Pricing During Periods of Operating Reserve 

Shortages in Organized Markets

15. This section of the Final Rule makes several reforms to further eliminate barriers 

to demand response participation in organized energy markets. These reforms are to 

ensure that demand response is treated comparably to other resources. To that end, the 

Commission will require RTOs and ISOs to: (1) accept bids from demand response 

resources in their markets for certain ancillary services, on a basis comparable to other 

resources; (2) eliminate, during a system emergency, certain charges to buyers in the 

energy market for voluntarily reducing demand; (3) permit ARCs to bid demand response 

on behalf of retail customers directly into the RTO’s or ISO’s organized markets; and (4) 

modify their rules governing price formation during periods of operating reserve shortage 

to allow the market-clearing price during periods of operating reserve shortage to more 

accurately reflect the true value of energy. 

 12 The technical conference was held on May 21, 2008. See Supplemental Notice 

of Technical Conference, Demand Response in Organized Electric Markets, Docket No. 

AD08-8-000 (May 13, 2008). 

13 NOPR, FERC Stats. & Regs. ¶ 32,628 at P 11. 
Docket Nos. RM07-19-000 and AD07-7-000 - 9 - 

1. Background

16. Commission policy does not favor granting preference for demand response; 

rather, our goal is to eliminate barriers to the participation of demand response in the 

organized power markets by ensuring comparable treatment of resources. This policy 

reflects the Commission’s view that the cost of producing electricity and the value to 

customers of electric power varies over time and from place to place.14 Demand response 

can provide competitive pressure to reduce wholesale power prices; increases awareness 

of energy usage; provides for more efficient operation of markets; mitigates market 

power; enhances reliability; and in combination with certain new technologies, can 

support the use of renewable energy resources, distributed generation, and advanced 

metering. Thus, enabling demand-side resources, as well as supply-side resources, 

improves the economic operation of electric power markets by aligning prices more 

closely with the value customers place on electric power. A well-functioning competitive 

wholesale electric energy market should reflect current supply and demand conditions. 

17. The Commission’s policy also reflects its responsibility under sections 205 and 

206 of the FPA to remedy any undue discrimination and preference in organized markets. 

To that end, the Commission explicitly addressed demand response in its Open Access 

 14 That is, for two customers at the same time and place, one customer may prefer 

to reduce consumption if the price is high, and the other may be willing to pay a high 

price to avoid curtailment in an emergency. 
Docket Nos. RM07-19-000 and AD07-7-000 - 10 - 

Transmission Tariff (OATT) Reform (Order No. 890)15 and reliability standards (Order 

No. 693).16 

18. Additionally, on numerous occasions, the Commission has expressed the view 

that the wholesale electric power market works best when demand can respond to the 

wholesale price.17 Also, the Commission has issued numerous orders over the last 

several years on various aspects of electric demand response in organized markets, with 

the goal of removing unnecessary obstacles to demand response participating in the 

wholesale power markets of RTOs and ISOs.18 To that end, some of these orders 

approved various types of demand response programs, including programs to allow 

 15 Preventing Undue Discrimination and Preference in Transmission Service, 

Order No. 890, FERC Stats. & Regs. ¶ 31,241 (2007), order on reh’g, Order No. 890-A, 

73 FR 2,984 (Jan. 16, 2008), FERC Stats. & Regs. ¶ 31,261 (2007), order on reh’g, Order 

No. 890-B, 73 FR 39,092 (July 8, 2008), 123 FERC ¶ 61,299 (2008). 

16 See Mandatory Reliability Standards for the Bulk-Power System, Order No. 

693, FERC Stats. & Regs. ¶ 31,242, order on reh’g, Order No. 693-A, 120 FERC 

¶ 61,053 (2007). 

17 See, e.g., New England Power Pool and ISO New England, Inc., 101 FERC 

¶ 61,344, at P 44-49 (2002), order on reh’g, 103 FERC ¶ 61,304, order on reh’g, 

105 FERC ¶ 61,211 (2003); PJM Interconnection, L.L.C., 95 FERC ¶ 61,306 (2001); 

PJM Interconnection, L.L.C., 99 FERC ¶ 61,227 (2002); Southwest Power Pool, Inc., 

116 FERC ¶ 61,289 (2006). 

18 See, e.g., New York Indep. Sys. Operator, Inc., 92 FERC ¶ 61,073, order on 

clarification, 92 FERC ¶ 61,181 (2000), order on reh’g, 97 FERC ¶ 61,154 (2001); New 

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

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

105 FERC ¶ 61,211 (2003); PJM Interconnection, L.L.C., 95 FERC ¶ 61,306 (2001); 

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

99 FERC ¶ 61,227 (2002). 
Docket Nos. RM07-19-000 and AD07-7-000 - 11 - 

demand response to be used as a capacity resource19 and as a resource during system 

emergencies,20 to allow wholesale buyers and qualifying large retail buyers to bid 

demand response directly into the day-ahead and real-time energy markets and certain 

ancillary service markets, particularly as a provider of operating reserves, as well as 

programs to accept bids from ARCs.21 The Commission also has approved special 

demand response applications such as use of demand response for synchronized reserves 

and regulation service.22 The theme underlying the Commission’s approval of these 

programs has been to allow demand response resources to participate in these markets on 

a basis that is comparable to other resources. 

19. While the Commission and the various RTOs and ISOs have done much to 

eliminate barriers to demand response in organized power markets, more needs to be 

done to ensure comparable treatment of all resources. Therefore, as discussed below, the 

 19 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), appeal 

pending sub nom. Maine Pub. Utils. Comm’n v. FERC, No. 06-1403 (D.C. Cir. 2007). 

20 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). 

21 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). 

22 See, e.g., PJM Interconnection, L.L.C., 114 FERC ¶ 61,201 (2006). 
Docket Nos. RM07-19-000 and AD07-7-000 - 12 - 

Commission is taking action in this Final Rule to further eliminate barriers to demand 

response in organized power markets. 

2. Ancillary Services Provided by Demand Response Resources

20. The Commission included several components in the NOPR obligating RTOs 

and ISOs to accept bids from demand response resources for ancillary services. First, 

demand response resources were required to meet necessary technical requirements 

established by the RTO or ISO in order to participate in these markets. Second, the 

Commission proposed that demand response resources be allowed to specify the 

frequency and duration of their service through the use of additional bidding parameters. 

Finally, the Commission proposed that RTOs and ISOs perform a small demand response 

resource assessment to evaluate the technical feasibility and value to the market of such 

smaller resources. Comments in response to these issues are addressed below. 

a. Ancillary Services Market

21. In the NOPR, the Commission proposed to obligate each RTO or ISO to accept 

bids from demand response resources, on a basis comparable to any other resources, for 

ancillary services that are acquired in a competitive bidding process, if the demand 

response resources: (1) are technically capable of providing the ancillary service and 

meet the necessary technical requirements; and (2) submit a bid under the generallyapplicable 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 
Docket Nos. RM07-19-000 and AD07-7-000 - 13 - 

customer to participate.23 The Commission stated that this proposal would apply to 

competitively-bid markets, if any, for energy imbalance, spinning reserves, supplemental 

reserves, reactive supply and voltage control, and regulation and frequency response as 

defined in the pro forma OATT, or to the markets for their functional equivalents in an 

RTO or ISO tariff.24 

22. The Commission proposed that, on compliance, an RTO or ISO must either 

propose amendments to its tariff to comply with the proposed requirement or demonstrate 

that its existing tariff and market design already satisfy the requirement. This filing 

would be submitted within six months of the date the Final Rule is published in the 

Federal Register. The Commission proposed to assess whether each filing satisfies the 

proposed requirement and issue additional orders as necessary.25

i. Comments

23. Many commenters support the Commission’s proposal and agree that allowing 

demand response resources to participate in ancillary services markets would increase 

competition, enhance system reliability, and lower the overall price for ancillary 

services.26 For instance, Public Interest Organizations assert that the presence of demand 

 23 NOPR, FERC Stats. & Regs. ¶ 32,628 at P 56. 

24 Id.

25 Id. P 63. 

26 E.g., American Forest at 5; BlueStar Energy at 1-2; California PUC at 9; 

Cogeneration Parties at 2-3; Dominion at 4; Duke Energy at 3; Integrys Energy at 9; 

ISO/RTO Council at 3-4; Industrial Coalitions at 9; Midwest Energy at 2-3; North 

 (continued...) 
Docket Nos. RM07-19-000 and AD07-7-000 - 14 - 

response in these markets will mitigate the exercise of market power and allow large 

amounts of variable resources (e.g., wind and solar) to be integrated into the grid.27 

DRAM states that allowing demand response to participate in ancillary services markets 

and other types of wholesale markets would lead to a more viable and sustainable 

demand response industry, and to the availability of a larger overall demand response 

resource.28 Comverge maintains that the Commission’s proposal is particularly 

appropriate because it enables market participants to simultaneously participate in 

capacity markets (or resource adequacy) and operating reserve markets.29 DRAM and 

APPA, while in support of the Commission’s proposal, state that demand response 

resources must be able to meet the appropriate technical requirements.30 

24. Several commenters state that they support the Commission’s clarification in 

the NOPR that the proposal would not require the adoption of competitive bidding 

processes in areas where they were not previously used.31 APPA states that it opposes 

the development of new RTO or ISO markets for ancillary services just so demand 

 

Carolina Electric Membership at 3-4; NYISO at 5; Public Interest Organizations at 5-6; 

Reliant at 3; and Wal-Mart at 5. 

27 Public Interest Organizations at 4-5. 

28 DRAM at 5-6. 

29 Comverge at 11. 

30 DRAM at 4-5; APPA at 31-32. 

31 NOPR, FERC Stats. & Regs. ¶ 32,628 at P 58. 
Docket Nos. RM07-19-000 and AD07-7-000 - 15 - 

response resources could participate in them.32 Similarly, EEI asserts that this proposal 

should be limited to competitively-bid markets only, as defined in the proposal.33 

Comverge also agrees with the Commission’s proposed requirement that this provision 

apply only to competitively-bid markets, but asks the Commission to include two other 

services within its proposal: Out-of-Market34 and Scarcity Pricing.35

25. Xcel requests that the Commission clarify that the proposed rule does not 

require a demand response provider to offer its potential demand response into the 

market.36 Xcel argues that a demand response provider should be free to evaluate its 

willingness to bid its offering into the market. 

26. In its reply comments, Allied Public Interests Groups note that providing for 

comparable treatment of demand-side resources in wholesale markets is critical to 

making those markets competitive, efficient, reliable and sustainable. Therefore, they ask 

 32 APPA at 34-35. 

33 EEI at 11. 

34 It is not entirely clear what service Comverge is referring to here. It is possible 

that Comverge is referring to Out-Of-Market Dispatch, i.e., RTO or ISO dispatch actions 

that are not reflected in the ISO’s real-time market prices. In CAISO, for example, 

dispatchers procure energy to make up for imbalances by contacting selected resources or 

control area operators that chose not to submit any bids into the ISO’s or RTO’s markets. 

This practice results in bilateral trades negotiated by the RTO or ISO. 

35 Comverge at 13-14. Similarly, it is not clear to the Commission what service 

Comverge is referring to, as Scarcity Pricing is not an ancillary service. 

36 Xcel at 7. 
Docket Nos. RM07-19-000 and AD07-7-000 - 16 - 

the Commission to clarify the meaning and implication of the term “comparable 

treatment.”37

27. NARUC argues that the state-law exemption within the NOPR should be 

modified to avoid displacing state authority and state policy decisions on demand 

response.38 NARUC explains that this exemption places the burden on state regulators to 

show that the demand response proposal conflicts with state laws or regulations. 

NARUC would like to see this reversed, and the burden placed on the RTO or ISO to 

obtain the state regulator’s permission to allow the demand response proposal. Similarly, 

Pennsylvania PUC states that the state exemption highlights a jurisdictional issue and 

recommends that the Commission continue to work with state authorities to eliminate 

these types of barriers to demand response.39

 37 Allied Public Interest Groups at 1. 

38 NARUC at 7. The proposal for ancillary services market states: 

The Commission proposed to obligate each RTO or ISO to 

accept bids from demand response resources, on a basis 

comparable to any other resources, for ancillary services that 

are acquired in a competitive bidding process, if the demand 

response resources (1) are technically capable of providing 

the ancillary service and meet the necessary technical 

requirements, and (2) submit a bid under the generallyapplicable 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. 

NOPR, FERC Stats. & Regs. ¶ 32,628 at P 56 (emphasis added). 

39 Pennsylvania PUC at 11. 
Docket Nos. RM07-19-000 and AD07-7-000 - 17 - 

28. Some commenters recommend that each RTO and ISO should determine new 

rules for ancillary services.40 Dominion states that each RTO and ISO should have 

flexibility to develop the necessary rules to modify existing ancillary services markets 

within its stakeholder processes.41 Comverge suggests that these rules be determined by 

each RTO and ISO, but initially framed in a Commission technical conference, consistent 

with the Commission’s substantive recommendations to amend RTO and ISO bidding 

rules.42 SoCal Edison-SDG&E argue that an overly prescriptive national approach may 

be counterproductive.43

29. While Midwest Energy supports the proposal, it is concerned that the quest for 

comparability may evolve into a program that treats demand response preferentially with 

respect to competitive resource providers. It states that any such preferential treatment 

could lead to overall increases in costs to customers through the subsidization of demand 

response.

44 Therefore, Midwest Energy asks that the Commission require that: (1) each 

RTO or ISO demand response program be subject to a net-benefits test and (2) all 

demand-side resources be subject to a performance evaluation.45 

 40 See, e.g., Comverge at 17; Dominion at 4; and SoCal Edison-SDG&E at 3. 

41 Dominion at 4. 

42 Comverge at 17. 

43 SoCal Edison-SDG&E at 3. 

44 Midwest Energy at 3. 

45 Id.
Docket Nos. RM07-19-000 and AD07-7-000 - 18 - 

30. Reliant comments that demand response resources should be subject to penalties 

for non-performance comparable to those that supply resources face. Reliant also states 

that demand response resources that supply ancillary services should participate in RTO 

and ISO ancillary services markets primarily via the entity that schedules and financially 

settles the load for their meters.46 Allied Public Interest Groups agrees that demand 

response resources should face comparable penalties for non-performance, but notes in 

reply comments that “comparable” penalties does not mean “the same” penalties.47

31. Public Interest Organizations urge the Commission to expand the demand 

response provisions to include energy efficiency resources, environmentally benign 

behind-the-meter distributed generation, and all other demand-side resources that are 

capable of providing the service.48 Public Interest Organizations explain in their 

comments that “energy efficient resources produce load reductions for the length of their 

measured lives, relieving congestion, reducing market costs, and increasing system 

reliability.” They state that “a bundle of energy efficient resources that reduces energy 

use on a large scale—an ‘efficiency power plant’ or EPP—can achieve energy savings 

that are just as predictable and substantial as the energy output of a conventional power 

plant. The consistent savings from these energy efficiency programs and investments can 

 46 Reliant at 4. 

47 Allied Public Interest Groups at 4. 

48 Public Interest Organizations at 4. 
Docket Nos. RM07-19-000 and AD07-7-000 - 19 - 

be thought of as a virtual power plant.”49 Allied Public Interest Groups assert that the 

comparable treatment proposed for demand response in the NOPR should be expanded to 

cover all reliable and efficient demand response resources that are technically capable of 

providing the service needed. Allied Public Interest Groups notes that limiting 

participation in ancillary services markets to “traditional” demand response resources 

may unintentionally exclude innovative new technologies that can help achieve goals of 

system reliability and efficiency.50

32. TAPS asserts that behind-the-meter generation can perform as a demand 

resource in ancillary services markets. TAPS states that the regulatory language should 

be modified to include this type of resources as well as reliability-based demand 

response. They note that reliability-based demand response, or demand response that is 

not in reaction to an increase in the price of electric energy or to incentive payments, is 

currently not included in the regulatory definition of Demand Response contained within 

this proceeding.51

33. Some supporters state that the Commission should address in the Final Rule 

compensation for demand response resources. For instance, Industrial Consumers 

suggest that the payment structure for demand response resources should be comparable 

 49 Id. at 13-14. 

50 Allied Public Interest Groups at 7. 

51 TAPS at 9. 
Docket Nos. RM07-19-000 and AD07-7-000 - 20 - 

to the payment of a generator.52 They also note that to promote the development of 

demand response resources and fairly compensate these resources for their ancillary 

services, a methodology for calculating and accurately representing customer baselines 

must be developed on a consistent basis.53 EnerNOC agrees and asks the Commission to 

require RTOs and ISOs to demonstrate in future compliance filings that customer 

baseline methodologies appropriately address concerns of accuracy, integrity, and 

comparable treatment of demand response resources.54 

34. E.ON U.S. does not support the Commission’s proposal. E.ON U.S. believes 

that the Commission’s proposal mandates the purchase of demand response products 

regardless of price, and that such a practice will distort the market and create additional 

costs for end-use customers.55 E.ON U.S. argues that the Commission should only 

require comparable treatment of demand response resources and not place any extra 

emphasis or incentive on their use. 

35. Several commenters request that the Commission develop a pro forma tariff 

regarding demand response participation in ancillary services markets. Industrial 

Consumers argue that the Commission should prescribe specific pro forma tariff 

language for RTOs and ISOs to adopt within 30 days of the Final Rule’s effective date. 

 52 Industrial Consumers at 13. 

53 Id. at 14. 

54 EnerNOC at 11. 

55 E.ON U.S. at 14. 
Docket Nos. RM07-19-000 and AD07-7-000 - 21 - 

Otherwise, they assert that piecemeal implementation by RTOs and ISOs may result in 

delay, inefficiency, and inconsistency.56 Similarly, Industrial Coalitions state that the 

Commission should incorporate into a pro forma demand response tariff appropriate 

minimum standards to enable demand response resources to provide, and be comparably 

compensated for, ancillary services. Industrial Coalitions and Steel Manufacturers 

contend that the Commission should obligate RTOs and ISOs to demonstrate that their 

own tariffs are consistent with or superior to the pro forma provisions and any deviations 

from the pro forma tariff should only be permitted if they can provide a clear justification 

for doing so.57 

36. A few commenters express concern about the Western Electricity Coordinating 

Council’s (WECC) regional reliability standard addressing operating reserve 

requirements because WECC currently allows demand response to supply only nonspinning reserves.58 For example, CAISO points out that WECC’s standard is 

inconsistent with the Commission’s directive in Order No. 890 that a transmission 

provider must permit non-generation resources to provide ancillary services to the extent 

they are capable of doing so. It argues that WECC is non-compliant with Order No. 693, 

 56 Industrial Consumers at 7-8. Industrial Consumers note that the Commission’s 

practice extending back to Order No. 888 has been to standardize rules and procedures 

for generators and other transmission users with the pro forma OATT as necessary to 

promote consistency and to avoid undue discrimination. Id.

57 Industrial Coalitions at 11; Steel Manufacturers at 10. 

58 California DWR at 8; CAISO at 5; California PUC at 9-10; and PG&E at 6-7. 
Docket Nos. RM07-19-000 and AD07-7-000 - 22 - 

which includes a requirement explicitly providing that demand-side management may be 

used as a resource for contingency reserves. Therefore, CAISO comments that the 

Commission should direct the Electric Reliability Organization (ERO) to effect a change 

in WECC requirements.59

37. Several entities ask that the Final Rule not disturb or replace ongoing 

proceedings in individual regions. Midwest ISO states that the Commission recently 

approved its integration of demand response resources to participate in Midwest ISO 

ancillary services markets, on a basis comparable to other resources (ASM Proposal).60 

Given this, Midwest ISO requests that the Commission find that its ASM Proposal 

satisfies the NOPR’s requirement that each RTO and ISO submit for Commission 

approval standards by which demand response resources are able to participate and bid in 

the ancillary service markets on comparable terms as other resources.61 CAISO states 

that it will comply with the NOPR requirement in the Release 1A enhancements to its 

Markets Redesign & Technology Upgrade (MRTU).62 It asks the Commission to clarify 

that it does not intend to replace the specific schedule that it has accepted for the 

CAISO’s 

 59 CAISO at 5; see also California PUC at 10. 

60 Midwest Independent Transmission System Operator, Inc., 112 FERC ¶ 61,283 

(2005), order on reh’g, 123 FERC ¶ 61,297(2008) (ASM Order). 

61 Midwest ISO at 9. 

62 Cal. Indep. Sys. Operator Corp., 116 FERC ¶ 61,274 (2006), order on reh’g, 

119 FERC ¶ 61,076 (2007). 
Docket Nos. RM07-19-000 and AD07-7-000 - 23 - 

implementation of MRTU with the generic compliance schedule proposed in the 

NOPR.63 

38. In addition, while Maine PUC agrees that demand response is important to the 

efficient functioning of wholesale electric markets, it states that the Commission should 

allow ISO New England to work with state regulators and NEPOOL Participants to make 

existing programs more robust and to eliminate barriers to demand response 

participation.64 Maine PUC notes that demand response programs in New England are 

achieving price savings and reducing the need for additional generation and transmission, 

demonstrated by the significant participation of demand response resources in the 

forward capacity market. Therefore, Maine PUC states that the Commission should not 

impose the NOPR’s specific requirements for demand response on ISO New England. 

39. SPP states that it does not currently have an ancillary services market; however, 

it reports that consideration and incorporation of demand response in future market 

development is currently being undertaken by SPP’s Working Groups and Task Forces.65 

40. Alcoa maintains that the Commission’s proposal is well-intended, but falls short 

of what is needed to ensure non-discriminatory treatment of demand response bids by 

industrial customers. Alcoa asserts that the Commission’s proposal is incomplete 

 63 CAISO at 2-4. 

64 Maine PUC at 3-4. 

65 SPP at 5. 
Docket Nos. RM07-19-000 and AD07-7-000 - 24 - 

because it relies too heavily on vague concepts such as comparability of resources and 

reasonable requirements to increase access to ancillary services. Alcoa argues that there 

should be no restriction on the amount of participation by demand response resources in 

organized wholesale markets, and suggests that, at a minimum, regional operators should 

be required to justify such restrictions to the Commission and demonstrate that they are 

necessary for technical reasons.66 

41. Several commenters support the Commission’s conclusion that it is not 

appropriate for the Commission to develop a standardized set of technical requirements.67 

California PUC stresses the importance of allowing RTOs and ISOs the flexibility to 

modify requirements in the future, as experience is gained with demand response 

programs. EEI believes that standardization of these requirements could result in 

unnecessary expense and delay in implementation by requiring incompatible 

infrastructure across different RTOs and ISOs. EnerNOC believes that the Commission 

struck the appropriate balance by requiring coordination among the RTOs and ISOs 

without mandating standardization. 

42. North Carolina Electric Membership states that the Commission should require 

RTOs and ISOs to develop technical requirements in conjunction with stakeholders to 

ensure that all interests are properly considered. Old Dominion also states that any 

 66 Alcoa at 2-3. 

67 E.g., California PUC at 9; EEI at 12; EnerNOC at 9; NYISO at 6; and North 

Carolina Electric Membership at 4. 
Docket Nos. RM07-19-000 and AD07-7-000 - 25 - 

standards developed in response to the Commission’s requirement should be 

comprehensive and result from a stakeholder process. 

43. LPPC supports the Commission’s recognition that demand response resources 

must be technically capable of providing ancillary services. In addition, LPPC agrees 

with the Commission’s statement that RTOs and ISOs need to impose requirements on 

telemetry and metering to allow demand response resources to fully participate in 

ancillary services markets. LPPC adds that an important element of any RTO- or ISO-led 

ancillary services program must be performance monitoring to ensure that demand 

response resources truly respond when called upon.68 Also, Old Dominion argues that 

the ability to accurately measure and verify demand response is necessary to guarantee 

that these resources are providing real benefits to the market.69 

44. APPA supports the Commission’s overall proposal, but states that the 

Commission should recognize that metering, telemetry and performance requirements 

that may have to be imposed on demand-side resources to ensure their reliable 

performance will be more stringent than the requirements most retail customers are used 

to accommodating. APPA questions whether end-use customers will offer ancillary 

services that may require them to reduce consumption substantially on very short notice. 

APPA asserts that program participants may drop out when called upon too frequently. 

APPA states that it may prove difficult to reconcile the rigorous technical requirements 

 68 LPPC at 6-7. 

69 Old Dominion at 7. 
Docket Nos. RM07-19-000 and AD07-7-000 - 26 - 

for end users necessitated by the instantaneous nature of certain ancillary services with 

the desire of many larger loads for reliability, flexibility and convenience.70

45. NYISO recommends that the Final Rule clarify the NOPR’s proposed 

regulatory language to specify that demand response resources must also meet applicable 

reliability requirements before they are permitted to bid into markets.71 NYISO states 

that this language would clearly articulate the Commission’s support for the integration 

of demand resources into ancillary services markets without overriding requirements 

adopted by NERC or the New York State Reliability Council. Further, it notes that this 

approach would be consistent with Order 890-A, which allows RTOs and ISOs to adopt 

reasonable reliability related limitations on demand resource participation.72 

46. Comverge requests that the Commission ensure that any requirements imposed 

on demand response resources are not overly technical and burdensome.73 California 

PUC states that telemetry, for example, is necessary for resources offering ancillary 

services, but a telemetry requirement for every participant (such as small commercial and 

residential customers) may be excessive and could erect a barrier to entry for these 

smaller customers, particularly when not every demand response supplier has the money 

 70 APPA at 33-34. 

71 NYISO at 5-6. 

72 Id. at 6 (citing Order No. 890-A, 73 FR 2984 (Jan. 16, 2008), FERC Stats. & 

Regs. ¶ 31,261 at P 499). 

73 Comverge at 13. 
Docket Nos. RM07-19-000 and AD07-7-000 - 27 - 

to install real-time telemetry and metering.74 EnerNOC also mentions this concern, and 

asks that the Commission clarify that its “reasonableness” requirement is aimed at 

ensuring that reasonable technical requirements not be unduly restrictive on demand 

response resources, such as those that may add unwarranted and unnecessary costs to 

participation. EnerNOC states that technical standards should focus on the reliability 

parameters of the particular ancillary service and allowing demand response resources to 

utilize alternative methods to meet these standards.75

ii. Commission Determination

47. In this Final Rule, the Commission adopts the NOPR proposal to require each 

RTO or ISO to accept bids from demand response resources, on a basis comparable to 

any other resources, for ancillary services that are acquired in a competitive bidding 

process, if the demand response resources: (1) are technically capable of providing the 

ancillary service and meet the necessary technical requirements; and (2) submit a bid 

under the generally-applicable bidding rules at or below the market-clearing price, unless 

the laws or regulations of the relevant electric retail regulatory authority do not permit a 

retail customer to participate. All accepted bids would receive the market-clearing price. 

48. The Commission’s policy has been, and continues to be, to identify and 

eliminate barriers to participation of demand response resources in organized power 

markets. Development of demand response resources provides benefits to consumers by 

 74 California PUC at 11. 

75 EnerNOC at 10-11. 
Docket Nos. RM07-19-000 and AD07-7-000 - 28 - 

providing competitive pressure to reduce wholesale power prices, providing for the more 

efficient operation of organized markets, helping to mitigate market power and enhance 

system reliability, and encouraging development and implementation of new 

technologies, including renewable energy and energy efficiency resources, distributed 

generation and advanced metering. The reforms implemented in this Final Rule will 

benefit energy consumers by removing several barriers to the development and use of 

demand response resources in organized wholesale electric power markets. 

49. As noted in the NOPR, this requirement would apply to competitively-bid 

markets, if any, for energy imbalance, spinning reserves, supplemental reserves, reactive 

supply and voltage control, and regulation and frequency response as defined in the pro 

forma OATT, or to the markets of their functional equivalents in an RTO or ISO tariff.76 

The Commission requires that demand response resources that are technically capable of 

providing the ancillary service within the response time requirements,77 and that meet 

reasonable requirements adopted by the RTO or ISO as to size, telemetry, metering and 

bidding, be eligible to bid to supply energy imbalance, spinning reserves, supplemental 

reserves, reactive and voltage control, and regulation and frequency response.78 

 76 NOPR, FERC Stats. & Regs. ¶ 32,628 at P 56. 

77 Some technologies may be capable of responding to an RTO’s or ISO’s control 

signal and providing certain ancillary services, such as regulation and frequency response 

service, more quickly than under existing response time requirements. 

78 The RTO or ISO may specify certain requirements, such as registration with the 

RTO or ISO, creditworthiness requirements, and certification that participation is not 

precluded by the relevant electric retail regulatory authority. The RTO or ISO should not 

 (continued...) 
Docket Nos. RM07-19-000 and AD07-7-000 - 29 - 

50. In response to Allied Public Interest Groups, we decline to define “comparable 

treatment.” Each RTO and ISO is unique, and the Commission hesitates to impose a 

uniform definition. Each RTO and ISO therefore should establish policies and 

procedures in cooperation with its customers and other stakeholders that ensure that 

demand response resources are treated comparably to supply-side resources. The 

Commission will have ample opportunity to evaluate concerns that may arise when it 

reviews the compliance filings required by this Final Rule. 

51. In light of APPA’s comments, we clarify that this requirement applies only to 

competitively-bid markets for those ancillary services specified, as well as to the markets 

of their functional equivalents in an RTO or ISO tariff. This requirement does not 

obligate RTOs or ISOs to create new competitively-bid ancillary services markets. 

52. In response to Xcel and E.ON U.S., we note that the Commission proposed in 

the NOPR to obligate RTOs and ISOs to accept bids from demand response resources on 

a comparable basis to supply resources for ancillary services. For Xcel, we clarify that 

demand response providers are not required to offer potential demand response into the 

ancillary services markets. Demand response resources may evaluate market prices and 

other factors before making a determination to bid or not. Regarding E.ON U.S.’s 

comments, the Commission did not propose (and does not require) that RTOs or ISOs 

 

be in the position of interpreting the laws or regulations of a relevant electric retail 

regulatory authority. 
Docket Nos. RM07-19-000 and AD07-7-000 - 30 - 

must purchase ancillary services from demand response resources without regard to 

whether these resources are lower-bid alternatives to supply resources. 

53. In response to NARUC and others who comment that the Commission’s 

proposal would place the burden on retail regulatory authorities to show that a demand 

response proposal conflicts with state or local laws or regulations, we clarify that we will 

not require a retail regulatory authority to make any showing or take any action in 

compliance with this rule.79 Rather, this rule merely requires an RTO or ISO to accept 

bids for ancillary services from demand response resources, unless the laws or 

regulations of the relevant electric retail regulatory authority do not permit a retail 

customer to participate. 

54. We disagree with commenters who argue that requiring RTOs and ISOs to 

allow demand response resources to participate in ancillary services markets may be 

counterproductive or unnecessary.80 This requirement removes a barrier to participation 

of demand response resources in organized wholesale markets and allows these resources 

to provide ancillary services on a basis comparable to generation sources. This 

 79 In reply to the Pennsylvania PUC’s recommendation that the Commission 

continue to work with state authorities to eliminate barriers to demand response, we note 

that NARUC and the Commission, through their Demand Response Collaborative, are 

working to outline options to coordinate retail and wholesale regulatory policies in order 

to stimulate participation in demand response by reducing or eliminating jurisdictional 

barriers. 

80 The Commission has approved actions by some RTOs and ISOs to incorporate 

demand response into their ancillary services markets. See, e.g., California Indep. Sys. 

Operator, 116 FERC ¶ 61,274 (2006); PJM Interconnection, L.L.C., 114 FERC ¶ 61,201 

(2006). 
Docket Nos. RM07-19-000 and AD07-7-000 - 31 - 

requirement would potentially expand the resource pool in these organized markets, 

thereby lowering the overall market price for ancillary services, as well as potentially 

mitigating the exercise of market power. The competitiveness within ancillary services 

markets, as well as the system reliability, would be enhanced through increased 

participation. 

55. Contrary to Midwest Energy’s comments, we do not find that this requirement 

will lead to any preferential treatment for demand response resources or supply-side 

resources. Both sets of resources would be treated and penalized comparably in instances 

of non-performance. 

56. In response to Public Interest Organizations, the Commission has not excluded 

from eligibility any type of resource that is technically capable of providing the ancillary 

service, including a load serving entity’s (LSE) or eligible retail customer’s behind-themeter generation or any other demand response resource. Further, the Commission 

appreciates the value of energy efficiency, and is aware of RTO and ISO efforts to 

integrate energy efficiency into organized markets. Nothing in this rule precludes an 

RTO or ISO from appropriately including energy efficiency into any of its markets. The 

Commission did not propose to include energy efficiency as a provider of competitively 

procured ancillary services, and does not have an adequate record to address this issue 

here. 

57. With regard to Industrial Consumers’ and EnerNOC’s comments requesting the 

resolution of customer baseline issues, the Commission agrees that customer baselines 

are an important factor in the appropriate compensation for demand response resources. 
Docket Nos. RM07-19-000 and AD07-7-000 - 32 - 

Customer baselines are designed to depict, as accurately as possible, a customer’s normal 

load on a given day. Establishing this baseline helps system operators to measure and 

verify load reductions, thus giving RTOs and ISOs the ability to not only determine if 

demand response resources showed up, but also what the proper value of the demand 

reduction should be. Many RTOs and ISOs currently establish such bidder baselines as 

part of their demand response programs, or they are working with their stakeholders to 

modify such methodologies. Accordingly, RTOs and ISOs should describe in their 

compliance filings their efforts to develop adequate customer baselines. 

58. Regarding comments related to WECC’s provisions for demand response 

resources in its reliability standards, we note that this rule requires comparable treatment 

for demand response resource participation in ancillary services markets. This is a 

general rulemaking and is not the proper venue for adjudicating the alleged issue 

regarding WECC’s regional reliability standards.81

59. In response to comments, the Commission again finds that it is not appropriate 

in this rulemaking to develop a standardized set of technical requirements for demand 

response resources participating in ancillary services markets. Instead, the Commission 

will allow each RTO and ISO, in conjunction with its stakeholders, to develop its own 

 81 Concerns regarding WECC’s regional reliability standards can be addressed by 

filing a complaint under section 206 of the FPA, 16 U.S.C. 824e, or by filing a notice 

under section 215 of the FPA, 16. U.S.C. 824o. Under section 215, “[i]f a user, owner or 

operator of the transmission facilities of a Transmission Organization determines that a 

[r]eliablity [s]tandard may conflict with a function, rule, order, tariff, rate schedule, or 

agreement accepted, approved, or ordered by the Commission . . . . the Transmission 

Organization shall expeditiously notify the Commission . . . .” 18 CFR 39.6. 
Docket Nos. RM07-19-000 and AD07-7-000 - 33 - 

minimum requirements. However, as proposed in the NOPR, the Commission will 

require RTOs and ISOs to coordinate with each other in the development of such 

technical requirements, and provide the Commission with a technical and factual basis 

for any necessary regional variations.82 In addition, having RTOs and ISOs work in 

conjunction with stakeholders as well as with each other should ensure that any 

developed requirement is not so full of technical detail or so burdensome that it 

discourages demand response resource participation. 

60. With respect to NYISO’s request that the Commission clarify its proposed 

regulatory language to specify that demand response resources must also meet 

“applicable reliability requirements,” the Commission does not see a need to include this 

provision in this Final Rule. To do so would merely duplicate existing regulations that 

require reliability standards, and that set out certain reliability requirements. This 

duplication would serve no useful purpose. 

61. As part of the compliance filing to be submitted within six months of the Final 

Rule, each RTO or ISO is required to file a proposal to adopt reasonable standards 

necessary for system operators to call on demand response resources, and mechanisms to 

measure, verify, and ensure compliance with any such standards. These standards would 

be subject to Commission approval. 

62. The Commission is mindful of the progress being made in California with 

MRTU and in the Midwest ISO with its ASM Order. Our requirement is that, where 

 82 NOPR, FERC Stats. & Regs. ¶ 32,628 at P 64. 
Docket Nos. RM07-19-000 and AD07-7-000 - 34 - 

there are markets for acquiring ancillary services, these markets must be open to qualified 

demand response bidders. This requirement allows each RTO or ISO to work with 

stakeholders to develop the appropriate implementation rules for its own market design. 

This approach allows for regional variation and should alleviate the concerns of Midwest 

ISO, CAISO, and Maine PUC. 

63. The Commission will not now rule on CAISO’s request that the Commission 

not interfere with its current timeline to implement MRTU, or Midwest ISO’s request that 

the Commission find Midwest ISO already satisfies the proposed requirements through 

its ASM Proposal. CAISO and Midwest ISO must submit, within their respective 

compliance filings, a description of how their current activities comply with the 

requirements of this Final Rule. Upon review, the Commission will determine if further 

action on behalf of either RTO or ISO is necessary. 

b. New Bidding Parameters

64. The Commission proposed to require RTOs and ISOs to allow demand response 

resources to specify limits on the frequency and duration of their service in their bids to 

provide ancillary services—or their bids into the joint energy-ancillary services market in 

the co-optimized RTO markets.83 These limits would include a maximum duration for 

dispatch, a maximum number of times per day that demand response resources could be 

called, or a maximum amount of energy per day or week that a resource can produce. 

 83 Id. P 62. 
Docket Nos. RM07-19-000 and AD07-7-000 - 35 - 

65. The Commission requested comment on this proposed requirement and whether 

these new parameters should be available for all bidders, not just for demand response 

resources. Further, the Commission intended that the bidding parameters would be 

implemented by all RTOs and ISOs, and proposed to require them to confer with each 

other and to provide a technical and factual basis for any necessary regional variations. 

i. Comments

66. Most commenters support the Commission’s proposal to require RTOs and 

ISOs to incorporate new parameters into their bidding rules to allow demand response 

resources to specify in their bids the duration and frequency of their service.84 For 

instance, several commenters state that allowing new bidding parameters would increase 

the number and type of demand response resources participating in the ancillary services 

markets.85 Some commenters note that generators face certain constraints (including 

start-up costs, ramp rates, and limits on the number of hours that they may operate 

efficiently), which are reflected within their bids. They assert that allowing demand 

response resources to specify similar constraints within their bids is consistent with the 

Commission’s principle of comparability between demand-side and supply-side 

 84 E.g., Ameren; American Forest; APPA; BlueStar Energy; Beacon Power; Mr. 

Borlick; BP Energy; California DWR; California PUC; Cogeneration Parties; Comverge; 

DC Energy; Detroit Edison; DRAM; Duke Energy; EEI; EnergyConnect; EnerNOC; 

Exelon; FTC; First Energy; Industrial Coalitions; Industrial Consumers; ISO New 

England; ISO/RTO Council; Midwest ISO; North Carolina Electric Membership; Ohio 

PUC; Old Dominion; Organization of Midwest ISO States; PG&E; Public Interest 

Organizations; Reliant; Steel Producers; TAPS; Wal-Mart; and Xcel. 

85 E.g., American Forest at 5; Exelon at 5. 
Docket Nos. RM07-19-000 and AD07-7-000 - 36 - 

resources.86 DC Energy states that, similar to generators, demand response providers 

should have the choice to observe market signals and make an informed decision on 

whether to bid into these markets.87 

67. The ISO/RTO Council asserts that the implementation of these new bidding 

parameters must be done in a way that assures demand response resources participating 

in ancillary services markets meet the same product requirements as supply-side 

resources.88 Several commenters express their support for this concept provided that 

demand response resources are not afforded an undue advantage over supply-side 

resources.89 

68. Two commenters state that they support the proposal provided that certain 

conditions are met. Ameren states there should be no adverse effect on system reliability 

and that any market rules that provide this flexibility should be limited in scope so as to 

avoid the potential for gaming.90 BP Energy agrees with the Commission’s proposal only 

to the extent that bidding parameters submitted by demand response resources can be 

 86 American Forest at 5; Cogeneration Parties at 3; DRAM at 6-7; Duke Energy at 

3-4; Exelon at 5-6; FTC at 25-27; FirstEnergy at 7; Industrial Consumers at 12; 

ISO/RTO Council at 4; North Carolina Electric Membership at 4; Old Dominion at 8; and 

Public Interest Organizations at 6. 

87 DC Energy at 4. 

88 ISO/RTO Council at 4. 

89 E.g., Old Dominion at 8; Reliant at 4; and Wal-Mart at 5. 

90 Ameren at 18. 
Docket Nos. RM07-19-000 and AD07-7-000 - 37 - 

incorporated into the RTO and ISO software in a cost effective manner while maintaining 

the algorithm’s ability to perform timely cost minimizing optimizations.91

69. ISO New England supports granting individual demand response resources the 

opportunity to specify additional bidding parameters, but notes that such specification 

may limit the resource’s qualification (under market rules) on an individual basis to bid to 

supply operating reserves.92 However, ISO New England itself notes that demand 

response aggregators should be in a position to formulate bids combining individual 

demand resources so as to be able to meet the reserves market’s availability requirements 

in a manner comparable to that of generation. 

70. Duke Energy notes that the NOPR proposal would allow demand response 

resources to manage the risk that they would be called upon too frequently or for too long 

a period relative to their individual constraints. In that respect, Duke Energy asserts that 

if RTOs and ISOs are not required to account for such bid flexibility, demand resources 

could potentially be eliminated from the ancillary services markets through voluntary 

means.93 Duke Energy argues that without any knowledge of how and when they will be 

used, demand resources may view the ancillary services markets as too risky and, 

 91 BP Energy at 14. 

92 ISO New England at 5. 

93 Duke Energy at 3-4. 
Docket Nos. RM07-19-000 and AD07-7-000 - 38 - 

therefore, not participate in them. APPA states that large end-use customers’ desire to 

reduce consumption on short notice decreases the more frequently they are called upon.94

71. Steel Producers asserts that demand response resources’ unique characteristics 

need to be taken into account, and recommends that the Commission require RTOs and 

ISOs to allow, at a minimum, the following optional bidding parameters in addition to the 

three mentioned in the NOPR: (1) minimum notice requirement; (2) minimum/maximum 

shut-down time; (3) minimum duration for dispatch; (4) targeted demand reduction level; 

(5) bids “down to” a designated megawatt level; and (6) guaranteed minimum LMP.95 

72. Similarly, California PUC requests that the Commission expand its proposal to 

include all demand response resource bids in all aspects of wholesale markets, and also 

permit each demand resource bidder to submit, as part of its bid and a master file, its 

output constraints such as minimum load reduction, minimum load, load reduction 

initiation time, minimum load reduction time, maximum load reduction time, minimum 

base load time, maximum number of daily load curtailments, minimum and maximum 

daily energy limits, load pick up rate, load drop rate, load reduction initiation cost, and 

minimum load reduction cost.96

 94 APPA at 36-37. 

95 Steel Producers at 4-5. 

96 California PUC at 13-14. 
Docket Nos. RM07-19-000 and AD07-7-000 - 39 - 

73. Multiple commenters argue for a regional approach in implementing the 

Commission’s proposal.97 For instance, EEI and Detroit Edison state that they support 

the Commission’s proposal provided that RTOs and ISOs can establish lower or 

minimum limits for such service.98 EEI asks that RTOs and ISOs be allowed to specify 

the minimum duration in hours or minimum number of times per day or week that a 

resource may be called upon. Duke Energy states that the specific bid parameters, as 

well as the methodologies and procedures that RTOs and ISOs use to implement the 

Commission’s proposal, should be developed on a regional basis within their stakeholder 

processes, rather than through a Commission-imposed uniform requirement in the Final 

Rule.99 NYISO also contends that a regional approach is appropriate because specifying 

bidding parameters in the regulations may prove problematic in the future as regional 

market designs continue to evolve.100 Exelon agrees with the Commission that minimum 

requirements for bidding parameters should not be prescribed by the Commission in this 

rulemaking, but rather should be developed by RTOs and ISOs. Exelon also supports the 

Commission’s proposed requirement that RTOs and ISOs provide justification for any 

necessary regional variations.101 EnerNOC believes the Commission, by requiring 

 97 E.g., EEI; Detroit Edison; Duke Energy; ISO/RTO Council; North Carolina 

Electric Membership; NYISO; and Kansas CC. 

98 EEI at 13; Detroit Edison at 2-3. 

99 Duke Energy at 4. 

100 NYISO at 6. 

101 Exelon at 6. 
Docket Nos. RM07-19-000 and AD07-7-000 - 40 - 

coordination and justification for variations, without mandating standardization, has 

articulated the correct compromise.102

74. Midwest ISO and CAISO state that their market designs already satisfy the 

NOPR’s proposed bidding parameters requirement. Midwest ISO states that it developed 

its bidding parameters through the stakeholder process and that the parameters were 

approved by the Commission within its ASM Order.103 Therefore, Midwest ISO asks 

that the Commission find that its ASM proposal satisfies the NOPR’s requirement 

regarding bidding parameters. Similarly, CAISO states that it is developing its ancillary 

services market and it will comply with the proposed bidding parameters in the Release 

1A enhancements to MRTU.104

75. Further, several commenters support making additional parameters available for 

all bidders, to include both demand and supply resources.105 Wal-Mart states that 

comparable rules could apply to supply resources as long as neither supply nor demand 

 102 EnerNOC at 9. 

103 Midwest ISO at 10. Midwest ISO states that its tariff allows market 

participants (both generators and demand response resources) to specify hourly ramp 

rates, hourly economic minimum and maximum limits, hourly regulation minimum and 

maximum limits, minimum and maximum run times, as well as a maximum start-up 

limit, which establishes the maximum number of times the resource can be called upon 

within a twenty-four-hour period. 

104 CAISO at 2. 

105 E.g., California DWR at 12; Duke Energy at 4; EEI at 14; EnerNOC at 8; 

Exelon at 6; Midwest ISO at 10; Reliant at 4; and Wal-Mart at 5. 
Docket Nos. RM07-19-000 and AD07-7-000 - 41 - 

resources are provided with an advantage.106 Old Dominion states that all resources 

bidding into the ancillary services markets should be susceptible to the same penalties, 

performance and reliability requirements.107 Exelon states that as long as the 

specification of operational limitations does not impair market efficiency, demand and 

supply resources should be treated on a comparable basis because they provide reliable 

and efficient capacity to RTOs and ISOs.108

76. The California DWR supports making new parameters available to all resources 

because certain facilities have a specific purpose that is distinct from sales to, or support 

of, the electric grid. For instance, hydroelectric generation sites must satisfy water 

storage, water delivery, and related operational requirements. The California DWR 

asserts that any RTO or ISO requirements must accommodate this primary purpose for 

these resources.109 

77. Several commenters state that new bidding parameters should not be available 

to all resources.110 For instance, TAPS states that there is already ample bidding 

flexibility for generators, and it is concerned about the possibility of creating unintended 

consequences such as new gaming opportunities. APPA states that RTO and ISO 

 106 Wal-Mart at 5. 

107 Old Dominion at 8. 

108 Exelon at 5-6. 

109 California DWR at 12-13. 

110 E.g., APPA at 37; Mr. Borlick at 2; and TAPS at 8. 
Docket Nos. RM07-19-000 and AD07-7-000 - 42 - 

ancillary services markets are already complex and accommodating additional bid 

parameters for generators in their software and problem solving algorithms would make 

the markets even more complicated. Although EEI is in agreement with making new 

bidding parameters available for all bids, it is concerned that applying the new parameters 

to generation resources without evaluating the implications could result in creating 

unintended incentives. Therefore, EEI suggests that RTOs and ISOs should not be 

required to apply the new parameters across all generating resources as long as they 

provide justification for treating some generating resources differently. 

78. Finally, among the supporters of this proposal, EEI states that the addition of 

new parameters to bidding rules must not result in any fundamental change to existing 

market designs or affect the efficiencies of co-optimized markets.111 

79. Several commenters state that demand response providers should be allowed to 

sell into the ancillary services markets without being required to sell into the energy 

market.112 Comverge is in favor of this, but notes that demand response providers should 

also be allowed to sell into the energy market on a voluntary basis. Beacon Power states 

that a generator is always capable of supplying energy and, therefore, does not face the 

financial risks and barriers that a non-generator faces if it is forced to bid into the energy 

market. 

 111 EEI at 14. 

112 E.g., Beacon Power at 9; Comverge at 12; and Wal-Mart at 5. 
Docket Nos. RM07-19-000 and AD07-7-000 - 43 - 

80. NEPOOL Participants opposes the Commission’s proposal to implement new 

bidding parameters for demand response resources. NEPOOL Participants states that 

each region needs an opportunity to evaluate this issue more fully and consider whether 

bidding limits are the most appropriate solution and whether such limits or other reforms 

should be restricted to just demand response or include other kinds of resources. It 

asserts that any change in bidding requirements needs to ensure comparability with others 

resources and that system reliability is maintained.113 Maine PUC agrees.114

ii. Commission Determination

81. The Commission determines that each RTO and ISO is required to allow demand 

response resources to specify limits on the duration, frequency and amount of their 

service in their bids to provide ancillary services—or their bids into the joint energyancillary services markets in the co-optimized RTO markets. As noted in the NOPR (and 

several commenters agree), these limits are comparable to the limits generators may 

specify on price, quantity, startup and no-load costs, and minimum downtime between 

starts.115 All RTOs and ISOs must incorporate new parameters into their ancillary 

services bidding rules that allow demand response resources to specify a maximum 

duration in hours that the demand response resource may be dispatched, a maximum 

number of times that the demand response resource may be dispatched during a day, and 

 113 NEPOOL Participants at 11-12. 

114 Maine PUC at 3-4. 

115 NOPR, FERC Stats. & Regs. ¶ 32,628 at P 62. 
Docket Nos. RM07-19-000 and AD07-7-000 - 44 - 

a maximum amount of electric energy reduction that the demand response resource may 

be required to provide either daily or weekly. 

82. This requirement eliminates a major barrier to participation of demand response 

resources in ancillary services markets by ensuring that demand response resources are 

treated comparably to supply-side resources. In this regard, the Commission agrees with 

comments from APPA, Duke Energy, and others that argue that the desire of many enduse customers to reduce their consumption levels on short notice may decrease the more 

frequently they are called upon. This requirement would allow those customers to limit 

the frequency with which they are called upon to reduce demand, and thus make it more 

economically beneficial for these resources to participate in ancillary services markets. 

83. The Commission’s requirement also enhances competition within ancillary 

services markets. With demand response resources able to specify the duration, 

frequency and amount of their service, ancillary services markets will become more 

attractive for such resources. Increased participation in the market will result in an 

expanded pool of available resources, thereby potentially improving demand elasticity 

and system reliability, as well as lessening price volatility. 

84. The Commission also finds that this requirement removes barriers to the 

comparable treatment of demand-side and supply-side resources. Generators include 

operational constraints in their bids, and permitting demand response resources to do the 

same results in the comparable treatment of both supply-side and demand-side resources. 

However, in keeping with this effort of greater comparability, the Commission 

determines that implementation of its requirement by RTOs and ISOs should not lead to 
Docket Nos. RM07-19-000 and AD07-7-000 - 45 - 

either demand-side or supply-side resources being afforded an undue advantage within 

ancillary services markets. 

85. In the NOPR, the Commission requested comment on whether other bidding 

parameters should be considered.116 The Commission noted that any proposed 

parameters must not have the effect of creating an undue preference for demand response 

resources. The Commission does not have a sufficient record here to assess whether the 

proposed additional bidding parameters submitted by the California PUC and Steel 

Producers may offer demand response resources greater flexibility within their bids as 

compared to the bids of generators. For this reason the Commission will not accept the 

proposed additional bidding parameters on a generic basis for all RTOs and ISOs in this 

rulemaking. Rather, individual RTOs and ISOs are free to propose additional parameters 

in their compliance filings, as long as they do not provide undue preference to demand 

response resources vis-à-vis supply-side resources, and interested persons may raise these 

additional parameters with their deliberations with the individual RTOs and ISOs. 

86. In the NOPR, the Commission stated that it was not appropriate for the 

Commission to develop in a rulemaking a standardized set of minimum requirements for 

minimum size bids, measurement, telemetry and other factors, and instead allowed RTOs 

and ISOs to develop their own minimum requirements, including bidding parameters.117 

The Commission adopts this position in this Final Rule. RTOs and ISOs must 

 116 Id. P 64. 

117 Id.
Docket Nos. RM07-19-000 and AD07-7-000 - 46 - 

incorporate bidding parameters that allow demand response resources to specify 

limitations on the duration, frequency and amount of their service. However, the 

development of specific parameters and the methods used to implement the 

Commission’s requirement are the responsibility of the RTOs and ISOs, in consultation 

with their respective stakeholders. RTOs and ISOs are also required to confer with each 

other on such parameters and methods and to provide a technical and factual basis for any 

necessary regional variations. This approach adequately accounts for regional variation 

between the RTOs and ISOs and alleviates the concerns of those commenters requesting 

regional flexibility in implementing the Commission’s requirement. 

87. Midwest ISO asks that the Commission find that it already complies with the 

additional bidding parameters requirement of the Final Rule. Similarly, the California 

ISO asserts that it will also be compliant with the requirement upon Release 1A in its 

MRTU process. The Commission does not intend to interrupt the progress being made in 

either region. However, as indicated above, the Commission will not at this time 

determine that either region satisfies the Commission’s requirement obligating RTOs and 

ISOs to incorporate new bidding parameters for demand response resources, and instead 

will wait until each region submits its necessary compliance filing. 

88. In the NOPR, the Commission requested comment on whether these additional 

parameters should be available for all bids, or for demand response bids only. In light of 

the comments received, the Commission determines that new requirements for bidding 

rules allowing demand response resources to specify the duration, frequency and amount 

of their service pertain only to demand response resources. Individual RTOs and ISOs 
Docket Nos. RM07-19-000 and AD07-7-000 - 47 - 

are free to propose to apply them more broadly. While the Commission understands that 

making these new parameters available for all resources could benefit hydropower 

resources and other environmentally restricted, or run-time limited resources, the 

Commission agrees with TAPS and others that there is already sufficient bidding 

flexibility afforded to generators, and is concerned about the possibility of creating 

unintended consequences. For these reasons, at this time the Commission will not 

require an RTO or ISO to make these new bidding parameters available for all resources. 

89. With regard to comments that demand response providers should be allowed to 

sell into the ancillary services markets without being required to sell into the energy 

market, the Commission notes that the ANOPR proposal permitting such action was 

removed at the NOPR stage, and replaced with a proposal to allow demand response 

resources to specify limitations on the duration, frequency and amount of their service.118 

The Commission had received comments previously that argued that allowing demand 

response resources to bid into the ancillary services markets without also bidding into the 

energy markets could upset certain market efficiencies in co-optimized markets. 

Therefore, the Commission put forth a compromise proposal, which allows demand 

response resources to specify operational limits in their bids as a way for these resources 

to minimize the risk that they are called on too frequently, thereby making participation 

in ancillary services markets more feasible. No one has persuaded us otherwise; 

therefore, the Commission will adopt this provision from the NOPR. 

 118 Id. P 62. 
Docket Nos. RM07-19-000 and AD07-7-000 - 48 - 

c. Small Demand Response Resource Assessment

90. The NOPR proposed to direct RTOs and ISOs to assess the value and technical 

feasibility of small demand response resources providing ancillary services one year from 

the effective date of the Final Rule, including whether (and how) smaller demand 

response resources can reliably and economically provide operating reserves through 

pilot projects or other mechanisms.119

i. Comments

91. Several commenters support the NOPR proposal for small demand response 

resource assessment.120 For example, Reliant states that accommodating smaller demand 

response resources may result in an increase in operating reserves.121 EnerNOC believes 

that the assessment effort will reveal ways for smaller demand response resources to 

provide ancillary services while maintaining reliable operations and appropriate 

measurement and verification.122 APPA believes that pilot programs could be 

particularly valuable in assessing technical feasibility of accommodating smaller 

demand-side resources.123 It notes that accurate metering and telemetry would be 

significant factors in any efforts associated with this assessment, primarily because 

 119 Id. P 59. 

120 E.g., APPA, Public Interest Organizations, EnerNOC; DRAM; Old Dominion; 

and Reliant. 

121 Reliant at 4. 

122 EnerNOC at 3. 

123 APPA at 35. 
Docket Nos. RM07-19-000 and AD07-7-000 - 49 - 

“communication and operational performance standards applicable to demand-side 

resources are more demanding than the current requirements applicable to retail 

customers.” Public Interest Organizations request that “RTOs and ISOs be directed to 

specifically address the issue of comparable treatment of smaller loads.”124 Allied Public 

Interest Groups believe that the Commission should include in its Final Rule a directive 

to RTOs and ISOs to initiate pilot programs for small demand response resources similar 

to the ISO New England Demand Response Reserves Pilot Program.125 In their view, 

pilot programs aid grid operators in determining whether a diverse portfolio of demand 

response resources that includes small resources can provide cost-effective and reliable 

ancillary services. 

92. EnerNOC and DRAM indicate that technical requirements for demand response 

participation in ancillary services markets may act as a barrier if the technical 

requirements exceed what is necessary to ensure reliable electric system operations.126 

For example, they note that certain telemetry requirements may preclude smaller loads 

from participating in ancillary services markets. However, EnerNOC states that an 

assessment on how to accommodate these resources could result in reasonable standards 

for smaller loads that take into account the operational characteristics of such loads so as 

to capture their value efficiently. DRAM states that the proposed assessment should 

 124 Public Interest Organizations at 6. 

125 Allied Public Interest Groups at 9. 

126 EnerNOC at 4; DRAM at 16. 
Docket Nos. RM07-19-000 and AD07-7-000 - 50 - 

allow parties to focus on how best to modify the requirements for small demand response 

resource participation without creating a bias against supply-side resources.127 Neither 

EnerNOC nor DRAM suggests that smaller demand response resources be allowed to 

participate in these markets with less stringent standards than other resources. Further, 

EnerNOC asserts that the small demand response resource assessment requirement 

should not be used as an excuse to delay currently underway pilot programs or other 

smaller resource reforms taking place in RTOs and ISOs. In addition, this requirement 

should not create an opportunity to avoid addressing barriers to smaller resource 

participation in ancillary services markets.128

93. Old Dominion supports the proposal and agrees that incorporating smaller demand 

response resources would be beneficial to the market, but notes that measurement and 

verification standards specific to these smaller resources may be necessary to ensure 

proper allocation of costs and to address any reliability concerns.129

94. Two commenters disagree on how smaller demand response resources should be 

defined. EnerNOC recommends that the Commission clarify that “smaller demand 

response resources” should be construed more broadly than the residential class of 

customers because a more diverse portfolio is more valuable to the market. EEI, 

however, disagrees and recommends that the Commission not define what constitutes 

 127 DRAM at 16. 

128 EnerNOC at 6. 

129 Old Dominion at 8. 
Docket Nos. RM07-19-000 and AD07-7-000 - 51 - 

smaller demand response resources, and instead allow each RTO or ISO to propose a 

definition that reflects its particular market design and characteristics.130 

95. The ISO/RTO Council comments that its Markets Committee is already 

addressing certain aspects of this issue by developing a communications protocol for 

small demand resources, and that these efforts will be discussed at a technical conference 

on integrating small demand resources into organized markets. The ISO/RTO Council 

asserts that its report will not supplant the Commission’s proposed assessment, but still 

urges the Commission to coalesce its proposal with the work of the ISO/RTO Council 

Markets Committee.131

96. Finally, ISO New England notes that it currently has a demand response reserve 

pilot program in place to assess the ability of smaller demand resources to provide 

reserve products to the wholesale market, and to develop comparable communication, 

metering, telemetry and other technical infrastructure solutions that are more suitable and 

cost effective for smaller, dispersed demand resources.132 

ii. Commission Determination

97. The Commission will require RTOs and ISOs, in cooperation with their customers 

and other stakeholders, to perform an assessment, through pilot projects or other 

mechanisms, of the technical feasibility and value to the market of smaller demand 

 130 EEI at 12. 

131 ISO/RTO Council at 6. 

132 ISO New England at 4. 
Docket Nos. RM07-19-000 and AD07-7-000 - 52 - 

response resources providing ancillary services, within one year from the effective date 

of the Final Rule, including whether (and how) smaller demand response resources can 

reliably and economically provide operating reserves and report their findings to the 

Commission. The choice between either a pilot program or other mechanisms in this 

assessment is appropriately left to the discretion of the RTO or ISO and its customers and 

other stakeholders. Additional issues raised here by commenters, such as the need for 

measurement and verification standards and a definition of what constitutes a “small 

demand response resource” should be addressed in the assessments. 

98. The Commission finds that, based on the comments, accommodating smaller 

demand response resources through adjusted minimum size thresholds and telemetry 

requirements could result in an increase in potential operating reserves. Allowing more 

resources to participate in operating reserves and other ancillary services markets may 

increase the competitiveness of these markets and could lower the overall price for such 

services. 

99. The Commission agrees that this assessment should not delay pilot programs that 

are currently underway or other smaller load reforms taking place in RTOs and ISOs, nor 

should it create an opportunity to avoid addressing barriers to smaller load participation 

in ancillary services markets. In addition, while not part of the Commission’s 

requirement, the Commission encourages the ISO/RTO Council to continue developing a 

communications protocol for small demand response resources and encourages RTOs and 

ISOs to consider the ISO/RTO Council’s work in developing their individual 

assessments. 
Docket Nos. RM07-19-000 and AD07-7-000 - 53 - 

3. Eliminating Deviation Charges During System Emergencies

a. Deviation Charges

100. The Commission proposed in the NOPR to require that all RTO and ISO tariffs be 

modified as necessary to eliminate a charge– referred to as a deviation charge133– to a 

buyer134 in the energy market for taking less electric energy than it planned to take in the 

real-time market, during a real-time market period for which the RTO or ISO declares an 

operating reserve shortage or makes a generic request to reduce load to avoid an 

operating reserve shortage.135 

101. The Commission proposed that an RTO or ISO must either propose amendments 

to its tariffs to comply with this requirement or demonstrate through a compliance filing 

that its existing tariff and market design meet this requirement. The Commission 

proposed that this filing be submitted within six months of the date that this Final Rule is 

published in the Federal Register. 

102. The Commission’s proposal applies to real-time demand response that occurs in 

addition to the demand response of participants in an RTO’s or ISO’s wholesale demand 

 133 Deviation charges recover certain costs, including generators’ costs (such as 

start-up costs) that exceed their energy market revenues when real-time demand is less 

than forecast. These “uplift” costs may include the cost of extra generators committed 

after the close of the day-ahead market to serve anticipated load, if those costs are not 

recovered from sales of energy at real-time LMPs. 

134 Examples of buyers in RTO and ISO energy markets include an LSE that 

purchases electricity to meet the load requirements of its retail customers and a retail 

customer that purchases electricity directly from the wholesale market. 

135 NOPR, FERC Stats. & Regs. ¶ 32,682 at P 72. 
Docket Nos. RM07-19-000 and AD07-7-000 - 54 - 

response program. Under the proposal, deviation charges would be eliminated only when 

the RTO or ISO announces an emergency situation after the close of the day-ahead 

market. The Commission also proposed that since deviation charges cover real costs to 

generators and others that are not recovered from the sale of energy in real time, these 

costs should be allocated to all loads of the RTO or ISO. 

i. Comments

103. A majority of commenters supports the Commission’s proposal and agree that 

eliminating deviation charges during periods when the RTO or ISO declares an operating 

reserve shortage or makes a generic request to reduce load to avoid an operating reserve 

shortage would eliminate a barrier to demand reduction in wholesale energy markets.136 

For instance, Energy Curtailment and PG&E state that penalizing an LSE for taking less 

energy in real-time during system emergencies would be counterproductive.137 Many 

 136 Ameren at 23; American Forest at 6; APPA at 3; BlueStar Energy at 2; Mr. 

Borlick at 2; BP Energy at 15; California DWR at 15; CASIO at 1; California PUC at 15; 

Cogeneration Parties at 3; Comverge at 17; DC Energy at 5; Dominion Resources at 6; 

DRAM at 18; Duke Energy at 5; EEI at 14; Energy Curtailment at 4; EnerNOC at 11; 

Exelon at 6; FirstEnergy at 8; Industrial Coalitions at 11; Industrial Consumers at 15; 

Integrys Energy at 9; ISO New England at 8; ISO/RTO Council at 6; LPPC at 7; MADRI 

States at 6; Maine PUC at 3; Midwest Energy at 2; Midwest ISO at 11; NCPA at 5; 

NEPOOL Participants at 12; NIPSCO at 9; North Carolina Electric Membership at 4; 

Ohio PUC at 7; Old Dominion at 9; OMS at 3; OPSI at 4; Pennsylvania PUC at 11; 

PG&E at 8; Public Interest Organizations at 6; Reliant at 4; Steel Manufacturers at 11; 

Steel Producers at 5; TAPS at 9; Wal-Mart at 5; and Xcel at 8. 

137 Energy Curtailment at 4-5; PG& E at 8. 
Docket Nos. RM07-19-000 and AD07-7-000 - 55 - 

commenters agree that this proposal would result in several benefits, including reduced 

market prices, mitigation of market power, and improved system reliability.138 

104. Several supporters also agree with the Commission’s proposal to allocate to all 

loads of the RTO and ISO uplift charges to cover costs associated with the elimination of 

such deviation charges.139 However, NIPSCO and Old Dominion state that uplift charges 

should be allocated only within the zones where the emergency occurred.140 Dominion 

Resources and ISO/RTO Council urge the Commission to allow each region to decide 

how the costs should be allocated based on market constraints and input from 

stakeholders.141

105. Several commenters seek clarification of various aspects of the proposal. For 

instance, EEI asks the Commission to clarify that deviation charges would be eliminated 

only when the RTO or ISO announces an emergency situation after the close of the dayahead market.142 TAPS suggests that the Commission clarify that it intends to encompass 

all forms of demand response that could be activated to reduce load during emergencies, 

including programs that operate behind the meter of the LSE with a reduction reflected in 

 138 While APPA supports this proposal, it states that if bid and offer caps are 

eliminated during system emergencies, it cannot support uplifting such charges. APPA at 

3. 

139 E.g., Ohio PUC at 7-8; Public Interest Organizations at 6; EEI at 14-15; DRAM 

at 18-19. 

140 NIPSCO at 9; Old Dominion at 9. 

141 Dominion Resources at 8-9; ISO/RTO Council at 6-8. 

142 EEI at 14-15. 
Docket Nos. RM07-19-000 and AD07-7-000 - 56 - 

the wholesale market participant’s demand.143 Cogeneration Parties note that it is unclear 

whether the costs caused by uninstructed deviations during normal operations would also 

be incurred during a system emergency, and recommend that the Final Rule require 

RTOs and ISOs to verify their actual costs incurred during system emergencies before 

such charges are imposed on customers.144 Similarly, Midwest Energy suggests that the 

net benefits for load reductions be verified before costs are imposed on customers.145 

106. A few commenters urge the Commission to clearly define “deviation charge” and 

the circumstances under which deviation charges would be eliminated. For example, 

NYISO requests that the Commission clarify its proposed regulatory text to more 

specifically define deviation charges.146 Others state that circumstances under which an 

RTO or ISO merely seeks to avoid an operating reserve shortage are significantly 

different from those in which it has experienced an actual operating reserve shortage or 

emergency. Therefore, they suggest that the Commission define the conditions when 

elimination of deviation charges would take place.147 NIPSCO states that the 

Commission should clarify that deviation charges should also be waived when an RTO or 

 143 TAPS at 9-11. 

144 Cogeneration Parties at 3. 

145 Midwest Energy at 3. 

146 NYISO at 7-8. 

147 E.g., DRAM at 18-19; Comverge at 17-18; and NIPSCO at 12-14. 
Docket Nos. RM07-19-000 and AD07-7-000 - 57 - 

ISO declares a NERC Energy Emergency Alert.148 The Pennsylvania PUC states that 

there are two types of emergencies, generation insufficiency and generation excess, and 

while generation insufficiency is of greatest concern to the public, excess generation 

emergencies are not uncommon. At such times locational marginal price or LMP may go 

negative in an effort to resolve a rapidly dropping load situation. For such reasons the 

Pennsylvania PUC asks that the Commission clarify whether eliminating a deviation 

charge is appropriate for both kinds of emergencies.149

107. Additionally, some commenters recommend that the proposal should be expanded 

so that deviation charges would be eliminated not just in emergency situations, but in all 

situations when demand deviates from schedule by using less energy.150 Duke urges the 

Commission to eliminate deviation charges so long as the load remains within an 

appropriate demand response “bandwidth.”151 No deviation charges would be assessed in 

emergency or non-emergency situations, so long as the load behaves consistently with the 

price-sensitive demand schedule provided to the RTO or ISO. Other commenters suggest 

 148 NIPSCO at 12-14. The NERC reliability standard provides procedures that 

RTOs and ISOs must follow when capacity emergencies are declared and requires that all 

resources be used to meet load before operating reserves are tapped to address an 

emergency. 

149 Pennsylvania PUC at 11. 

150 E.g., California PUC at 15-16; Industrial Consumers at 15-16; and Steel 

Manufacturers at 11-12. 

151 Duke suggests that a reasonable solution to preventing inequitable cost shifts is 

to establish a bandwidth that would determine whether deviation charges should apply. 

Duke at 5-7. 
Docket Nos. RM07-19-000 and AD07-7-000 - 58 - 

that the proposal be expanded to include other contractual arrangements,152 demandreduction services,153 and programs that compensate market participants for demand 

reductions during system emergencies.154 

108. Several commenters support a regional approach to establishing methods for 

dealing with deviation charges. For example, ISO/RTO Council urges the Commission 

to allow each RTO or ISO to develop its own appropriate rules to implement the proposal 

to account for regional operating considerations and to establish appropriate details, 

including defining what system conditions constitute an emergency.155 California Munis 

urges regional flexibility to ensure that specific facts pertaining to each RTO or ISO can 

be fully considered in assessing whether this proposal will be beneficial to consumers or 

merely shifts costs among consumers.156 Similarly, SoCal Edison-SDG&E state that, 

rather than having the Commission eliminate deviation charges in a uniform manner for 

 152 NCPA states that the Commission’s proposal to allow RTOs and ISOs to waive 

deviation charges should be expanded to include other contractual arrangements to the 

degree that ARCs are permitted to perform aggregations of retail load. NCPA at 5-6. 

153 OMS recommends that the Commission direct RTOs and ISOs to explore the 

development of programs that compensate market participants for demand reductions 

during system emergencies. OMS at 3. 

154 Id. at 3. Similarly, EEI asks the Commission to allow RTOs and ISOs to 

propose compensation sufficient to encourage demand response resources to incur the 

cost of reducing consumption. EEI at 14-15. 

155 ISO/RTO Council at 6-8. 

156 California Munis is not opposed to the Commission’s proposal, but states that 

there are California-specific issues that must be considered, which may lead to a policy 

conclusion that elimination of deviation charge may not be appropriate for California. 

California Munis at 11-12. 
Docket Nos. RM07-19-000 and AD07-7-000 - 59 - 

all RTOs and ISOs, a method for dealing with deviations from the day-ahead energy 

market purchases must be considered comprehensively by each RTO or ISO within the 

framework of its overall market design.157 

109. NEPOOL Participants states that the Commission should not impose its proposal 

on RTOs and ISOs before allowing NEPOOL Participants to evaluate, through its 

stakeholder process, issues around how deviation charges are calculated and assessed, 

including ISO New England’s ability to separate out the types of deviation charges that 

the Commission has proposed.158 

110. Constellation opposes this proposal, stating that eliminating deviation charges 

during system emergencies could create unintended consequences. Constellation 

believes that the proposal provides preferential treatment for energy providers that supply 

load reductions over generators that supply a similar product. Constellation argues that 

deviation charges are appropriate because such charges provide: (1) an incentive for 

LSEs to accurately forecast and bid their load into the day-ahead market; and (2) a source 

of funds to compensate out-of-market generators that are necessary to meet peak load 

when the real-time load deviates from its day-ahead load bid.159 In addition, 

 157 SoCal Edison-SDG&E state that eliminating charges in a uniform manner to all 

demand does not recognize the locational benefits of reducing demand in certain areas or 

cases where decreasing demand could hinder efforts to address grid reliability concerns. 

SoCal Edison-SDG&E at 3. 

158 NEPOOL Participants at 14. 

159 Constellation at 6. 
Docket Nos. RM07-19-000 and AD07-7-000 - 60 - 

Constellation states that opportunities for the demand side of the market to respond are 

lost whenever supply resources are compensated outside of market-clearing prices 

through the use of uplift charges. It believes this problem can be alleviated through 

proper price formation.160 For these reasons, Constellation recommends that the 

Commission leave the deviation charge in place and institute a shortage pricing regime, 

and address other issues that socialize out-of-market costs in order to minimize socialized 

uplift charges.161

ii. Commission Determination 

111. The Commission adopts the NOPR proposal to require all RTOs and ISOs to 

modify their tariffs to eliminate a deviation charge to a buyer in the energy market for 

taking less electric energy in the real-time market than was scheduled in the day-ahead 

market during a real-time market period for which the RTO or ISO declares an operating 

reserve shortage or makes a generic request to reduce load in order to avoid an operating 

reserve shortage. This requirement does not apply to RTO or ISO wholesale demand 

response program participants, but rather to market buyers who voluntarily provide 

additional demand response either during or prior to an RTO- or ISO- directed operating 

reserve shortage in an effort to improve system reliability. 

112. Removal of the deviation charge during a system emergency will eliminate a 

disincentive for participation of demand response in the real-time market. A buyer may 

 160 Id. at 7. 

161 Id. at 6-7. 
Docket Nos. RM07-19-000 and AD07-7-000 - 61 - 

be deterred from reducing demand during periods of reserve shortage if that buyer is 

subject to a charge for reducing its real-time consumption below its day-ahead purchases 

at the request of the RTO or ISO market operator. This unintended disincentive may 

result in the buyer maintaining a higher level of demand or discourage an LSE from 

calling on the demand response resources in its retail market. Removal of this 

disincentive will help maintain system reliability and help reduce prices during system 

emergencies. 

113. Demand response program participants currently are not levied a deviation charge 

if they reduce demand as directed by the RTO or ISO, and the Commission’s requirement 

in this Final Rule does not alter this practice. In addition, the Commission is not 

requiring that RTOs and ISOs remove penalties for day-ahead bidders of demand 

response that fail to follow dispatch instructions to reduce demand in real time. What this 

requirement does focus on is demand response that is provided by LSEs and other market 

buyers that consume less total energy in real time during system emergencies or at the 

request of the RTO or ISO than they had scheduled in the day-ahead market. The intent 

of the Commission’s requirement is not only to ensure that market buyers who 

voluntarily reduce their energy consumption during system emergencies at the request of 

the RTO or ISO are not penalized for their deviation, but also that demand-side and 

supply-side resources are treated comparably. 

114. As noted above, a majority of commenters support this requirement and agree that 

removal of these deviation charges would remove a disincentive for demand reduction. 

Elimination of deviation charges for a buyer’s response to RTO and ISO calls for demand 
Docket Nos. RM07-19-000 and AD07-7-000 - 62 - 

reductions also will further comparable treatment of demand and supply resources. RTO 

and ISO tariffs already do not impose deviation charges on generators that generate more 

power during system emergencies than scheduled in the day-ahead market. 

115. An RTO or ISO must either propose amendments to its tariff to comply with this 

requirement or demonstrate in a compliance filing that its existing tariff and market 

design already satisfy this requirement. This compliance filing must be filed with the 

Commission within six months of the date that this Final Rule is published in the Federal 

Register. The Commission will assess each filing to determine if it satisfies the 

requirements of this section and will issue additional orders, as needed. This process 

addresses comments by RTO/ISO Council, California Munis, SoCalEdison-SDG&E, 

NEPOOL Participants and others recommending regional flexibility in addressing this 

issue. 

116. The Commission encourages each RTO and ISO to work with its customers and 

other stakeholders in making tariff revisions and other changes to its market design 

necessary to comply with this requirement. The Commission’s goal is to remove barriers 

to the development and use of demand response resources in wholesale energy markets, 

and the Commission expects that barriers can be effectively removed if each RTO and 

ISO works effectively and cooperatively with its customers and stakeholders. 

117. Although the majority of commenters express support for this requirement, as 

noted above, a significant number ask for clarification or suggest changes to the NOPR 

proposal. Customer demand reduction in response to an emergency appeal benefits all 

customers, by averting or reducing the severity of a power shortage, so voluntary 
Docket Nos. RM07-19-000 and AD07-7-000 - 63 - 

reductions during system emergencies can provide system-wide benefits. They can help 

maintain system reliability and reduce overall energy prices, which benefits all 

customers. As a result, the Commission finds that socialization of these costs is justified. 

However, in response to comments by NIPSCO and Old Dominion that the deviation 

charge should be allocated locally rather than on a system wide basis, this matter is best 

addressed in each RTO’s or ISO’s compliance filing. Any proposal for local allocation 

of these costs should be accompanied by an explanation of when costs would be spread 

across the entire RTO or ISO region and when applied locally, how the local area would 

be determined, and why local cost recovery is justified. Further, in response to comments 

by EEI and NIPSCO, we clarify that deviation charges would be eliminated only when 

the RTO or ISO announces an emergency situation or requests a voluntary load reduction 

after the close of the day-ahead market. 

118. In response to TAPS’s request for clarification on what forms of demand response 

this requirement would apply to, we note that this requirement applies to all buyers in the 

wholesale energy market, outside of an RTO’s or ISO’s demand response program, that 

may respond to an RTO or ISO request for voluntary load reduction during a system 

emergency. In response to comments by Cogeneration Parties and Midwest Energy state 

that the costs and benefits of load reduction must be verified before costs are imposed on 

customers, measurement and verification protocols should be addressed within the 

RTO’s or ISO’s compliance filing, and therefore will not require a net benefits test. In 

order to accommodate regional differences, we will also defer NYISO’s request that the 
Docket Nos. RM07-19-000 and AD07-7-000 - 64 - 

Commission specify more clearly the definition of “deviation charge” to the compliance 

filing process (which will permit stakeholder input). 

119. The Pennsylvania PUC asked for clarification of whether it is appropriate to 

eliminate deviation charges during periods of excess generation, when RTOs and ISO 

might call upon generators to reduce supply. The Commission notes that the intent of 

this Final Rule is to remove disincentives to demand-side resources so that they can be 

treated similarly and comparably in relation to supply-side resources. While it may be 

appropriate to remove deviation charges for supply-side resources during periods of 

excess generation, issues involving periods of excess generation are not addressed in this 

rulemaking. 

120. We disagree with comments by the California PUC, Industrial Consumers and 

Steel Manufacturers recommending that deviation charges be eliminated any time 

demand deviates from schedule by using less energy. As noted in the NOPR, a reduction 

in demand during a system emergency benefits the RTO or ISO and its customers by 

better matching demand with available supply.162 The Pennsylvania PUC mentions in its 

comments that if actual demand deviates from scheduled demand during non-emergency 

periods, such load reductions may result in periods of excess supply and impose costs on 

the RTO or ISO and its customers. Similarly, Duke’s request that no deviation charges 

be assessed, so long as load remains within a specified bandwidth, may lead to greater 

disparity between day-ahead and real-time market purchases and could result in 

 162 NOPR, FERC Stats. & Regs. ¶ 32,628 at P 77. 
Docket Nos. RM07-19-000 and AD07-7-000 - 65 - 

additional costs to consumers without providing consumer benefits. In particular, 

eliminating deviation charges for all periods could result in over-scheduling, which has 

cost consequences for generators. Therefore, the Commission does not accept these 

recommendations. 

121. With regard to Constellation’s recommendation that the Commission leave the 

deviation charge in place and institute a shortage pricing regime to better match supply 

and demand, the Commission is addressing shortage pricing issues in another part of this 

Final Rule. As noted above, we find that elimination of deviation charges for demand 

reduction during system emergency periods provides benefits to consumers distinct from 

those inherent in a shortage pricing regime and removes a disincentive to participation of 

demand-side resources by treating demand and supply comparably. The Commission 

therefore declines to adopt Constellation’s recommendation. 

b. Virtual Purchasers

122. In the NOPR, the Commission asked for comments on whether it should require 

RTOs and ISOs to modify their tariffs to eliminate deviation charges for virtual purchases 

during system emergencies.163 The Commission noted that virtual purchasers may not 

cause significant additional costs during an emergency. Instead, virtual purchases may 

 163 A virtual purchase (or sale) is a purchase (or sale) in the RTO or ISO day-ahead 

market that does not go to physical delivery. For example, an entity that does not serve 

load may make a purchase in the day-ahead market, which it must pay for, and then take 

no power in real time. This lack of consumption is treated as a sale of the purchased 

power into the real-time spot market. By making virtual energy purchases and sales in 

the day-ahead market and settling these positions in the real-time market, a market 

participant can arbitrage price differences between the two markets. 
Docket Nos. RM07-19-000 and AD07-7-000 - 66 - 

enhance reliability by increasing the amount of generation resources available in real time 

during a system emergency. Therefore, the Commission noted that assessing a deviation 

charge on virtual purchasers during an emergency may be unfair and may discourage 

helpful virtual purchases when system resources are expected to be tight.164 

i. Comments

123. Several commenters state that virtual purchasers should be treated in the same 

manner as other “physical” purchasers by exempting their day-ahead market bids from 

deviation charges during system emergencies.165 MADRI States and BP Energy assert 

that there is no need to assess deviation charges to virtual purchasers because such 

purchasers enhance reliability by increasing the amount of generation resources available 

in real-time during an emergency.166 Mr. Borlick asserts that virtual bids in the dayahead market do not impose any costs on the system; he states this is because an RTO 

and ISO is able to differentiate between virtual and physical bids and it can ignore the 

virtual bids when determining unit commitment for the next day’s real-time operations.167 

Further, DC Energy claims that all buyers of energy (physical and virtual buyers) in the 

real-time market should be treated equally.168

 164 NOPR, FERC Stats. & Regs. ¶ 32,628 at P 78. 

165 E.g., Mr. Borlick at 2-3; BP Energy at 15; Exelon; MADRI States; and DC 

Energy at 5-6. 

166 MADRI States at 6-7; BP Energy at 15. 

167 Mr. Borlick at 3. 

168 BP Energy at 5. 
Docket Nos. RM07-19-000 and AD07-7-000 - 67 - 

124. Exelon agrees with the elimination of charges for virtual purchasers during system 

emergencies, but suggests that the Commission allow each RTO or ISO to implement 

such a rule after exploring the consequences of such action through its stakeholder 

process.169

125. Other commenters oppose this option and state that virtual purchasers should be 

subject to deviation charges.170 For instance, First Energy and TAPS state that virtual 

purchasers provide no load reduction benefit and, therefore should not be exempt from 

paying the deviation charge. TAPS also states that the NOPR record contains no 

evidence that the hypothetical benefits of eliminating the deviation charge for virtual 

bidders would outweigh the harm that would result from removing deviation charges, as 

they act to discourage bidding behavior that imposes significant costs on consumers. 171 

Several commenters believe that exempting virtual purchasers from deviation charges 

(1) may encourage speculation; (2) result in over commitment of generation when it is 

not needed; and (3) result in cost shifts to other market participants, thereby distorting 

markets.172 APPA asserts that virtual bidders may be able to game the system and 

receive a payment when no benefit is provided to the region. 

 169 Exelon at 6-8. 

170 E.g., Ameren at 24; APPA at 3; ISO New England at 9; ISO/RTO Council at 8; 

Old Dominion at 10; and TAPS at 10. 

171 First Energy at 8; TAPS at 9-11. 

172 ISO New England at 8-9; RTO/ISO Council at 6-8; and NYISO at 7-8. 
Docket Nos. RM07-19-000 and AD07-7-000 - 68 - 

126. NEPOOL Participants believes that it is important to more fully evaluate the issues 

around virtual bidding and whether it is necessary to include virtual bidding in any 

discussion regarding the removal of deviation charges.173

ii. Commission Determination

127. The Commission agrees with the comments that virtual purchases can enhance 

reliability by increasing the amount of generation resources available in real-time during 

an emergency. Further, assessing a deviation charge on virtual purchasers during an 

emergency may be unfair and may discourage such virtual purchasing when it may be 

most beneficial to other customers. Our preferred policy is to eliminate deviation charges 

for virtual purchasers as well as physical purchasers during a real-time market period for 

which the RTO or ISO declares an operating reserve shortage or makes a generic request 

to reduce load in order to avoid an operating reserve shortage. However, we are 

concerned an RTO’s or ISO’s particular market design may not readily accommodate this 

policy, and we acknowledge commenters’ concerns about the possibility of market 

manipulation under a particular market design if deviation charges are removed for 

virtual purchasers. Therefore, we direct RTOs and ISOs to modify their tariffs to 

eliminate deviation charges for virtual purchasers, during the same period as they are 

eliminated for physical purchasers as set out above, unless the RTO or ISO upon 

compliance makes a showing that it would be appropriate to assess such deviation 

charges for virtual purchasers during this period. This approach establishes a reasoned 

 173 NEPOOL Participants at 13. 
Docket Nos. RM07-19-000 and AD07-7-000 - 69 - 

generic policy and still provides an opportunity for each RTO or ISO, on a case-by-case 

basis, to present a factual record that the generic policy does not fit its overall market 

design. 

4. Aggregation of Retail Customers

a. Commission Proposal

128. In the NOPR, the Commission proposed 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.174 

129. The Commission recognized that each region’s market design is different and that 

it is important for ARC provisions to respect these market design differences. For this 

reason, the Commission proposed not to mandate generic market rule amendments; 

rather, it proposed to require RTOs and ISOs to amend their tariffs and market rules as 

necessary to allow an ARC to bid demand response directly into the RTO’s or ISO’s 

organized market, provided that the ARC’s demand response bid must meet the same 

requirements as a demand response bid from any other entity such as an LSE. The 

NOPR proposed the following flexibilities in RTO and ISO market designs: 

• The RTO or ISO may require the ARC to be an RTO member if membership is a 

requirement for other bidders. 

 174 NOPR, FERC Stats. & Regs. ¶ 32,628 at P 86. 
Docket Nos. RM07-19-000 and AD07-7-000 - 70 - 

• RTOs and ISOs may require that an aggregated bid must consist of individual 

demand response bids from a single area, reasonably defined. 

• An RTO or ISO may place appropriate restrictions on any customer’s 

participation in an ARC-aggregated demand response bid to avoid counting the 

same demand response resource more than once. 

• The market rules do not have to allow bids from an ARC if this is not permitted 

under the laws or regulations of the relevant electric retail regulatory authority. 

The RTO or ISO must receive explicit notification from the relevant retail 

regulatory authority in order to disqualify a bid from an ARC that includes the 

demand response of that authority’s retail customers. 

130. The Commission requested comment about whether: (1) these features of the 

proposal are appropriate and whether there are additional appropriate criteria or features 

for allowing an ARC to bid demand response; and (2) there is any reason not to subject 

an ARC to the same requirements as any other bidder in the energy market.175 

131. The Commission proposed that an RTO or ISO must either propose amendments 

to its tariff to comply with the requirement or demonstrate in a filing that its existing 

tariff and market design already satisfy the requirement to permit an ARC to bid demand 

response on behalf of retail customers.176 It also proposed that this filing be submitted 

within six months of the date the Final Rule is published in the Federal Register. The 

 175 Id. P 88, 91. 

176 Id. P 92. 
Docket Nos. RM07-19-000 and AD07-7-000 - 71 - 

Commission proposed that it would assess whether each filing satisfies the proposed 

requirement and would issue additional orders as necessary. 

b. Comments

i. Comments regarding ARC proposal

132. Many commenters support the NOPR proposal to allow ARCs to bid demand 

response directly into organized markets, unless it is not permitted by the relevant 

regulatory authority.177 For instance, EEI asserts that the Commission should adopt this 

proposal in the Final Rule because it is appropriate for RTOs and ISOs to treat ARCs 

comparably to wholesale market participants under RTO and ISO rules as long as: (1) 

state commissions permit aggregation of retail demand response; (2) such treatment is 

aligned with state requirements; and (3) no preferential treatment is accorded to ARCs, 

including being subject to monitoring and verification requirements.178 Some 

commenters note that experiences in organized markets have demonstrated that allowing 

ARCs to participate directly in wholesale energy markets has increased market efficiency 

and led to greater diversity of demand response options.179 In particular, Comverge and 

 177 E.g., American Forest; BlueStar Energy; BP Energy; California PUC ; 

Comverge; DC Energy; Dominion Resources; DRAM; EEI; EnergyConnect; Energy 

Curtailment; EnerNOC; Exelon; FirstEnergy; IMEA; Industrial Coalitions; Industrial 

Consumers; Integrys Energy; ISO/RTO Council; LPPC; MADRI States; Midwest ISO; 

NYISO; Ohio PUC; OMS; OPSI; Pennsylvania PUC; PG&E; Public Interest 

Organizations; Reliant; Retail Energy; Steel Producers; Wal-Mart; and Xcel. 

178 EEI at 16. 

179 E.g., DRAM at 20; EnerNOC at 12. 
Docket Nos. RM07-19-000 and AD07-7-000 - 72 - 

EnerNOC note that allowing ARCs to enter wholesale energy markets has been 

successful in PJM, ISO New England, and NYISO.180 

133. Industrial Coalitions note that this proposal would expand the pool of potential 

demand response providers, thereby increasing demand elasticity. American Forest states 

that the proposal could encourage development of state-level retail programs that may not 

otherwise be considered. The potential for such participation may encourage the 

development of state law or retail structures to accommodate participation where none 

now exists as retail customers seek to avail themselves of the opportunities larger markets 

offer.181

134. Ameren states, however, that unless RTOs and ISOs develop and properly 

implement clear tariff provisions and market rules that explain how the aggregation of 

retail customers for demand response reductions will work, LSEs and providers of last 

resort could be harmed by ARCs’ demand bids. Ameren asserts that ARCs’ 

unanticipated demand reductions can expose LSEs and providers of last resort to the 

difference between day-ahead and real-time locational marginal prices, as well as to 

deviation charges due to this difference. Ameren urges the Commission to require RTOs 

and ISOs to adopt tariff provisions and market rules that protect LSEs and providers of 

last resort from such harm if an ARC reduces load. Similarly, NCPA urges the 

Commission to require coordination among the LSE, the ARC, and the RTO or ISO. 

 180 Comverge at 18; EnerNOC at 12-13. 

181 American Forest at 5-6. 
Docket Nos. RM07-19-000 and AD07-7-000 - 73 - 

NCPA asserts that such coordination is necessary to preserve the value of the demand 

response and to prevent imprudent resource planning or operating decisions.182

135. BP Energy is concerned that ARCs’ participation in wholesale markets during 

non-emergency periods can lead to gaming. Therefore, it recommends that the 

Commission consider restricting or eliminating during any non-emergency period any 

incentive, subsidy or capacity-type payment for RTO and ISO demand response 

programs related to energy markets.183 Similarly, LPPC states that each RTO or ISO 

should adopt mechanisms to prevent gaming of the program.184 

136. TAPS believes that the Commission’s proposal regarding ARCs may require 

existing LSE demand response programs to change to accommodate the ARC demand 

response programs, which would increase rather than decrease barriers to effective 

demand response programs. It requests clarification that the Commission’s proposal 

would not require any change to an existing aggregation program that already functions 

well. 

137. Several regional entities maintain that they are already working to allow ARC 

participation in their markets. CAISO states that it is working with its stakeholders and 

California PUC to address regulatory policy and state law concerning aggregation. ISO 

New England states that its current market rules allow ARCs to aggregate retail 

 182 NCPA at 3-4. 

183 BP Energy at 16. 

184 LPPC at 8. 
Docket Nos. RM07-19-000 and AD07-7-000 - 74 - 

customers for the purpose of participating in demand response programs and the forward 

capacity market. Midwest ISO notes that, in accordance with the Commission’s ASM 

Order,185 it will continue to work with stakeholders to develop tariff provisions to allow 

ARCs to operate within its footprint. Finally, NYISO states that it is making efforts to 

identify common issues and best practices related to demand resource bidding 

programs.186

138. SPP states that there are no states within its footprint that currently provide retail 

access. However, to the extent there would be an ARC within its footprint, it notes that it 

would be up to the relevant retail regulatory authority to determine whether retail load 

would be permitted to participate in the wholesale market demand response program.187 

ii. Comments on regulatory approval of ARCs

139. Most regulatory authorities, including NARUC, as well as other commenters, such 

as NRECA, APPA, and TAPS, ask the Commission to modify its proposal to clarify that 

an ARC or any retail customer may not bid load-reduction response into an RTO or ISO 

market without the relevant retail regulatory authority’s express permission.188 They 

assert that the Commission’s proposal would allow ARCs to bid retail demand response 

 185 See infra note 60. 

186 NYISO at 10. 

187 SPP at 5-6. 

188 E.g., APPA at 43; California PUC at 17; IMEA at 2; Kansas CC at 2; Maine 

PUC at 4; NARUC at 8; NCPA at 3; North Carolina Electric Membership at 5; NRECA 

at 12; Ohio PUC at 8; Pennsylvania PUC at 12; NIPSCO at 13; PG&E at 9; and Old 

Dominion at 13. 
Docket Nos. RM07-19-000 and AD07-7-000 - 75 - 

into organized energy markets without express permission from the relevant retail 

regulatory authority and thereby place a burden on the local authority to take affirmative 

action to disallow such participation. Some assert that such a burden displaces state 

authority and would impose an undue burden on municipalities, resulting in unintended 

consequences.189 They state that an ARC’s participation should be subject to the rules 

and laws of the relevant retail regulatory authority and argue that an ARC or any retail 

customer should not bid load-reduction response into an RTO or ISO market without the 

relevant retail regulatory authority’s express permission. They contend that the burden 

should be on the ARC or the regional entity to obtain state regulators’ permission for the 

demand response program, and not on the retail electric regulatory authority to prohibit it. 

140. The Final Rule, they contend, should specify that an RTO or ISO can accept ARC 

bids only if the relevant electric retail regulatory authority affirmatively informs the RTO 

or ISO that it permits ARC activities for its retail load; without such explicit notification, 

the RTO should presume that an ARC could not lawfully aggregate the retail load. For 

instance NARUC states that the last criterion proposed by the Commission should be 

revised to state that: 

The market rules shall not allow bids from an ARC unless

this is expressly permitted under the laws or regulations of the 

 189 E.g., NRECA at 10-14; NARUC at 7; TAPS at 13; and IMEA at 2. APPA 

notes that only a small fraction of the 1,315 public systems providing retail electric 

services in states served by RTOs and ISOs have laws or rules that address end-use 

aggregation. Therefore, it argues that requiring relevant electric retail regulatory 

authority to take affirmative actions to consider retail aggregation by ARCs can be a 

substantive undertaking. APPA at 44. 
Docket Nos. RM07-19-000 and AD07-7-000 - 76 - 

relevant electric retail regulatory authority. The RTO or ISO 

must receive explicit notification from the relevant retail 

regulatory authority in order to qualify a bid from an ARC 

that includes the demand response of that authority’s retail 

customers.[190] 

141. NRECA argues that if the Commission does not require explicit permission from 

the relevant authority, ARCs would effectively be allowed to cherry-pick the best load 

response resources out of existing LSE demand response programs. NRECA contends 

that this would deprive those LSEs of important resources used to keep rates down for all 

consumers.191 APPA, like NRECA, asks that the Commission require RTOs and ISOs to 

assume that in the case of public power systems, aggregation is not permitted unless the 

state’s retail regulatory authority has notified the RTO or ISO otherwise. However, if the 

Commission maintains the NOPR proposal over APPA’s objections, APPA suggests an 

alternative approach to this issue, making it clear that this is not its preferred approach. It 

suggests that the Commission implement its proposal for power systems with 4 million 

MWh or more in total annual output, but exempt systems of smaller size.192 That is, for 

power systems above 4 million MWh of total annual output the presumption would be as 

proposed by the Commission: that an ARC or individual retail consumer may bid 

demand response into an organized wholesale power market unless the relevant electric 

 190 NARUC at 9. PG&E and NRECA offer similar revisions. PG&E at 10; 

NRECA at 11. 

191 NRECA at 14. 

192 APPA at 47. APPA states that the United States Small Business 

Administration defines an entity whose total annual output is under 4 million MWh as a 

small utility. APPA at 45 & n.21. 
Docket Nos. RM07-19-000 and AD07-7-000 - 77 - 

retail regulatory authority notifies the RTO or ISO that this is not permitted. For smaller 

systems, the presumption would be that retail load may not be bid into the organized 

market, unless the relevant electric retail regulatory authority expressly indicates that 

participation by retail customers is permitted. APPA states that this option would 

preserve the Commission’s intention to remove barriers to the participation of demand 

response resources in organized wholesale electricity markets while not imposing an 

undue burden on small systems that may not be prepared to address this issue. 

142. E.ON U.S. opposes the proposal on the grounds that it violates the separation of 

federal and state jurisdiction and places at risk a utility’s obligation to serve its retail 

load.193 It notes that state regulatory commission approval is required before retail 

customers may band together to offer a bid into the wholesale market and such an 

approval will be difficult if the program benefits large customers to the detriment of 

many small customers. Also, while Mr. Borlick does not oppose the proposal, he states 

that ARCs are not the best means for promoting demand response resources.194

143. PG&E asserts that explicit approval of the regulatory authority is needed to assure 

that opportunities for unreasonable and unfair allocations of cost are eliminated and that 

critical enabling elements have been established. According to PG&E, this includes: (1) 

assuring that a customer properly informs a load-serving entity of its demand response 

participation; (2) assurance that costs are not inappropriately transferred from one group 

 193 E.ON U.S. at 11. 

194 Mr. Borlick at 3. 
Docket Nos. RM07-19-000 and AD07-7-000 - 78 - 

of customers to another through demand response aggregation; (3) that appropriate RTO 

or ISO metering protocols exist to eliminate double counting concerns; and (4) resource 

adequacy value is fairly allocated.195

144. Wal-Mart, however, states that the Commission has the authority to promote 

aggregation of retail load reduction bids, including bids from individual retail customers, 

and should not require RTOs or ISOs to reject bids unless permitted by the relevant retail 

regulatory authority.196 Similarly, some commenters assert that the Commission should 

exercise its jurisdiction over demand response programs to direct RTOs and ISOs to 

allow any retail customer either on its own or through an aggregator to participate in 

RTO or ISO demand response programs as long as the customer can meet the operational 

requirements of the RTO or ISO tariff, without consulting with a state commission.197 

They contend that such unrestricted access to demand response programs is the best way 

to maximize program participation and thereby bring benefits to organized markets. In 

the alternative, however, they state that they support the NOPR proposal.198

145. Xcel supports the proposed rule on aggregation by ARCs, but asks the 

Commission to clarify how the RTO or ISO would receive explicit notification from the 

relevant regulatory authority to disqualify an offer from an ARC. Xcel suggests that the 

 195 PG&E at 9. 

196 Wal-Mart at 6-7. 

197 Integrys Energy at 4-5; Retail Energy at 2. 

198 Integrys Energy at 5; Retail Energy at 2 
Docket Nos. RM07-19-000 and AD07-7-000 - 79 - 

Commission follow the procedure used for compliance with NERC mandatory electric 

reliability standards and require each ARC to register with the RTO or ISO, which could 

then require the ARC to certify that it has received the appropriate regulatory approval.199

iii. Comments on proposed criteria and regional 

flexibility

146. Many commenters state that they support the Commission’s proposed criteria and 

regional flexibility for RTOs and ISOs listed in the NOPR for allowing an ARC to bid 

retail load-response into an RTO or ISO market.200 For example, LPPC believes that the 

proposed criteria are useful in evaluating RTO and ISO implementation of the proposal. 

It also suggests two additional criteria: (1) the RTO or ISO must demonstrate that its 

procedure for administering ARC bids effectively coordinates activities of the ARCs and 

LSEs; and (2) the Commission should ensure that there is a demonstration of net benefits 

to consumers and that a system is in place for verifying that demonstrated load reduction 

is achieved.201 

147. Reliant agrees with the Commission’s proposed criteria, but it believes that the 

most effective approach for demand response development is through the direct 

relationship between the retail customer and its LSE.202 

 199 Xcel at 9-10. 

200 E.g., Exelon at 9; Industrial Consumers at 16; LPPC at 8; MADRI States at 5; 

NYISO at 9; Reliant at 6; and Wal-Mart at 7. 

201 LPPC at 8. 

202 Reliant at 6. 
Docket Nos. RM07-19-000 and AD07-7-000 - 80 - 

148. Many commenters support the NOPR proposal to allow each market to develop its 

own rules to implement retail aggregation by ARCs.203 For example, Dominion 

Resources agrees with the Commission that it is important for RTOs and ISOs to have 

flexibility in developing ARC provisions to account for regional differences.204 EEI 

stresses that RTOs and ISOs should have flexibility to adopt pricing methods and other 

provisions that reflect regional differences.205 NEPOOL Participants states that the 

current arrangements in ISO New England already allow ARCs to participate in its 

markets, and any changes to the existing program to accommodate Commission 

directives should be handled through the stakeholder process. SoCal Edison-SDG&E 

believe that CAISO should have the flexibility to pursue development of demand 

response programs without being constrained by overly broad nationwide restrictions and 

requirements. California Munis urges the Commission to consider regional and 

jurisdictional distinctions that may affect ARCs’ effectiveness, noting that some states 

and local jurisdictions within RTO or ISO may not have adopted a retail choice model. 

149. Public Interest Organizations, however, recommend that the Commission adopt a 

more detailed generic (pro forma) set of market rules on ARCs, which RTOs and ISOs 

may modify based on regional differences if the modifications are comparable or superior 

 203 E.g., APPA; California Munis; Dominion Resources; EEI; Exelon; ISO/RTO 

Council; Old Dominion; NEPOOL Participants; and SoCal Edison-SDG&E. 

204 Dominion Resources at 5. 

205 EEI at 17. 
Docket Nos. RM07-19-000 and AD07-7-000 - 81 - 

to the Commission’s rules. According to Public Interest Organizations, these pro forma

rules could be developed through a technical conference. 

iv. Comments on specific ARC requirements and 

clarifications

150. Many commenters assert that it is important that ARCs be required to comply with 

necessary technical requirements.206 For instance, several commenters state that certain 

technical matters should be standardized, including (1) the method for determining 

baseline compensation, (2) tools to establish uniform baselines and verification, (3) 

interface tools for demand response to use a common portal and protocol in organized 

markets, and (4) telemetry and metering requirements.207 DC Energy states that ARCs 

should provide verification of measurement equal to others in the same market and notes 

that all participants should have similar requirements for the ability to bid into wholesale 

markets. DRAM and Converge state that double payment should be avoided and 

FirstEnergy asserts that each RTO or ISO should adopt appropriate restrictions to avoid 

double counting. 

151. EnergyConnect notes that past efforts to aggregate small retail loads have not been 

successful primarily due to the requirement that every small resource in an aggregated 

group meet the same registration, measurement and verification standards as large 

 206 E.g., NYISO at 5; LPPC at 7; Comverge at 18; EEI at 2; and Industrial 

Consumers at 14. 

207 E.g., DRAM at 21; Comverge at 18; and NEPOOL Participants at 9. 
Docket Nos. RM07-19-000 and AD07-7-000 - 82 - 

generators or other resources. EnergyConnect recommends the use of sampling or other 

techniques to address this issue. 

152. Several commenters seek clarification of various aspects of the proposal. For 

instance, EEI stresses that the Final Rule should clarify that RTOs and ISOs may specify 

certain requirements of ARCs, such as registration and creditworthiness requirements, 

and that RTOs and ISOs should have the flexibility to adopt pricing methods and other 

provisions that reflect regional differences.208 Industrial Coalitions also ask the 

Commission to clarify that ARCs, like LSEs and industrial customers, should be held 

accountable for responding when called upon by their respective RTO or ISO. LPPC 

requests that the Commission clarify that its rules would not permit ARC bids to be 

submitted on behalf of load served by LSEs that are not RTO or ISO members. 

Similarly, SMUD requests clarification that the Commission did not intend that loads 

located outside the control area of an RTO or ISO would participate in demand response 

programs, whether through a retail aggregator or directly with the RTO or ISO. 

153. NYISO states that the Commission should not accept proposals that would provide 

preferential treatment to ARCs or that would not be comparable to the rules for other 

demand resources or generators.209 NYISO suggests that the Commission amend its 

proposed regulatory text in section 35.28(g)(iii) to clarify that ARCs must meet 

“applicable reliability requirements” before they can bid into regional markets, and 

 208 EEI at 17. 

209 NYISO at 9-10. 
Docket Nos. RM07-19-000 and AD07-7-000 - 83 - 

clarify that the reference to “organized market” has the same meaning as proposed under 

subsection (g)(i).210 Similarly, it states that the Commission should conform subsection 

(g)(iii) to (g)(i) so that (g)(iii) will specifically require ARCs to comply with “necessary 

technical requirements under the RTO or ISO tariff.” NYISO notes that such a change 

will ensure that RTOs and ISOs may adopt reasonable metering, verification, 

communications, minimum size, and other technical rules for both individual demand 

resources and ARCs.211

c. Commission Determination

154. The Commission adopts in this Final Rule the proposed rule 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. We find 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. 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. We also agree 

with commenters that this proposal could encourage development of demand response 

 210 Section 35.28 (g)(i) establishes that “organized markets” includes any RTO or 

ISO-administered market based on competitive bidding. 

211 NYISO at 10. 
Docket Nos. RM07-19-000 and AD07-7-000 - 84 - 

programs and thereby provide retail customers more opportunities available through 

larger markets. Additionally, as some commenters note, experiences with existing 

aggregation programs in PJM, NYISO, and ISO New England have shown that these 

programs have increased demand responsiveness in these regions. 

155. We are mindful of the comments that allowing ARCs to bid into the wholesale 

energy market without the relevant electric retail regulatory authority’s express 

permission may have unintended consequences, such as placing an undue burden on the 

relevant electric retail regulatory authority. In the NOPR, the Commission sought to 

address the concerns of state and local retail regulatory entities by proposing to require 

that an ARC may bid retail load reduction into an RTO or ISO regional market unless the 

laws or regulations of the relevant electric retail regulatory authority do not permit a retail 

customer to participate in this activity. The Commission’s intent was not to interfere 

with the operation of successful demand response programs, place an undue burden on 

state and local retail regulatory entities, or to raise new concerns regarding federal and 

state jurisdiction, as some commenters argue. As described above, we clarify that we 

will not require a retail electric regulatory authority to make any showing or take any 

action in compliance with this rule. Rather, this rule requires an RTO or ISO to accept a 

bid from an ARC, unless the laws or regulations of the relevant electric retail regulatory 

authority do not permit the customers aggregated in the bid to participate. 

156. In response to E.ON U.S., we do not agree that the approach we adopt here 

violates the separation of federal and state jurisdiction. Rather, we find that this action 

properly balances the Commission’s goal of removing barriers to development of demand 
Docket Nos. RM07-19-000 and AD07-7-000 - 85 - 

response resources in the organized markets that we regulate with the interests and 

concerns of state and local regulatory authorities. 

157. With regard to LPPC’s request that ARCs not bid on behalf of load served by 

LSEs that are not RTO or ISO members, SMUD’s request for clarification that loads 

outside of an RTO’s or ISO’s control area would not participate in demand response 

programs, and TAPS’s comment that the proposal should not require a change to an 

existing retail load reduction program, the continuing role of the relevant retail electric 

regulatory authority adequately addresses these concerns. 

158. Further, we agree with the comments that, because each region’s market design is 

different, it is important to permit each RTO or ISO to design ARC provisions that 

account for these differences. Therefore, instead of developing pro forma language or 

requiring RTOs and ISOs to make detailed generic market rule amendments, we direct 

RTOs and ISOs to amend their tariffs and market rules as necessary to allow an ARC to 

bid demand response directly into the RTO’s or ISO’s organized market in accordance 

with the following criteria and flexibilities that remain largely unchanged from those 

advanced in the NOPR: 

a. The ARC’s demand response bid must meet the same requirements as a 

demand response bid from any other entity, such as an LSE. For example: 

i. Its aggregate demand response must be as verifiable as that of an 

eligible LSE or large industrial customer’s demand response that is 

bid directly into the market; 
Docket Nos. RM07-19-000 and AD07-7-000 - 86 - 

ii. The requirements for measurement and verification of aggregated 

demand response should be comparable to the requirements for other 

providers of demand response resources, regarding such matters as 

transparency, ability to be documented, and ensuring compliance; 

iii. Demand response bids from an ARC must not be treated differently 

than the demand response bids of an LSE or large industrial 

customer. 

b. The bidder has only an opportunity to bid demand response in the 

organized market and does not have a guarantee that its bid will be selected. 

c. The term “relevant electric retail regulatory authority” means the entity that 

establishes the retail electric prices and any retail competition policies for 

customers, such as the city council for a municipal utility, the governing 

board of a cooperative utility, or the state public utility commission. 

d. An ARC can bid demand response either on behalf of only one retail 

customer or multiple retail customers. 

e. Except for circumstances where the laws and regulations of the relevant 

retail regulatory authority do not permit a retail customer to participate, 

there is no prohibition on who may be an ARC. 

f. An individual customer may serve as an ARC on behalf of itself and others. 

g. The RTO or ISO may specify certain requirements, such as registration 

with the RTO or ISO, creditworthiness requirements, and certification that 
Docket Nos. RM07-19-000 and AD07-7-000 - 87 - 

participation is not precluded by the relevant electric retail regulatory 

authority.212 

h. The RTO or ISO may require the ARC to be an RTO or ISO member if its 

membership is a requirement for other bidders. 

i. Single aggregated bids consisting of individual demand response from a 

single area, reasonably defined, may be required by RTOs and ISOs. 

j. An RTO or ISO may place appropriate restrictions on any customer’s 

participation in an ARC-aggregated demand response bid to avoid counting 

the same demand response resource more than once. 

k. The market rules shall allow bids from an ARC unless this is not permitted 

under the laws or regulations of relevant electric retail regulatory authority. 

159. The above criteria in combination with regional flexibility will provide the 

foundation for each RTO and ISO to work with its stakeholders, including state and local 

regulatory entities, to develop market rules that will enable more small entities to provide 

demand response to the regional markets. Such a process would provide the forum 

necessary to discuss and resolve concerns raised by the commenters in this proceeding, 

including: (1) developing standardized terms and conditions, (2) the requirement that 

ARC’s demand response bid must meet the same requirements as other demand response 

 212 The RTO or ISO should not be in the position of interpreting the laws or 

regulations of a relevant electric retail regulatory authority. 
Docket Nos. RM07-19-000 and AD07-7-000 - 88 - 

bids,213 (3) verification and measurement, (4) penalties for non-compliance, (5) 

registration and creditworthiness requirements, and (6) mechanisms to prevent gaming. 

Further, in response to those who ask us to require in this rule (1) that each RTO or ISO 

should be required to demonstrate net benefits of its program, (2) that bids should be 

aggregated on a local basis, and (3) that so called “double payment” should be either 

required or prohibited, we decline to do so here. Such issues are more appropriately 

addressed by each region in its compliance filing if it chooses to do so. 

160. Given this regional approach, we do not find that standardized technical issues or a 

pro forma set of market rules, as raised by some commenters, is necessary at this time. 

The comments do not persuade us to add additional criteria to the criteria adopted herein. 

As noted above, we encourage RTOs and ISOs to coordinate their efforts with customers, 

state and local regulatory entities, and other stakeholders. The Commission will consider 

such regional proposals in the compliance filings. Further, we agree with commenters on 

the need for coordination of the activities of the ARCs and LSEs to ensure efficient 

operation of the markets. 

161. In accordance with NYISO’s recommendation, the Commission will clarify that 

its regulatory reference in § 35.28 (g)(ii) to “organized market” has the same meaning as 

proposed under (g)(i) and that ARCs are to comply with any necessary technical 

requirements under the RTOs or ISO’s tariff. 

 213 We note that “same requirement” does not necessarily mean identical to other 

demand response bids. An ARC’s demand response bid must meet similar or comparable 

requirements as other demand response bids. 
Docket Nos. RM07-19-000 and AD07-7-000 - 89 - 

162. Regarding NYISO’s recommendation that the Commission clarify that ARCs must 

meet “applicable reliability requirements,” the Commission does not see a need to change 

its proposed language in this rulemaking because reliability issues are addressed by each 

RTO or ISO in accordance with Commission established reliability requirements. 

163. Each RTO and ISO is required to submit, within six months of the date that this 

Final Rule is published in the Federal Register, a compliance filing with the Commission, 

proposing amendments to its tariffs or otherwise demonstrating how its existing tariff and 

market design is in compliance with the requirements of this Final Rule. 

164. We appreciate comments of CAISO, ISO New England, Midwest ISO, and 

NYISO that they are already working with stakeholders to allow ARCs to operate within 

their footprint or to address compliance issues. With regard to SPP’s comment that there 

is no retail access state within SPP, the Commission notes that its ARC requirements are 

not limited to aggregation of retail customers who have retail choice. We will not 

prejudge here whether any nascent ARC program will satisfy our requirements. Nor will 

we decide whether a regulator of a traditional, vertically-integrated monopoly utility may 

give permission for an ARC to aggregate retail customers’ demand responses for bidding 

into SPP’s markets. SPP may explain in its compliance filing its situation regarding retail 

choice but should also explain how it would accommodate a bid from an ARC consistent 

with the criteria listed above. 
Docket Nos. RM07-19-000 and AD07-7-000 - 90 - 

5. Market Rules Governing Price Formation During Periods of 

Operating Reserve Shortage

165. In the NOPR, the Commission observed that existing RTO and ISO market rules 

continue to appear to be unjust, unreasonable, and unduly discriminatory or preferential 

during periods of operating reserve shortages. In particular, the Commission noted that 

these rules may not produce prices that accurately reflect the true value of energy in such 

an emergency and, by failing to do so, may harm reliability, inhibit demand response, 

deter new entry of demand response and generation resources, and thwart innovation.214 

166. Therefore, the Commission proposed to reform market rules governing price 

formation in RTO and ISO energy markets during operating reserve shortages. 

Specifically, the Commission proposed to require each RTO or ISO with an organized 

energy market to make a compliance filing, within six months of the date that the Final 

Rule is published in the Federal Register, proposing any necessary reforms to ensure that 

the market price for energy accurately reflects the value of such energy during shortage 

periods (i.e., an operating reserve shortage). The Commission stated that each RTO or 

ISO may propose one of four suggested approaches to pricing reform during an operating 

reserve shortage or to develop its own alternative approach to achieve the same 

objectives. These approaches are discussed in section (b) of this chapter. Alternatively, 

an RTO or ISO may demonstrate that its existing market rules already reflect the value of 

energy during periods of shortage and, therefore, do not need to be reformed. The 

 214 NOPR, FERC Stats. & Regs. ¶ 62,628 at P 107. 
Docket Nos. RM07-19-000 and AD07-7-000 - 91 - 

Commission proposed to require RTOs and ISOs proposing reforms or demonstrating the 

adequacy of existing market rules to provide an adequate factual record for the 

Commission to evaluate their proposals; and proposed six criteria by which the 

Commission would evaluate the RTO’s or ISO’s compliance filing. The Commission 

asked for comments on these criteria. The Commission noted that any change in market 

rules to implement the proposed reforms must consider the issue of market power abuse, 

recognize regional differences in market rules, and be based on a sound factual record. 

167. Further, the Commission stated that it would require any RTO or ISO proposing 

reform in this area to address the adequacy of any market power mitigation measures that 

would be in place during periods of operating reserve shortage. In addition, to ensure an 

adequate record on the issue of market power mitigation, the Commission proposed to 

solicit the views of the Independent Market Monitor for each RTO or ISO region on any 

proposed reforms in this area. 

168. Section (a) of this Chapter presents a discussion of the Commission’s proposed 

rule to reform pricing for RTOs and ISOs to more accurately reflect the value of energy 

during periods of operating reserve shortage. Section (b) addresses comments on the four 

approaches provided by the Commission that RTOs and ISO must consider in addressing 

this issue. Section (c) addresses the six criteria that the Commission proposed to ensure 

that any reforms implemented by an RTO or ISO achieve the desired results; and section 

(d) addresses the option for each RTO or ISO to phase-in its reform proposal over a 

number of years.
Docket Nos. RM07-19-000 and AD07-7-000 - 92 - 

a. Price Formation During Periods of Operating Reserve 

Shortage

i. Comments

169. A number of commenters state that they support the proposed rule on price 

formation during periods of operating reserve shortage.215 Some of these commenters 

assert that prices must be allowed to reflect the true value of energy during an operating 

reserve shortage in order for wholesale energy markets to operate efficiently.216 Other 

commenters state that a transparent price signal can: (1) enhance system reliability and 

protect customers;217 (2) encourage a vibrant demand response market because both 

demand response and other sources of energy supply will participate in the market to a 

greater degree;218 and (3) encourage those with advanced metering technology to follow 

energy prices more closely, and those without such technology to acquire it.219 

 215 E.g., Mr. Borlick; BP Energy; CAISO; California PUC; Comverge; 

Constellation; DC Energy; Dominion Resources; DRAM; Duke Energy; EEI; EPSA; 

Exelon; FirstEnergy; Integrys Energy; Ohio PUC; OMS; Potomac Economics; PJM 

Power Providers; PPL Parties; and Reliant. 

216 E.g., BP Energy at 22; Mr. Borlick at 5; Comverge at 20, 22; Dominion 

Resources at 7; Exelon at 11; OMS at 6; PPL Parties at 5; and PJM Power Providers at 3. 

217 Comverge at 20, 23; PPL Parties at 5. PPL Parties notes that “customers will 

be protected because the price signal will encourage more robust bilateral contracting, 

self-supplied generation, the improved use of hedging and financial instruments, and 

increased amounts of demand responsive load.” PPL Parties at 6. 

218 PPL Parties at 5. 

219 OMS at 6. 
Docket Nos. RM07-19-000 and AD07-7-000 - 93 - 

170. EEI maintains that RTOs and ISOs should modify their market rules to allow the 

market-clearing price to accurately reflect the value of energy during periods of operating 

reserve shortages. It also agrees that any change in market rules must consider the issue 

of market power, recognize regional differences in market rules, and be based on a sound 

factual record.220 

171. PJM Power Providers asserts that accurate price signals are the cornerstone of a 

successful wholesale market design. It notes that many of the problems in wholesale 

electric markets stem from market design features that suppress prices during shortage 

conditions to levels below the value of lost load.221 It adds that shortage pricing can 

provide short-term signals to generation to ensure production and long-term signals to 

allow for fixed cost recovery supporting maintenance of existing facilities and new entry. 

Therefore, PJM Power Providers asserts that a shortage pricing mechanism must be 

integrated with the overall market design. 

172. Reliant states that for all RTOs and ISOs—with or without capacity markets, 

prices in real-time should properly signal needed responses from both supply-side and 

demand-side resources. To the extent that price caps or bid mitigation suppress the 

appropriate price signals in the energy market, reforms should be made. These price 

signals are needed to encourage the necessary short-term response to the market and also 

 220 EEI at 19. 

221 PJM Power Providers at 3. See also PPL Parties at 5 (“implementing 

appropriate [shortage] pricing will require permitting energy prices to rise when 

warranted to reflect the average value of lost load”). 
Docket Nos. RM07-19-000 and AD07-7-000 - 94 - 

to provide critical pricing information to the market.222 Reliant argues that the current 

market design in several RTOs and ISOs does not support the investment needed to 

maintain system reliability.223 It asserts that transparent price signals in the market will 

encourage the most efficient and effective implementation of new generation and 

demand-side technology and investment. Therefore, to the extent that RTO and ISO 

market design fails to provide such transparent price signals, Reliant asserts that the 

Commission should direct necessary pricing reforms.224 

173. Several commenters note that they support the proposed shortage pricing proposal 

and also note that generation and demand resources should be treated comparably during 

shortage pricing.225 For instance, OMS states that both generation and demand resources 

are equally valuable so they should be treated comparably. In that respect, it notes that, 

similar to generators, demand resources, if offered and accepted into the market during 

shortage periods, should be assessed penalties if the RTO calls on them and they do not 

comply.226

 222 Reliant at 8. 

223 For example, in Midwest ISO and CAISO, Reliant notes that market revenues 

were not sufficient to support new generation investment. Id. at 9. 

224 Id. 9-10. 

225 PPL Parties at 5; First Energy at 11; and OMS at 6. 

226 OMS at 6. 
Docket Nos. RM07-19-000 and AD07-7-000 - 95 - 

174. Several commenters support the Commission’s proposal to recognize regional 

differences by adopting a flexible regional approach, rather than a general mandate.227 

These commenters state that given the market design and rule variations among 

organized markets, a one-size-fits-all approach may not be appropriate. They believe that 

it is reasonable for the Commission to establish fundamental principles and necessary 

elements for promoting demand responsiveness, while leaving the specifics of 

implementation to each RTO or ISO market. Therefore, they support the Commission’s 

proposal to allow each region to choose its own shortage pricing approach from the four 

offered or to choose another developed through the stakeholder process. 

175. EEI also strongly supports the Commission’s regional approach; stating that, given 

the regional differences in market design, each region should have the flexibility to 

propose its own approach or demonstrate that its existing market rules satisfy this 

requirement.228 Similarly, California PUC states that implementation of this rule should 

be done through collaborative efforts between the state commission and its respective 

RTO or ISO (e.g., how the shortage price is set, at what level it is set, and under what 

circumstances the shortage price is triggered).229 

 227 E.g., CAISO; EEI; EPSA; ISO/RTO Council; Midwest ISO; PJM Power 

Providers; Old Dominion; Wal-Mart; ISO New England; NYISO; NY TOs; Detroit 

Edison; Dominion Resources; and SPP. 

228 EEI at 19. 

229 California PUC at 19. CAISO also states that it supports the Commission’s 

proposal to require RTOs and ISOs to study shortage pricing market reforms and report 

back to the Commission. 
Docket Nos. RM07-19-000 and AD07-7-000 - 96 - 

176. Several regional entities assert that they are in compliance or will be in 

compliance with the proposed rule. For instance, CAISO states that it will be in 

compliance with the proposed plans to incorporate a demand curve for reserves within 12 

months of the roll-out of MRTU, as directed by the Commission.230 Midwest ISO states 

that it is in compliance with the proposed rule because its recently-approved ancillary 

services market incorporates a demand curve for operating reserves.231 NYISO maintains 

that it intends to demonstrate in its compliance filing that its rules fully satisfy the 

NOPR’s requirements.232 ISO New England also states that it has a demand curve for 

operating reserves and thus is in compliance with the proposal.233 

177. Many commenters object to the Commission’s proposed rule on pricing reform 

during periods of operating reserve shortages, and they proffer various reasons.234 Some 

of these commenters oppose the proposed rule on grounds that it will result in exercise of 

market power because the organized markets are not competitive,235 leading to unjust and 

 230 CAISO at 3. 

231 Midwest ISO at 16. 

232 NYISO at 4. 

233 ISO New England at 12; see also NEPOOL Participants at 16; NSTAR at 3; 

and Maine PUC at 4-5. 

234 E.g., Alcoa; APPA; California Munis; Industrial Coalitions; Industrial 

Consumers; LPPC; North Carolina Electric Membership; NRECA; OLD Dominion; 

TAPS; Steel Manufacturers; SMUD; Public Interest Organizations; New Jersey BPU; and 

National Grid. 

235 E.g., Alcoa; APPA; NRECA; TAPS; North Carolina Electric Membership; 

Pennsylvania PUC; LPPC; and Steel Manufacturers. 
Docket Nos. RM07-19-000 and AD07-7-000 - 97 - 

unreasonable rates. APPA argues that the prices produced by RTO or ISO markets do 

not reflect the actual economic costs of providing service because the rates are not the 

product of competitive markets.236 According to APPA, the only restraint on generation 

suppliers’ ability to extract the maximum amount of profits from regional markets is the 

RTO’s and ISO’s market mitigation rules. It states that exposing retail consumers 

directly to unmitigated price signals would result in unjust and unreasonable rates. 

Therefore, APPA urges the Commission to first address market deficiencies, including 

market competitiveness and proper demand response infrastructure, in order to enable 

consumers to respond to higher prices.237 NRECA argues that the Commission would 

violate its duty under FPA if it were to subject customers to unjust and unreasonable 

rates, even if those excessive rates were limited to emergency situations.238

178. LPPC is opposed to proposals that would permit generation prices to rise above 

rate cap levels during scarcity situations.239 According to LPPC, the proposed rule would 

undermine the Commission’s core mission to ensure just and reasonable rates and would 

result in an unjust and unreasonable transfer of wealth from customers to generators. It 

notes that the Commission has long approved the use of price caps in RTO and ISO 

markets in order to mitigate market power and to protect customers from unreasonable 

 236 APPA at 53. 

237 Id. at 30-31. The California Munis adopt the comments of APPA on these 

issues and incorporate them by reference into their comments. California Munis at 17. 

238 NRECA at 16. 

239 LPPC at 3. 
Docket Nos. RM07-19-000 and AD07-7-000 - 98 - 

prices during periods of capacity deficiency or emergency.240 It asserts that removing 

these price caps would be inconsistent with Commission precedent that market-based 

rates may be relied on only where the Commission has determined that the market is 

sufficiently competitive.241 It further argues that the Commission is abdicating market 

mitigation by abandoning price caps when it has previously determined that price caps 

are needed to restrain prices in times of scarcity.242 Therefore, instead of removing bid 

caps, LPPC believes that the Commission should promote demand response through 

payments for demand reduction. 

179. Several commenters dispute the Commission’s premise that customers will be able 

to respond to higher prices.243 For instance, Steel Manufacturers asserts that the vast 

majority of end users do not see hourly price signals because they are retail customers 

regulated by state commissions.244 According to Steel Manufacturers, only a small 

percentage of loads, typically large manufacturing loads, who take electric service 

through advanced meters will be able to respond to price signals during periods of 

 240 Id. at 9-10. 

241 Id. at 12 (citing California ex re. Lockyer v. FERC, 383 F.3d 1006 (9th Cir. 

2004, cert denied, Coral Power, L.L.C. v. Cal. ex rel. Brown, 127 S. Ct. 2972, 168 L. Ed. 

2d 719 (2007); Interstate Natural Gas Ass’n v. FERC, 285 F.3d 18, 30-31 (D.C. Cir. 

2002); Elizabethtown Gas Co. v. FERC, 10 F.3d 866 (D.C. Cir. 1993); Louisiana Energy 

& Power Auth. v. FERC, 10 F.3d 866 (D.C. Cir. 1998)). 

242 LPPC 12-13. 

243 E.g., North Carolina Electric Membership; New Jersey BPU; Old Dominion; 

Steel Manufacturers; and Pennsylvania PUC. 

244 Steel Manufacturers at 12-13. 
Docket Nos. RM07-19-000 and AD07-7-000 - 99 - 

scarcity. Therefore, they argue that there is no rational justification for imposing all 

market risks only on such a small pool of retail loads.245 Further, New Jersey BPU states 

that demand-side resources that pay a fixed seasonal or annual retail price for electricity 

will have no reason to respond to any dramatic increase in hourly prices.246

180. Similarly, TAPS argues that the proposed rule is not supported by sufficient 

evidence that lifting such bid caps will attract demand response sufficient to protect 

consumers from market power.247 It asserts that when the Commission is relying on 

demand response to provide the competitive response necessary to keep rates just and 

reasonable, there must be sufficient empirical proof that actual prices will be just and 

reasonable.248 TAPS contends that the Commission has not provided such evidence, and 

is prepared to “unleash market forces without making factual findings that the demand 

response necessary to restrain prices is ready, willing and able to be called upon.”249 

TAPS also disputes the Commission’s statement that artificial bid caps inhibit price 

 245 Id.

246 New Jersey BPU notes that virtually all New Jersey residential customers and 

commercial and industrial customers below 100 kW pay fixed retail prices. Therefore, a 

major increase in wholesale electricity prices during peak hours cannot be expected to 

attract new demand resources from the large majority of New Jersey customers. New 

Jersey BPU at 3. 

247 TAPS at 24. 

248 Id. at 24-25. 

249 Id. at 26. TAPS asserts that the Commission must protect customers from 

excessive rates and charges, and if it acts without the requisite empirical proof, the 

Commission will fail to protect consumers. TAPS at 29 (citing, Atl. Ref. Co. v. Pub. 

Serv. Comm’n of N. Y., 360 U.S. 378, 388 (1959)). 
Docket Nos. RM07-19-000 and AD07-7-000 - 100 - 

signals needed to attract entry by both generation and demand response resources. It 

asserts that high spot market prices do not correlate with entry in RTO and ISO 

markets.250

181. Pennsylvania PUC states that demand response must be fully integrated into 

existing markets before price caps can be removed in RTOs and ISOs. It asserts that the 

Commission wrongly concludes that price caps are inhibiting an otherwise competitive 

market. It also argues that without infrastructure improvements that permit load to see 

shortages being priced, removing bid caps would promote the exercise of market 

power.251

182. Similarly, Industrial Coalitions argue that necessary technology and demand 

response capability must be in place before any changes to mitigation rules can be 

contemplated. They also state that there are barriers to demand response such as 

inadequate federal-state coordination, utilities’ ability to preclude and frustrate customer 

participation, and complex participation requirements. Industrial Coalitions ask that the 

Commission demonstrate how any change in shortage pricing rules will result in lower 

prices to consumers.252 SMUD also states that while the elimination of every barrier to 

demand response is not a prerequisite to easing bid caps for demand response, the 

problem is that there are still significant barriers to demand response participation that 

 250 TAPS at 26-27. 

251 Pennsylvania PUC at 14-15. 

252 Industrial Consumers at 19. 
Docket Nos. RM07-19-000 and AD07-7-000 - 101 - 

must be addressed first.253 SMUD reports that there were deficiencies in technology that 

led the Commission not to allow bid caps to be lifted previously, and these technologies 

are still insufficiently developed today. 

183. Old Dominion also opposes removing price caps and asserts that efforts to 

increase demand response should not come at the expense of a customer base that cannot 

respond to price signals.254 It states that the Commission should adopt a presumption that 

such pricing incentives are not necessary and require the RTOs and ISOs that believe 

otherwise to make a factual demonstration that they are. This would include 

demonstrating that non-price barriers to demand response have been removed and that 

current market power mitigation rules will suffice to deal with any gaming behavior. 

184. North Carolina Electric Membership states that there is no evidence that 

generators require higher scarcity payments if the region already has a capacity market.255 

National Grid states that the Commission’s proposal to shift revenue from capacity 

markets to energy markets should not be implemented because it conflicts with the 

market designs approved by the Commission and implemented in NYISO and ISO New 

England.256 New Jersey BPU does not share the Commission’s belief that such shortage 

 253 SMUD at 3 (citing NOPR, FERC Stats. & Regs. ¶ 32,628 at P 109). 

254 Old Dominion at 14. 

255 North Carolina Electric Membership at 9. 

256 National Grid at 23. 
Docket Nos. RM07-19-000 and AD07-7-000 - 102 - 

pricing reforms will automatically lead to lower prices in capacity markets.257 PG&E 

states that any proposed shortage pricing rules must be coordinated with other 

mechanisms that provide similar reliability benefits to electrical systems, including 

resource adequacy requirements and DR programs.258 This must include capacity pricing 

mechanisms. An explanation of such coordination should be a requirement of the filing 

that RTOs and ISOs make as part of their proposal. PG&E is particularly concerned 

about the CAISO’s implementation of reserve shortage pricing, along with its relaxation 

of price caps, before meaningful demand response products are available. 

185. Comverge and DRAM state that they support the Commission’s proposal to reflect 

the value of energy during times of scarcity. However, they note that they are concerned 

about how the proposal would impact existing capacity markets, particularly in the longer 

term.259 Comverge states that where capacity markets are, or will be, in place each of the 

four approaches may reduce capacity market prices because revenues from energy and 

ancillary services would be subtracted from capacity payments. This may discourage 

participation by some demand response resources in capacity markets.260 According to 

DRAM, demand response resources need the “stable revenue stream” from the capacity 

market, and any energy payment received during reliability events is of secondary 

 257 New Jersey BPU at 5. 

258 PG&E at 11. 

259 DRAM at 23. 

260 Comverge at 21-23. 
Docket Nos. RM07-19-000 and AD07-7-000 - 103 - 

importance.261 DRAM states that shortage pricing should not be pursued in a way that 

requires demand response providers to participate in the energy market because not all 

customers are suited to, or interested in, energy market participation. Instead, it notes 

that these customers may participate in a reliability-based demand response program that 

helps preserve reliability, allowing them to be paid to be a reliability resource. EnerNOC 

asks the Commission to fashion a policy on shortage pricing that encourages demand 

response resources to interact in both energy and capacity markets, or in either one, in a 

manner that is most appropriate for the demand response resource.262 

186. The FTC encourages the Commission to require that proposals from RTOs and 

ISOs to lift wholesale bid caps during periods of operating reserve shortages be 

accompanied by an analysis of how the proposed change in the wholesale bid caps will 

change the totality of regulatory restrictions on wholesale prices during these periods.263 

Industrial Consumers also state that capacity markets should be suspended prior to any 

shortage pricing changes to prevent the gaming of multiple markets. They add that 

shortage pricing without competition is “monopoly pricing in disguise” and assert that 

conditions of true competition must be demonstrated before shortage price is used.264

 261 DRAM at 24. 

262 EnerNOC at 14. 

263 FTC at 29. 

264 Industrial Consumers at 19. 
Docket Nos. RM07-19-000 and AD07-7-000 - 104 - 

187. PJM Power Providers agrees with the Commission that 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.265 They also agree that 

many of the problems in wholesale electric markets stem from mitigation policies and 

market design features that suppress prices during shortage conditions below the value of 

lost load (VOLL). PJM Power Providers notes that in addressing these issues, a balance 

must be struck to encourage supplies to enter the market while minimizing market power 

concerns. 

188. In this regard, PJM Power Providers notes that scarcity pricing mechanisms need 

to be integrated into the overall market design in order to be effective, so that prices 

reflect actual system operation.266 It states that in the PJM market, pricing does not 

always match operating procedures. For example, they note that due to startup 

limitations the system operator may keep a peaking unit operating during non-peak hours 

so that the unit may be used again later in the day to meet increasing load. While 

operators should have the flexibility to make these types of decisions, it is critical that 

prices accurately reflect these operating procedures. Thus, PJM Power Providers states 

that if the system operator compensates the generator for the cost of keeping a peaking 

unit operating during non-shortage periods through an uplift charge rather than through 

the market-clearing price, as is currently the practice in PJM, this practice “must be 

 265 PJM Power Providers at 3. 

266 Id. at 4. 
Docket Nos. RM07-19-000 and AD07-7-000 - 105 - 

fixed.” It states that the shortage pricing mechanism should be coupled with a new 

“reserve product” so that the scarcity price reflects the opportunity cost of held reserves 

(the cost of operating the peaking unit during no-scarcity periods) in a manner that is 

consistent with the overall shortage pricing rules. Finally, PJM Power Providers states 

that to achieve the intended results, the Commission must provide that when a 

contingency or constraint related to operations and reserves is seen in either the dayahead or real-time market, shortage pricing should be reflected in the energy market as 

well. 

189. Finally, TAPS makes two recommendations. The first is that the Commission 

should maintain some type of “safety net cap” that will protect consumers against 

“stratospheric” prices.267 The second is that if the Commission does approve some 

shortage pricing rules, it must also revisit its approval of RTO and ISO capacity markets 

that were justified on the basis that such caps prevented generators from earning revenues 

needed to recover investment costs.268 It argues that if spot market prices can rise to the 

levels claimed to be needed to recover generator investment costs, a principal 

justification for organized capacity markets is eliminated, and consumers will be 

subjected to the high energy prices that the capacity market was intended to replace. 

 267 TAPS at 43. 

268 For example, TAPS notes that a primary justification of ISO New England’s 

locational installed capacity market proposal was that caps take away revenues needed 

for cost recovery. Id. 43-44. 
Docket Nos. RM07-19-000 and AD07-7-000 - 106 - 

190. Several commenters address the Commission’s requirement that RTOs and ISOs 

proposing shortage pricing reforms address the adequacy of any market power mitigation 

measures and that the Commission will solicit the views of the Independent Market 

Monitor for each RTO and ISO on any proposed reforms. EEI states that the 

Commission is correct to address concerns regarding the exercise of market power by 

requiring that any proposed reforms be supported by an adequate record demonstrating 

that provisions exist for mitigating market power and deterring gaming behavior.269 EEI 

agrees that the Commission should solicit input from the Independent Market Monitor on 

any proposed rule changes in this area. Old Dominion states that the Commission should 

adopt a presumption that such pricing incentives are not necessary and require the RTOs 

and ISOs that believe otherwise to make a factual demonstration that they are.270 This 

would include demonstrating that non-price barriers to demand response have been 

removed and that current market power mitigation rules will suffice to deal with any 

gaming behavior. Public Interest Organizations urge that before current market 

mitigation rules are relaxed, resource adequacy requirement must be in place and that an 

independent market monitor must be able to monitor shortage pricing behavior very 

closely.271 TAPS states that the Commission needs to strengthen the factual showing that 

 269 EEI at 19. 

270 Old Dominion at 15. 

271 Public Interest Organizations at 9. 
Docket Nos. RM07-19-000 and AD07-7-000 - 107 - 

RTOs and ISOs must make with respect to shortage pricing reforms272 to include at least 

six analyses: (1) address market power under scarcity conditions; (2) measure whether 

demand response successfully mitigates market power, including empirical evidence, 

such as critical loss analyses; (3) examine the incentive and ability of demand response 

resources to engage in withholding of their demand response resources; (4) demonstrate 

that market power mitigation methods are effective during shortage periods for any 

resource, demand or generation, that can affect prices; (5) determine if there is enough 

demand response available to respond under scarcity conditions; and (6) prepare statistics 

on past and expected frequency of scarcity events as an indication of the effectiveness of 

policies to ensure resource adequacy. 

191. Comverge and DRAM express concerns about “price averaging” and its possible 

adverse impact on demand response resource participation in organized markets. DRAM 

recommends time-differentiated capacity payments based on loss-of-load probability or 

loss-of-load expectation as an alternative to raising price caps during a period of 

operating reserve shortage as a means of removing a barrier to demand response 

resources.273 

ii. Commission Determination

192. In this Final Rule, the Commission adopts the proposed rule on price formation 

during times of operating reserve shortage. The Commission continues to find that 

 272 TAPS at 29. 

273 Comverge at 10; DRAM at 10. 
Docket Nos. RM07-19-000 and AD07-7-000 - 108 - 

existing rules that do not allow for prices to rise sufficiently during an operating reserve 

shortage to allow supply to meet demand are unjust, unreasonable, and may be unduly 

discriminatory. In particular, they may not produce prices that accurately reflect the 

value of energy and, by failing to do so, may harm reliability, inhibit demand response, 

deter entry of demand response and generation resources, and thwart innovation. 

193. When bid caps are in place, it is not possible to elicit the optimal level of demand 

or generator response, thereby forgoing the additional resources that are needed to 

maintain reliability and mitigate market power. This, in turn, increases the likelihood of 

involuntary curtailments and contributes to price volatility and market uncertainty. 

Further, by artificially capping prices, price signals needed to attract new market entry by 

both supply- and demand-side resources are muted and long-term resource adequacy may 

be harmed. Without accurate prices that reflect the true value of energy, we cannot 

expect the optimal integration of demand response into organized markets. 

194. Therefore, we are taking action to remove such barriers to demand response by 

requiring price formation during periods of operating shortage to more accurately reflect 

the value of such energy during such shortage periods. Each RTO or ISO is required to 

reform or demonstrate the adequacy of its existing market rules to ensure that the market 

price for energy reflects the value of energy during an operating reserve shortage. The 

RTO or ISO is required to provide, as part of its compliance filing, a factual record that 

includes historical evidence for its region regarding the interaction of supply and demand 

during periods of scarcity and the resulting effects on market prices, an explanation of the 

degree to which demand resources are integrated into the various markets, the ability of 
Docket Nos. RM07-19-000 and AD07-7-000 - 109 - 

demand resources to mitigate market power,274 and how market power will be monitored 

and mitigated, among other factors. 

195. Some commenters oppose price reforms during periods of shortages on grounds 

that such reforms may lead to the exercise of market power and will result in unjust and 

unreasonable rates. They argue that the Commission is abdicating market mitigation by 

allowing price caps to be removed during a power shortage. We disagree. To the 

contrary, the Commission is not taking any action to remove market mitigation in 

regional markets. Each of the Commission’s proposed reforms includes some form of 

mitigation, either bid caps, administratively-determined prices, or prices tied to payments 

made in emergency demand response programs administered by RTOs or ISOs (and thus 

approved by the Commission). RTOs and ISOs are free to propose other pricing reforms 

and associated mitigation that meet the criteria herein. Moreover, these reforms to 

enhance demand responsiveness further mitigate seller market power by allowing 

demand to choose to not consume power when the price is higher than they wish to pay. 

Allowing buyers to respond to prices reduces incentives for a seller to manipulate market 

prices. 275 

 274 As discussed further below, demand resources are the set of demand response 

resources and energy efficiency resources and programs that can be used to reduce 

demand or reduce electricity demand growth. 

275 See B.F. Neenan et al., Neenan Associates, 2004 NYISO Demand Response 

Program Evaluation, at E-5, (Feb. 2005); David B. Patton, Potomac Economics, 2006 

State of the Market Report - The Midwest ISO, at 44 (May 2007). 
Docket Nos. RM07-19-000 and AD07-7-000 - 110 - 

196. To guard the consumer against exploitation by sellers, we adopt the proposal to 

require RTOs and ISOs to adequately address market power issues in the compliance 

filings directed herein. We require an adequate factual record demonstrating that 

provisions exist for mitigating market power and deterring gaming behavior to be part of 

a compliance filing for price reform during periods of operating reserve shortage. This 

could include, but is not limited to, the use of demand resources to discipline bidding 

behavior to competitive levels during an operating reserve shortage. We also intend to 

closely monitor market behavior during periods of operating reserve shortage to ensure 

that market participants are following market rules and to guard against the exercise of 

market power. 

197. For purposes of providing the Commission with an adequate factual record 

regarding its shortage pricing proposal, the RTO or ISO must address the six criteria that 

we adopt below,276 several of which refer to demand resources. For these purposes, 

“demand resources” refers to the set of demand response resources and energy 

efficiency277 resources and programs that can be used to reduce demand or reduce 

 276 See discussion infra P 247. 

277The Commission’s Staff has defined energy efficiency to refer to using less 

energy to provide the same or improved level of service to energy consumers in an 

economically efficient way. Energy efficiency uses less energy by employing products, 

technologies, and systems to use less energy to do the same or better job than by 

conventional means. Energy efficiency saves kilowatt-hours on a persistent basis, rather 

than being dispatchable for peak hours, as are some demand-response programs. Energy 

efficiency can include switching to energy-saving appliances (such as Energy Star® 

certified products) and advanced lighting (compact fluorescent or LED lighting); 

improving building design and construction (better insulation and windows, tighter 

 (continued...) 
Docket Nos. RM07-19-000 and AD07-7-000 - 111 - 

electricity demand growth. Although the Final Rule requires provisions related to RTO 

or ISO ancillary services markets, aggregation by ARCs and deviation penalties to be 

implemented for demand response resources, we believe it is appropriate to allow the 

RTO or ISO to support its shortage pricing proposal with reference to the broader set of 

demand resources. 

198. We note that this Final Rule does not eliminate or otherwise revise the market 

power mitigation measures that remain in place during times when operating reserves are 

insufficient. For example, conduct and impact tests are applied in ISO New England, 

NYISO, and Midwest ISO. A pivotal supplier test is used in PJM. Further, PJM and 

CAISO mitigate bids by generators that are chosen out-of-merit order. 

199. Existing rules should combine effectively with the more vigilant monitoring 

required in this rule to dissuade the exercise of market power. Further, as noted in the 

NOPR, the pricing reform established in this Final Rule is only one part of the continuing 

effort by the Commission and RTOs and ISOs to improve the functioning of organized 

markets. 

200. TAPS recommends a “safety net cap” to protect against very high prices and for a 

review of the need for capacity markets if there is shortage pricing. As stated earlier, 

none of the four approaches suggested by the Commission precludes a limit on prices. 

 

ductwork, use of high-efficiency heating, ventilation, and air conditioning); and 

redesigning manufacturing processes (advanced electric motor drives, heat recovery 

systems) to use less energy, thus reducing use of electricity and natural gas. Federal 

Energy Regulatory Commission, Assessment of Demand Response & Advance Metering: 

Staff Report at A-4 (September 2007). 
Docket Nos. RM07-19-000 and AD07-7-000 - 112 - 

For example, the first approach does not propose necessarily to eliminate bid caps; 

instead, “bid caps would be allowed to rise above existing caps” (as stated in the NOPR) 

during an operating reserve shortage. No explicit amount of increase is stated or required 

under the first suggested approach. Under the second approach, a demand curve for 

operating reserves is commonly capped at some multitude of the expected cost of new 

entry (for instance, one and a half times the cost of new entry). The market-clearing price 

under the fourth approach—allowing the payment made to emergency demand response 

providers to set the market-clearing price—depends on that payment. As such, the 

approaches already account for a “safety net” cap. 

201. TAPS and others also recommend examining the need for capacity markets under 

shortage pricing and whether customers would be charged twice. Under all existing 

capacity market rules, the revenues earned from the sale of energy and ancillary services 

are accounted for in the calculation of capacity payments so that customers will not be 

double charged. Comverge and DRAM suggest addressing price averaging in capacity 

markets as an alternative to raising price caps during periods of operating reserve 

shortages. The Commission has noted previously that this rulemaking is not designed to 

address capacity market issues and, therefore, finds their comments to be outside the 

scope of this proceeding. 

202. Some commenters argue that end users are not able to see hourly prices and, 

therefore, will not respond to a shortage price signal. Similarly, several commenters 

argue that demand response capability must be in place before changes to mitigation rules 

are considered. Demand response programs that currently allow a fraction of the load to 
Docket Nos. RM07-19-000 and AD07-7-000 - 113 - 

respond can have a positive effect on system reliability and market demand and help 

reduce prices for all. Full deployment of advanced meters and complete participation by 

all load is not needed to help cope with operating reserve shortages.278 In addition, the 

Commission establishes six criteria, as discussed below, to evaluate an RTO’s or ISO’s 

proposal – criteria designed to ensure that the shortage pricing proposal achieves the 

objectives of this requirement while protecting customers from market power.279

203. Further, with better price signals, more buyers would find it worthwhile to invest 

in technologies that allow them to respond to prices. Also, while some customers may 

not be able to respond to hourly prices, they will see monthly bills and have an incentive 

to reduce use of power in general by, for example, setting air conditioning thermostats 

higher during peak periods or simply when the weather forecast calls for high 

temperatures, or engaging in energy efficiency, which can lead to an overall reduction in 

market demand, reduced need for marginal resources, and fewer periods of shortage. 

Further, we reiterate that such price signals would encourage entry by generators, 

investment in new technology, and more participation in demand response programs. 

204. Several commenters are concerned that some demand response resources would be 

negatively affected by the shift of revenues from capacity markets to energy markets. In 

 278 See Federal Energy Regulatory Commission, Assessment of Demand Response 

and Advanced Metering: Staff Report, Docket No. AD06-2-000, at 7. As little as five 

percent of load responding to a high price can avert a system emergency and may help to 

lower the market price. 

279 See discussion infra at P 247. 
Docket Nos. RM07-19-000 and AD07-7-000 - 114 - 

general, giving resource suppliers and customers more choices for how they participate in 

markets is beneficial. Shortage pricing in an emergency and capacity markets for longterm resource adequacy assurance serve largely distinct purposes, but we agree that they 

should not work at cross purposes. Adding any new element to a market design can have 

effects on the other elements. We require that each RTO and ISO address in its 

compliance filing how its selected method of shortage pricing interacts with its existing 

market design. 

205. We disagree with LPPC’s claim that higher prices during shortage periods will 

destabilize long-term arrangements. Allowing prices to rise during emergencies should 

instead provide an incentive for customers to increase their hedging through long-term 

contracting. Further, as noted above, it should also encourage investment in demand 

response technology and provide an incentive to market participants to participate in load 

response programs, thereby mitigating the expected higher prices. 

206. Our requirement that RTOs and ISOs provide a factual record to demonstrate the 

adequacy of market power mitigation measures, coupled with the Commission’s 

solicitation of the views of each RTO’s and ISO’s Market Monitoring Unit on proposed 

shortage pricing reforms, as supported by EEI, should address the concerns of Old 

Dominion, Public Interest Organizations, and TAPS regarding the ability of market 

participants to exercise market power during periods of operating reserve shortages. 

207. Finally, we address PJM Power Providers’ concerns that shortage pricing 

mechanisms be integrated into the overall market design of the RTO, perhaps with a new 

“reserve product,” and the need for contingencies or constraints related to reserves that is 
Docket Nos. RM07-19-000 and AD07-7-000 - 115 - 

seen in the day-ahead or real-time market to be reflected in the energy market. We share 

PJM Power Providers’ concern about out-of-merit order generation, such as the example 

they cite, and it being reimbursed through up-lift charges. A market works more 

efficiently when all decisions of the system operator that affect costs, e.g., running 

peaking units, are reflected in market prices rather than in uplift charges. We encourage 

all RTOs and ISOs to consider this when evaluating their existing shortage pricing rules 

or developing new ones. This might include, as PJM Power Providers describes it, the 

development of “new reserve products.” As to their second concern, we also agree that 

the better integrated markets are with one another, the more efficiently they will operate. 

However, the aim of this rulemaking, maintaining reliability through entry of new 

generation and demand response resources, need not be achieved through one particular 

market rule structure. 

b. Four Approaches

208. In the NOPR, the Commission proposed to require each RTO or ISO to make a 

compliance filing proposing any necessary reforms to ensure that the market price for 

energy accurately reflects the value of such energy during an operating reserve shortage. 

Given regional differences in market design, the Commission did not propose to require 

one particular approach to achieving this reform. Rather, the Commission stated that 

each RTO or ISO may propose one of four suggested approaches or another approach 

that achieves the same objectives. 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 
Docket Nos. RM07-19-000 and AD07-7-000 - 116 - 

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. 

i. Comments

209. Many commenters spoke for or against all four approaches collectively. Those in 

support state that each of the four approaches is an appropriate means for achieving the 

goals of the NOPR’s proposal on shortage pricing. Supporters of all four approaches 

typically did not address each approach individually, and their comments are included 

above among those who spoke in support of the overall proposal. Similarly, many of the 

commenters that oppose the overall proposal and all four approaches are also summarized 

above, but a few of these make more detailed collective comments on the NOPR’s four 

suggested approaches, which are presented next. For example, NRECA and APPA state 

that they are firmly opposed to the Commission’s four approaches to change pricing rules 

during shortage situations and base their opposition on the fundamental disagreement that 

current prices during shortage periods are unjust and unreasonable.280 NRECA states that 

the approaches put forward by the Commission would result in rates that are unjust and 

unreasonable, and would, at a minimum, grant windfall profits to those suppliers that 

 280 NRECA at 23. 
Docket Nos. RM07-19-000 and AD07-7-000 - 117 - 

have been found by the RTOs’ and ISOs’ market monitors to possess market power. 

APPA also states that it does not support any of the four proposed shortage pricing 

approaches.281 Public Interest Organizations state that it cannot support any of the 

Commission’s proposed approaches at this time because demand response participation is 

not at a level that will assure customers that prices will be just and reasonable.282 Public 

Interest Organizations urge that before current market mitigation rules are relaxed, a 

resource adequacy requirement must be in place and market access and effective demand 

response resource participation must be demonstrated. It also states that an independent 

market monitor must be able to monitor shortage pricing behaviors very closely.

210. Numerous commenters spoke for or against some of the four approaches, and their 

comments on each approach are discussed next. 

211. Among those who favored one or more of the four approaches, the demand curve 

for operating reserves (the third approach) received the most and strongest support. 

212. Under the first approach, RTOs and ISOs would increase energy bid caps (for each 

bidder) and the price cap (for the market-clearing price) above the current level, but only 

during an operating reserve shortage.283 PJM Power Providers supports this approach 

 281 APPA at 29. 

282 Public Interest Organizations at 17. 

283 For example, PJM may choose to increase its current market-wide price cap. 

Another RTO or ISO could lift individual generator bid caps while keeping its marketwide price cap at its existing level. What exactly will be changed under this proposal 

depends on existing rules and what the RTO or ISO stakeholders consider for that 

 (continued...) 
Docket Nos. RM07-19-000 and AD07-7-000 - 118 - 

and notes that to avoid market power concerns, bids may be assessed for the potential of 

economic withholding by considering the value of lost load multiplied by the increased 

probability of outages. FirstEnergy supports lifting bid caps during a shortage if the 

shortage is genuine, wholesale prices are reflected in retail rates, and energy and demand 

response are treated on a comparable basis.284 Ohio PUC states that it would recommend 

this approach only where there are a sufficient number of suppliers or enough demand 

response to check the exercise of market power.285 In commenting on the four 

approaches, Mr. Borlick notes that the Commission has correctly concluded that energy 

prices during periods of supply shortage fail to accurately reflect the value of load 

reduction.286 Mr. Borlick states that approach 1 would produce energy prices high 

enough to accurately reflect the marginal value of consumption but would also encourage 

generators to exercise market power both through economic and physical withholding. 

Of the four approaches proposed in the NOPR, Mr. Borlick states that this is the least 

desirable. He states that approach 2 is superior to approach 1 because it would allow the 

demand side to set economically efficient clearing prices while controlling economic 

withholding by generators, although generators could still physically withhold capacity. 

 

region’s market design and on what the RTO or ISO then proposes in its compliance 

filing. 

284 FirstEnergy at 11. 

285 Ohio PUC at 10-11. 

286 Mr. Borlick at 5. 
Docket Nos. RM07-19-000 and AD07-7-000 - 119 - 

Its drawback is that it does not provide a vehicle for efficiently trading off operating 

reserves for energy production. 

213. NRECA opposes the first approach because it would remove price caps that have 

been established to mitigate market power, exposing consumers to the price bid by the 

marginal resource. NRECA asserts that the market-clearing price during a system 

emergency could potentially exceed the cost of the marginal resource dispatched and the 

cost of new entry.287 Similarly, TAPS opposes the first approach because it offers 

consumers no protection against the exercise of market power and thus would only 

produce unjust and unreasonable rates.288 TAPS notes that if demand response is 

insufficient to restrain prices, the Commission would have to rely on generators, who 

have neither the ability nor the incentive to set a price that is just and reasonable under 

shortage conditions.289

214. Other commenters present a variety of reasons for not supporting the first 

approach. NEPOOL Participants argues that imposing either of the first two approaches 

in ISO New England could have unintended effects on New England markets because 

many market participants agreed to the forward capacity market with the understanding 

that the $1000/MWh cap on “energy offers and bids” would not be removed.290 Maine 

 287 NRECA at 20. 

288 TAPS at 40. 

289 Id.

290 NEPOOL Participants at 17. 
Docket Nos. RM07-19-000 and AD07-7-000 - 120 - 

PUC claims that in New England, it is particularly unreasonable to impose a requirement 

to remove bid caps from the energy market or take other steps that remove consumer 

protections prior to a showing that consumers can change their behavior to avoid being 

harmed.291

215. Comverge asserts that the first approach may invite gaming: generators could 

withhold capacity so that emergency conditions occur and then take advantage of the 

ensuing higher prices. However, it states that if a much more dispatchable demand 

response and voluntary price-response were in place the potential for gaming would be 

substantially reduced.292 Duke Energy states that it is unrealistic to expect resources to 

accurately predict emergency conditions and tailor their bids appropriately. Thus, it 

states that this approach would provide generation owners with an incentive to bid above 

cost, putting upward pressure on prices.293 

216. Potomac Economics recommends that the Commission not encourage this 

approach because it believes that the theory implicit in this approach is flawed. It states 

that when the system is in a shortage, relying on supply offers is not the action generally 

taken by system operators. Also, if suppliers do not have market power, they will not 

have an incentive to raise the price of their offers. Therefore, it concludes that pursuing 

 291 Maine PUC at 5. 

292 Comverge at 21. 

293 Duke Energy at 9. 
Docket Nos. RM07-19-000 and AD07-7-000 - 121 - 

an approach that relies on suppliers to raise their offers to achieve efficient price signals 

during shortage conditions would not be reliable.294

217. NRECA states that, in presenting the first and second approaches, the NOPR uses 

the terms bid caps, offer caps, and price caps interchangeably and asks the Commission 

to specifically define these terms. North Carolina Electric Membership also notes that 

the NOPR does not clearly distinguish between a generation offer cap in place as a result 

of mitigation procedures and the $1,000/MWh umbrella energy offer cap ceiling in place 

in most RTOs and ISOs.295

218. Under the second approach, RTOs and ISOs would raise bid caps above the 

current levels only for demand bids, that is, for bids by customers expressing their 

willingness to pay more than the market price cap to continue to receive power during an 

emergency and hence perhaps avoid being curtailed. Ohio PUC states that lifting the 

caps for only demand bids during system emergencies is a reasonable approach for 

creating transparent price signals in shortage situations.296 

219. NRECA opposes this approach because these demand bids would set the marketclearing price paid to all resources, including generators. This would result in customers 

paying rates to generators that exceed the costs of the most expensive generator available 

on the system, even if those generators do nothing unusual to alleviate the emergency 

 294 Potomac Economics at 4-5. 

295 Id. 

296 Ohio PUC at 12. 
Docket Nos. RM07-19-000 and AD07-7-000 - 122 - 

condition.297 TAPS states that this approach could also raise market power concerns if 

the market participant submitting a demand bid also had generation that could benefit 

from a price increase.298 

220. Duke Energy and FirstEnergy do not support this approach because generation 

resources would be treated differently from load, which is inconsistent with the 

comparability principle the Commission proposes for demand resources.299

221. Under the third approach, RTOs and ISOs would establish a demand curve for 

operating reserves, which establishes a predetermined schedule of prices according to the 

level of operating reserves. As operating reserves become shorter, the price increases. 

Many commenters support this approach and state that it should be implemented.300 

Several commenters assert that this approach: (1) is the most efficient means of moving 

prices toward the value of lost load during emergency situations;301 (2) would promote 

reliability by providing greater and timely incentives for market participants to provide 

 297 NRECA at 20. 

298 TAPS at 41-42. 

299 Duke Energy at 9; First Energy at 11. 

300 E.g., Ameren; Mr. Borlick; Constellation; Duke Energy; Exelon; FirstEnergy; 

Potomac Economics; PJM Power Providers; and PPL Parties. 

301 Duke Energy at 10. Duke Energy explains that the use of predetermined 

demand curves provides a structure under which the price of energy rises to the level of 

the value of lost load when firm loads are interrupted. As the probability of falling below 

target reserve levels rises, the price of energy and reserves also rises. Any load that 

wishes to respond to higher prices would take appropriate action to curtail demand. Duke 

Energy believes that the use of such shortage pricing is essential to elicit broader demand 

response. Id. (citing Robert Stoddard Affidavit, Duke Energy ANOPR Comments). 
Docket Nos. RM07-19-000 and AD07-7-000 - 123 - 

capacity;302 (3) can allow RTOs and ISOs to set prices that more accurately reflect the 

costs of meeting demand and reserve requirements during power shortages;303 and (4) 

avoids various concerns regarding the exercise of market power. PPL Parties note that 

the Commission has already approved this approach for the ISO New England, NYISO, 

and Midwest ISO markets.304 Dominion Resources also emphasizes that the demand 

curve for operating reserves has proved to be a workable method in ISO New England.305 

Of the four approaches, Mr. Borlick states that approach 3 is the most appealing based on 

economic theory; however, it poses implementation problems because of the 

computational burden involved in developing a demand curve that would accurately 

reflect the value of consumption. 306

222. Potomac Economics states that implementing a demand curve for operating 

reserve is critical for achieving efficient shortage pricing and should be a required 

element for RTO or ISO markets.307 It states that such demand curves are most 

effectively implemented in the context of jointly-optimized energy and ancillary services 

markets. It believes that effective shortage pricing requires jointly-optimized markets 

 302 PJM Power Providers at 6. 

303 Ameren at 28. 

304 PPL Parties at 6. 

305 Dominion Resources at 7. 

306 Mr. Borlick at 8. 

307 Potomac Economics at 5. 
Docket Nos. RM07-19-000 and AD07-7-000 - 124 - 

with operating reserve demand curves set at levels that reflect the value of reliability that 

the operating reserves provide to consumers.308 However, Potomac Economics states that 

the third approach alone is not sufficient and that the fourth approach, allowing payments 

to emergency demand response resources to set the market-clearing price is a valuable 

complement.309 It notes that RTOs and ISOs can call on emergency demand response or 

interruptible retail load to maintain reliability. These forms of demand response are not 

integrated into the market, and therefore some form of the fourth approach is needed to 

set efficient shortage prices when the demand response of emergency demand response 

providers is called on in an emergency.310

223. PJM Power Providers proposes that PJM should use a downward-sloping 

operating reserve demand curve simultaneously for both energy and operating reserves, 

instead of having a fixed operating reserve requirement. It notes that this would (1) 

remove certain anomalies that occur with the current fixed requirement, (2) provide an 

adequate incentive for “increased energy demand bidding,” and (3) improve reliability by 

providing greater and timely incentives for market participants to provide capacity.311

Constellation supports the approach of using a demand curve for operating reserves. 

While acknowledging this approach presents practical problems associated with 

 308 Id. at 6. 

309 Id. at 7. 

310 Id.

311 PJM Power Providers at 7. 
Docket Nos. RM07-19-000 and AD07-7-000 - 125 - 

developing the demand curve, Constellation states that these can be addressed and the 

benefits of this solution justify efforts to deal with these challenges.312 Exelon states that 

the demand curve for operating reserves, the Commission’s third approach, would be the 

most effective of the four approaches (although it recommends an alternative approach, 

reported below) because it would help induce additional demand response during periods 

of peak demand. FirstEnergy states that an administratively set demand curve is an 

acceptable way to set the operating reserve price in times of shortage because the demand 

side of the market is underdeveloped and cannot respond to market forces on the same 

scale as supply-side resources. It states that a demand curve can effectively mitigate 

market power where one market participant becomes the last available supplier in a 

shortage.313

224. NRECA opposes the demand curve for reserves approach because it is designed to 

raise the price above the current maximum level allowed. TAPS states that the third 

approach risks mandating a particular type of reform, an RTO-run ancillary services 

market, rather than a reform that originates with stakeholders.314

225. Ohio PUC does not support the third approach because a demand curve for 

operating reserves may not ensure that any new generation will be built.315 Comverge 

 312 Constellation at 13. 

313 FirstEnergy at 11-12. 

314 TAPS at 42. 

315 Ohio PUC at 11. 
Docket Nos. RM07-19-000 and AD07-7-000 - 126 - 

states that the third approach is difficult to implement because it requires an 

administrative determination of the demand curve’s characteristics.316

226. Under the fourth approach, RTOs or ISOs would set the market-clearing price 

during an operating reserve shortage at the payment made to participants in an emergency 

demand response program. PJM Power Providers states that this fourth approach is 

reasonable, but notes that when operating reserves and locational reserve requirements 

decline below target levels despite use of the fourth approach, the question of how to set 

and adjust the price must then be addressed.317

227. TAPS states that the fourth approach appears to allow market-clearing prices to be 

set by the RTO or ISO at whatever payment an RTO or ISO makes to a demand response 

resource that reduces consumption during emergencies in return for a contractually 

established payment that, perhaps, was determined by a regulatory body other than the 

Commission and, therefore, would be outside of the Commission-approved marketclearing mechanism and on that basis rejects it.318 Comverge believes that the fourth 

approach presents two issues: (1) participants are likely to ignore the market value of 

demand response before an emergency is declared; and (2) the emergency value of 

demand response would be substituted for the market value of power, which may 

 316 Comverge at 22. 

317 PJM Power Providers at 8. 

318 TAPS at 42. 
Docket Nos. RM07-19-000 and AD07-7-000 - 127 - 

reinforce the use of demand resource as an emergency-only resource.319 Similarly, Duke 

Energy states that this proposal is questionable because it would be difficult to determine 

exactly what price would be paid to non-demand response market participants, and the 

program price paid to participating demand response resources may not actually reflect 

these participants’ or other parties’ economic assessment of the hourly value of power. 

Emergency demand response resources do not submit bids, but just receive a payment, 

against which they must judge the cost of forgoing energy. Because there is no 

solicitation of value from resources, it would be difficult and unreliable to determine a 

single price that would be suitable both for the interrupted emergency demand response 

providers and for payment to other resource providers.320 Mr. Borlick gives approach 

four the most favorable review on the basis that it creates an incentive of demand 

response to bid its true interruptible cost and, therefore is more likely to produce 

economically efficient prices.321 

228. Ameren particularly objects to the fourth approach because of the market 

distortion and unintended consequences it could cause. It states that load should receive 

payments for demand response only if the load clears in the day-ahead market, and its 

 319 Comverge at 22. 

320 Duke Energy at 10 (citing Robert Stoddard Affidavit, Duke Energy ANOPR 

Comments at 16). 

321 Mr. Borlick at 9. 
Docket Nos. RM07-19-000 and AD07-7-000 - 128 - 

payment should be based on the bid that the market participant submitted.322 Ohio PUC 

does not support the fourth approach, stating that it falls short of resolving the problem at 

hand.323

229. A few commenters offer new approaches or variations on one of our four 

suggested approaches. EPSA points to the 2007 PJM State of the Market Report to assert 

that other approaches besides these four should be considered. Specifically, in that report 

PJM’s market monitor, Joseph Bowring, recommended that shortage pricing should be 

defined in several stages with different pricing in each stage. While EPSA does not 

specifically endorse this proposal, it states that such a proposal should be considered.324 

230. Exelon suggests a variation on the Commission’s proposed shortage pricing 

approaches. Exelon proposes a price cap in the market that would ratchet up as shortage 

conditions worsen.325 This price cap would rise to predetermined levels as a shortage 

situation approaches. In essence, this would work like a demand curve, with the price 

cap increasing as the amount of available operating reserves diminished. Under this 

approach, the administratively set price levels would function as a moving cap and the 

market would determine the value of supply, up to that administratively set price cap.326 

 322 Ameren at 28-29. 

323 Ohio PUC at 12. 

324 EPSA at 10. 

325 Exelon at 11. 

326 Id. at 12. 
Docket Nos. RM07-19-000 and AD07-7-000 - 129 - 

Exelon maintains that this approach would elicit demand response to alleviate the 

shortage before it becomes a real crisis. It makes the point that no bids under this cap 

would be subject to mitigation procedures. Exelon believes that this approach is superior 

because it allows the market to determine the value of supply, within the cap, rather than 

requiring the market administrator to impose a value. 

231. NRECA offers what it says is a variation on the second approach, and APPA and 

TAPS support this alternative. They propose allowing only demand response resources 

to bid higher than the current caps. Demand response resources would be paid the 

resulting clearing price, but generating resources would not. Instead, generators would 

receive the highest clearing price among the generating resources. NRECA explains that 

this approach would encourage additional demand response by allowing demand 

response resources to obtain a higher price for their response during emergencies. 

Specifically, it states that this proposal would: (1) encourage additional demand 

response; (2) contribute to maintaining reliability; (3) help achieve the needed balance 

between demand and supply on a real-time basis; and (4) not shift rents from consumers 

to those generators whose market power must be mitigated by supply bid caps in the first 

place.327 TAPS states that if properly implemented, this proposal should not incent 

generators to create emergencies because they would not profit from them and, although 

this proposal would add to the uplift consumers must bear, it would not exact the same 

degree of extreme hardship on consumers as elevating the market-clearing price across 

 327 NRECA at 17. 
Docket Nos. RM07-19-000 and AD07-7-000 - 130 - 

“swaths of the nation.”328 TAPS asserts that this alternative proposal is an effective way 

for the Commission to gather data on the willingness of demand response to come to 

market and on the relative costs of the uplift associated with this method versus allowing 

the demand response price to be the market-clearing price. In order to guarantee that 

such a proposal would be allowable, TAPS suggests changes to the proposed regulatory 

language and the definition of “operating reserve shortage.”329 Like NRECA, Steel 

Manufacturers indicates that it would support the removal of bid caps for demand 

response resources during a system emergency if the higher bids do not set the marketclearing prices.330 

232. Comverge recommends an alternative approach that allows price caps to be 

relaxed as the market adds more dispatchable, price-responsive demand response. It 

states that this would allow for use of the best forms of market power mitigation: 

dispatchable demand response and customer price response.331

233. Potomac Economics states that the Commission should add to the four approaches 

provisions that would set efficient prices when the RTOs and ISOs take other emergency 

 328 TAPS at 37. 

329 Id. at 39. 

330 NRECA at 17; Steel Manufacturers at 13. 

331 Comverge at 22. 
Docket Nos. RM07-19-000 and AD07-7-000 - 131 - 

actions under shortage conditions, including emergency transactions, export curtailments, 

voltage reductions, and other emergency actions.332

ii. Commission Determination

234. Although we require RTOs and ISOs to modify, where necessary, their market 

rules governing price formation during periods of operating reserve shortage, we will not 

mandate any specific approach to this reform. Rather, because each market design is 

different, the changes to market rules should reflect each region’s market design. To that 

end, each RTO or ISO may propose one of four approaches or another approach that 

achieves the same objectives. Each RTO or ISO should work with its stakeholders to 

develop a program that is appropriate for its region. Each of the four suggested 

approaches can be fashioned in a reasonable way upon compliance to achieve the 

objectives of the reform required here. 

235. We address comments on the four approaches below. We will not address 

individually each comment on the four approaches provided by the Commission because 

we are not mandating one specific approach that all RTOs and ISOs must follow, and 

because each RTO and ISO must demonstrate that it currently complies with the rule or 

has a proposal that will put it in compliance. We cannot make a determination at this 

point that any particular approach as offered by an RTO or ISO is superior to another. 

Indeed, that is why a menu of options is offered here. One method of pricing during 

shortage situations may work better than another for any one RTO or ISO. All four of the 

 332 Potomac Economics at 7. 
Docket Nos. RM07-19-000 and AD07-7-000 - 132 - 

approaches presented by the Commission have the potential to meet the goals of this 

rulemaking: maintaining reliability, eliminating barriers to the comparable treatment of 

demand response, and allocating energy during a shortage to those who value it most. 

Any filing by an RTO or ISO will be judged according to the criteria set forth in this 

Final Rule. We are also requiring the Independent Market Monitor for each RTO and 

ISO to provide us with its view on any proposed reforms. Finally, any proposal put forth 

by an RTO or ISO that follows a path different from the four approaches offered here 

must meet the same criteria set forth above. Only when an RTO or ISO submits a 

compliance filing can and will the Commission determine if its pricing rules are just and 

reasonable, not unduly discriminatory and sufficient to meet the stated goals of this 

rulemaking. 

236. NRECA and North Carolina Electric Membership seek clarification on the terms 

bid cap, offer cap, and price cap. Bid cap refers to the maximum price that a seller 

(generation or demand response resource) or buyer may bid (i.e., offer to sell or buy) 

energy.333 The term price cap refers to a limit on the price of energy in an organized 

market.334 In this rulemaking we have restricted our usage to bid cap or price cap, as 

appropriate. 

 333 Although bid cap and offer cap have the same meaning in the NOPR, we use 

only the term bid cap to avoid confusion. 

334 For example, a particular generator may have a bid cap of $100 and bid $100 

but be paid a higher market-clearing price. A price cap is a limit on the market-clearing 

price. 
Docket Nos. RM07-19-000 and AD07-7-000 - 133 - 

237. Several commenters offer alternative approaches to modifying shortage pricing 

rules. In the NOPR we asked commenters to provide us with, not just barriers, but 

potential solutions, and these commenters have done just that. While we will not adopt 

any of these proposed changes explicitly in this rule, we note that RTOs and ISOs and 

their stakeholders are free to consider these and other possible solutions and propose to us 

their own method of shortage pricing reform that satisfies the criteria as well as our four 

approaches.

c. The Commission’s Proposed Criteria

238. The Commission proposed to adopt further requirements to ensure that any 

proposed reforms of shortage pricing rules or demonstrations of the adequacy of existing 

rules in the area of shortage pricing have adequate factual support and that RTOs and 

ISOs show how the proposed reforms are designed to protect consumers against the 

exercise of market power.335 First, each RTO or ISO proposing to reform or demonstrate 

the adequacy of its existing market rules in this area must provide an adequate factual 

record for the Commission to evaluate its proposal. This factual record will allow the 

Commission to discharge its duty to ensure that any reform is just and reasonable, not 

unduly discriminatory, and appropriately tailored to the circumstances in the RTO’s or 

ISO’s region. Second, the Commission proposed that any change in market rules to 

implement the proposed reforms must consider the issue of market power and the RTO or 

ISO proposing reform must address the adequacy of any market power mitigation 

 335 NOPR, FERC Stats. & Regs. ¶ 32,628 at P 118. 
Docket Nos. RM07-19-000 and AD07-7-000 - 134 - 

measures that would be in place during an operating reserve shortage. In addition, to 

ensure an adequate record on the issue of market power mitigation, the Commission 

proposed to solicit the views of the Independent Market Monitor for each RTO or ISO 

region on any proposed reform. 

239. Further, the Commission stated that it would consider the factual record compiled 

by the RTO or ISO to determine whether its proposal, or its demonstration of the 

adequacy of its existing market rules, meet six criteria, namely, that the proposal would: 

• Improve reliability by reducing demand and increasing generation during 

periods of operating reserve shortage; 

• Make it more worthwhile for customers to invest in demand response 

technologies; 

• Encourage existing generation and demand resources needed during an operating 

reserve shortage to remain in business; 

• Encourage entry of new generation and demand resources; 

• Provide comparable treatment and compensation to demand resources during 

periods of operating reserve shortages; and 

• Have provisions for mitigating market power and deterring gaming behavior, 

including, but not limited to, use of demand resources to discipline bidding 

behavior to competitive levels during periods of operating reserve shortages. 
Docket Nos. RM07-19-000 and AD07-7-000 - 135 - 

240. The Commission requested comment on whether these criteria are appropriate and 

whether there are additional criteria that we should consider in evaluating a proposal for 

pricing during a period of operating reserve shortage by RTOs and ISOs.

i. Comments

241. Duke Energy supports the proposed criteria to evaluate RTO’s and ISO’s filings 

on proposed reforms for shortage pricing. Wal-Mart states that the criteria are a 

reasonable approach to providing guidance to RTOs and ISOs in their reform 

proposals.336 EPSA states that the Commission must be clear in the Final Rule on the 

principles and the criteria which underpin its proposal.337

242. Comverge states that it supports each of the six proposed criteria to demonstrate 

the merits of new energy market rules and the Commission’s proposed rulemaking 

approach for each respective RTO or ISO. However, it recommends that the 

Commission add the following criterion: “where applicable, require a detailed 

assessment of the impact of new energy market rules on the respective capacity market 

participants.”338

243. North Carolina Electric Membership states that if the Commission adopts the 

proposed rule on price reform during shortage periods, the Commission should adopt 

additional criteria to protect consumers against the exercise of market power, similar to 

 336 Wal-Mart at 8. 

337 EPSA at 8. 

338 Comverge at 23. 
Docket Nos. RM07-19-000 and AD07-7-000 - 136 - 

the minimum protections included in the PJM shortage pricing settlement.339 It suggests 

that the Commission should also require RTOs and ISOs to show that any shortage 

pricing will: (1) protect consumers in the most vulnerable and smallest load pockets 

where access to available resources is significantly constrained even in non-shortage 

conditions; (2) define explicit triggers for when shortage prices will apply; (3) ensure that 

the extra revenues received by generators will be included in the energy and ancillary 

service revenue offset to capacity market clearing prices paid in forward capacity 

markets; and (4) require that RTOs and ISOs work with stakeholders to develop a 

program for setting prices during a power shortage that is acceptable to all.340 

244. Similarly, PG&E states that the proposed criteria should be expanded to include 

the following: (1) a demonstration that any proposed market rule changes are cost 

effective, including an evaluation of the impact on reliability and an estimation of the 

cost of the program; (2) an evaluation that the operating reserve shortage pricing 

mechanism is adequately coordinated with other key market mechanisms; and (3) an 

assessment of the readiness of demand response programs that will be called upon to 

reduce the number and severity of shortage pricing events and help mitigate market 

power.341

 339 North Carolina Electric Membership at 12-13. 

340 Id. at 12. 

341 PG&E at 13. 
Docket Nos. RM07-19-000 and AD07-7-000 - 137 - 

245. TAPS asserts that the Commission needs to strengthen the factual showing that 

RTOs and ISOs must make with respect to shortage pricing reforms. It states that each 

RTO’s or ISO’s compliance filing should include the following: (1) market power 

analysis specifically addressing scarcity conditions, including pivotal supplier, market 

share, and the delivered price test; (2) an analysis of whether demand response 

successfully mitigates market power, including empirical evidence, such as critical loss 

analyses; (3) market power analyses addressing the ability of generation owners to 

withhold demand response; (4) a demonstration that the RTO has methods for mitigating 

market power that are effective during shortage periods, for any resources, demand or 

generation, that can affect prices; (5) an analysis of whether there is enough demand 

response available to respond under scarcity conditions, given reliance on demand 

response for capacity reserves and ancillary services; and (6) prepared statistics on past 

power shortages and expectations of future power shortages.

ii. Commission Determination

246. In this Final Rule, the Commission adopts the proposal to require each RTO or 

ISO to support its proposed reform in shortage pricing or its demonstration of the 

adequacy of its existing rules with adequate factual support. This factual record will 

allow the Commission to discharge its duty to ensure that any reform is necessary and 

narrowly tailored to address the circumstances in that region, and that it is designed to 

protect consumers against the exercise of market power. The Commission here adopts 

the six criteria proposed in the NOPR, as modified below, and will use these six criteria 
Docket Nos. RM07-19-000 and AD07-7-000 - 138 - 

to consider whether the factual record compiled by the RTO or ISO meets the 

requirements adopted in this Final Rule. 

247. After further review of the criteria identified in the NOPR, we revise the criteria. 

The RTO or ISO must describe how its proposal would: 

• Improve reliability by reducing demand and increasing generation during 

periods of operating reserve shortage; 

• Make it more worthwhile for customers to invest in demand response 

technologies; 

• Encourage existing generation and demand resources to continue to be relied 

upon during an operating reserve shortage; 

• Encourage entry of new generation and demand resources; 

• Ensure that the principle of comparability in treatment of and compensation to 

all resources is not discarded during periods of operating reserve shortage; and 

• 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. 

248. The criteria we adopt are not significantly different from the criteria proposed in 

the NOPR. Our intention in revising the criteria is to further clarify what we expect from 
Docket Nos. RM07-19-000 and AD07-7-000 - 139 - 

an RTO’s or ISO’s compliance filing.342 Under the revised criteria, we expect an RTO or 

ISO to explain how its market rules will reduce or avoid periods of operating reserve 

shortages as well as how its market rules will reliably reduce demand and increase 

generation during periods of operating reserve shortage. Nothing in this Final Rule 

dictates the particular market rules or mechanisms an RTO or ISO must adopt. For 

example, we do not require regions that have not adopted a capacity market to develop 

such markets. We are intentionally providing latitude to the RTOs and ISOs to work with 

their stakeholders to determine the appropriate mechanisms for their regions and then 

explain how those mechanisms meet the revised criteria. 

249. Some commenters propose expanding or modifying the criteria. However we 

conclude, that the following suggestions are already either explicitly part of the required 

filing or are implicitly required. For example, North Carolina Electric Membership 

suggests a specific criterion that the Commission should adopt to protect consumers 

against the exercise of market power. Such a requirement, however, is already implicit in 

the required analysis of market power mitigation adopted here. Requiring that energy 

 342 For example, the third criterion in the NOPR sought an explanation of how the 

market rules encourage existing generation and demand resources needed during an 

operating reserve shortage to “remain in business.” Upon review, the Commission is 

concerned that this could have been read to require shortage pricing provisions that 

would subsidize or give preferences to resources to ensure they “remain in business.” 

Instead, our intention is for the RTO or ISO to explain how its shortage pricing proposal, 

together with existing market rules, encourages existing generation and demand resources 

to be available in an emergency. Similarly, the fifth criterion in the NOPR could have 

been read to limit comparable treatment and compensation for all resources to periods of 

operating reserve shortage. Because neither of these implications was our intention, we 

clarify the wording of these criteria. 
Docket Nos. RM07-19-000 and AD07-7-000 - 140 - 

and ancillary services revenues be accounted for in the settlement of capacity market 

payments also is already an explicit requirement for existing capacity markets. Further, 

all RTOs and ISOs have established procedures by which market rule changes are 

developed, which generally include consultations with their stakeholders. We expect that 

RTOs and ISOs will work with their stakeholders to develop any new proposed rules and 

decline to make this an explicit criterion. 

250. Similarly, the changes requested by PG&E are already addressed in the six 

criteria, as modified above. We note that an explicit requirement to evaluate the effect of 

a rule change on reliability is not needed. We are firmly of the opinion that the changes 

mandated in this Final Rule will increase system reliability by inducing additional 

response by demand- and supply-side resources and that RTO and ISO compliance will 

not result in a decrease in reliability. Second, requiring an explicit accounting of the 

costs of the program will not be included. We do not see the usefulness of this exercise. 

While there will be costs involved, the long-term benefits of maintaining grid reliability 

are evident. 

251. As to when these pricing rules would go into effect, it is when the RTO or ISO has 

an operating reserve shortage. The reliability standards of the North American Electric 

Reliability Corporation, which have been approved by the Commission, or of other 

authorized reliability body, specify system operating reserve requirements, and these 

standards are well known to system operators such as RTOs and ISOs, as well as to the 

many stakeholders who helped develop them. The level of operating reserves required by 

the reliability standards depends on the characteristics of each system and cannot be 
Docket Nos. RM07-19-000 and AD07-7-000 - 141 - 

correctly reduced to a single number that applies to every system, such as seven percent 

of peak load. Further, if we were to repeat the reliability standard definition here in our 

regulations, it would be cumbersome for reliability organizations to improve their 

definition of operating reserve requirements over time without also having to seek a 

change in our regulations. We find that this is the best definition of when these price 

reforms apply; we do not adopt a second, different definition, here, because having two 

definitions of operating reserve shortage would only cause confusion for system 

operators. 

252. We decline to accept all other suggested criteria because they would represent a 

level of burden to the RTO or ISO that would exceed the benefit of doing the analysis. 

253. We find that the criteria proposed in the NOPR, as modified above, are sufficient 

to show whether a region’s proposed changes to its existing market rules meet the 

requirements of this rule, while protecting consumers from market power. 

d. Phase-In of New Rules

254. In the NOPR, the Commission stated that each RTO or ISO may also consider a 

“phase-in” of its specific emergency pricing method over a period of years, giving three 

years as an example. This would serve to introduce customers gradually to pricing 

increases during an emergency and allow them to develop ways to reduce demand and 

avoid higher prices.343

 343 NOPR, FERC Stats & Regs. ¶ 32,628 at P 128. 
Docket Nos. RM07-19-000 and AD07-7-000 - 142 - 

i. Comments

255. Duke Energy states that while it prefers that any shortage pricing program start 

immediately, if a phase-in is deemed worthwhile, this phase-in should not be 

indefinite.344 EEI also states that these rule changes may best be implemented through a 

phase-in, provided that it is not protracted.345 It also notes that it is appropriate for the 

Commission to allow such a phase-in to be linked to key factors such as the deployment 

of advanced metering. Old Dominion supports a phase-in of emergency pricing. 

256. FirstEnergy supports the Commission’s proposed phase-in approach because it can 

allow the Market Monitor to evaluate the market reform, mindful of any unintended 

consequences including the exercise of market power and gaming.346

257. Industrial Consumers recommends that the Commission require a phase-in period 

of at least three to five years, together with benchmarks that measure the ability of 

specific market factors to protect consumers from the exercise of market power at the 

time of shortages. It urges that the shortage price levels only be allowed to increase in 

conjunction with and proportional to four benchmarks: (1) measured and verified amount 

of new net incremental demand response resources entering the market; (2) net 

incremental reductions in congestion, whether through enhancement of generation or 

transmission resources, in the zones where such shortage pricing is implemented; (3) 

 344 Duke Energy at 11. 

345 EEI at 20. 

346 FirstEnergy at 12. 
Docket Nos. RM07-19-000 and AD07-7-000 - 143 - 

sustained increases in the volume of load hedged in long-term forward markets; and (4) 

development of credible forward price curves of power delivered at RTO and ISO hubs 

published in support of the third benchmark that are regularly relied upon by market 

participants.347

ii. Commission Determination

258. The Commission will allow an RTO or ISO to phase in any new pricing rules for a 

period of a few years, provided that this period is not protracted. Any phase-in period 

must be justified as part of the RTO’s or ISO’s overall proposal to change its pricing 

rules. No RTO or ISO is required to use a phase-in period, and we will not adopt by rule 

a requirement that any such phase-in be tied to certain benchmarks as Industrial 

Consumers and EEI propose. However, an RTO or ISO in consultation with its 

stakeholders, may propose to tie the phase-in period to certain benchmarks, and we will 

consider these in the compliance filing. We caution, however, that it should not choose 

to tie implementation to benchmarks that will not be met over a few years. This would 

not be consistent with our requirement that the phase-in period must not be protracted. 

6. Reporting on Remaining Barriers to Comparable Treatment of 

Demand Response Resources

259. In the NOPR, the Commission recognized that further reforms may be necessary 

to eliminate barriers to demand response in the future. The Commission did not wish to 

delay the adoption of the specific reforms proposed in the NOPR while the Commission 

 347 Industrial Consumers at 19. 
Docket Nos. RM07-19-000 and AD07-7-000 - 144 - 

and the industry continue to study and consider other advances in this area. Rather, the 

proposed reforms were to proceed while the Commission and stakeholders studied what 

additional efforts were necessary and developed a record to support further reform. 

260. The Commission directed staff to hold a technical conference to consider the 

following issues for demand response participation in the wholesale markets: (1) whether 

there are barriers to comparable treatment of demand response that have not previously 

been identified, and what they are; (2) potential solutions to eliminate any potential 

barriers to comparable treatment of demand response; (3) appropriate compensation for 

demand response; and (4) the need for and the ability to standardize terms, practices, 

rules and procedures associated with demand response, among other things.348 

261. In the NOPR, the Commission also proposed to require each RTO and ISO to 

assess and report on the barriers to comparable treatment of demand response resources 

that are within the Commission’s jurisdiction, including those listed above. The RTOs 

and ISOs would be required to submit their findings and any proposed solutions, along 

with a timeline for implementation to address barriers, to the Commission within six 

months of the Final Rule’s publication in the Federal Register. The Commission also 

proposed to require the Independent Market Monitor for each RTO or ISO to provide its 

views on this issue to the Commission. To ensure that minority views are adequately 

 348 NOPR. FERC Stats. & Regs. ¶32,628 at P 95. The technical conference was 

held on May 21, 2008. See infra note 12. 
Docket Nos. RM07-19-000 and AD07-7-000 - 145 - 

represented, the Commission proposed to require that the RTO or ISO identify any 

significant minority views in its filing. 

262. The Commission sought comment on the proposed approach to identify and assess 

remaining barriers to comparable treatment of demand response as well as any particular 

issues or areas that should be addressed in the RTO and ISO reports. 

a. Comments

263. A number of commenters indicate their support for the Commission’s intention to 

continue to address barriers to demand response resources, and/or the Commission’s 

proposal to require each RTO and ISO to report on the barriers they currently perceive.349 

Some offer suggestions for how the Commission should proceed toward this goal. 

264. For example, APPA cautions the Commission, as it seeks to remove barriers to 

demand response resources, not to unintentionally endanger existing and planned demand 

response and energy efficiency programs at the retail level.350 EnerNOC is encouraged 

by the Commission’s objective to continue its oversight, to review and approve 

implementation of reforms for demand response programs and to consider future 

reforms.351 However, it believes the Commission’s continued involvement and active 

engagement may be necessary to eliminate barriers to demand response resources. 

 349 E.g., Exelon at 9; Pennsylvania PUC at 12; PG&E at 11; Public Interest 

Organizations at 8; Reliant at 6; and Steel Producers at 6. 

350 APPA at 51. 

351 EnerNOC at 22. 
Docket Nos. RM07-19-000 and AD07-7-000 - 146 - 

265. EEI agrees that the Commission should not delay the adoption of specific reforms 

for demand response while the Commission and industry stakeholders evaluate additional 

reforms in this area. However, EEI suggests that the Commission provide additional 

specification of the parameters of these studies, suggesting that the Commission clarify 

that such studies should not ignore existing work and should be conducted in a costeffective manner. EEI also urges the Commission to have RTOs and ISOs study whether 

demand response is cost-effective and to quantify benefits.352

266. Regional entities report that they are already engaged in some of the issues the 

Commission described. With regard to future demand response reforms, the ISO/RTO 

Council says that it is working to develop standards for incorporating small demand 

response resources into organized markets, and that it is actively engaged with NAESB to 

standardize measurement and verification protocols.353 These efforts, in combination 

with the Commission’s technical conference, in which the ISO/RTO Council participated, 

should benefit future discussions on barriers, pricing, and standardization. The ISO/RTO 

Council looks forward to sharing the results of its standardization initiative. 

267. Midwest ISO supports the Commission’s approach to identifying additional 

demand response barriers and solutions, and states that many issues regarding barriers 

and solutions to demand response resources are already being addressed as part of the 

Midwest ISO’s ongoing emergency demand response and long-term resource adequacy 

 352 EEI at 18. 

353 ISO/RTO Council at 8. 
Docket Nos. RM07-19-000 and AD07-7-000 - 147 - 

proceedings.354 Through the rest of 2008, the Midwest ISO’s Demand Response 

Working Group will facilitate many activities to further identify measures to advance 

demand response resources. 

268. NYISO agrees that this Final Rule should not mark the end of the Commission’s 

efforts in the demand response area and that further improvements and additional 

enhancements should be explored. NYISO has no objection to preparing the post-Final 

Rule report that the NOPR proposes.355

269. SPP notes that it is currently studying what further reforms are necessary to 

eliminate barriers to demand response in its organized markets. This process is done 

through its working groups and task forces as well as participating in groups such as the 

ISO/RTO Council.356

270. The California PUC believes that two important areas that could be improved are 

the evaluation of the cost-effectiveness of demand response and how it impacts load. The 

California PUC is working with stakeholders on both of these issues. The California 

PUC would also like to see more effective load-shifting and the technology that allows 

for that to be encouraged to a greater degree.357

 354 Midwest ISO at 14-15. 

355 NYISO at 3. 

356 SPP at 6. 

357 California PUC at 20. 
Docket Nos. RM07-19-000 and AD07-7-000 - 148 - 

271. Old Dominion supports the Commission’s proposal to continue discussions on 

demand response through RTO and ISO studies and suggests that RTOs and ISOs be 

required to identify all minority views and not just “significant minority views” as 

currently required by the NOPR. Old Dominion sees lack of telemetry, high 

implementation costs, institutional barriers related to cost recovery, insufficiently detailed 

business rules, and demand response gaming as impediments to demand response that 

should be discussed further.358

272. Old Dominion also suggests that each RTO and ISO should be directed to work 

with its stakeholders to develop by a specific date a prioritized list of barriers to demand 

response and a timeline for developing solutions to the same; that demand response 

should be considered in the transmission planning process in accordance with 

engineering-based transmission planning principles; and that implementation of demand 

response should be evolutionary in accordance with the sufficiency and certainty of 

business rules and availability of necessary measurement and verification infrastructure. 

Similarly, California DWR asks the Commission to require RTOs and ISOs to provide a 

listing of barriers identified by market participants, state or local regulators, the RTO or 

ISO market monitor, and the RTO or ISO itself; further, the RTOs and ISOs would 

provide information on their response to each barrier and let the Commission know if 

additional action is needed.359

 358 Old Dominion at 16-19. 

359 California DWR at 37. 
Docket Nos. RM07-19-000 and AD07-7-000 - 149 - 

273. Public Interest Organizations recommend that the Commission schedule a 

technical conference in each region to address both general and region-specific 

barriers.360 Public Interest Organizations also recommend that RTOs and ISOs be 

required to: (1) assess the potential of other demand-side resources in their control areas, 

including demand response, energy efficiency, and environmentally benign and efficient 

behind-the-meter distributed generation; (2) analyze and quantify all local and regional 

benefits as well as costs and risks of demand side resources available to address grid 

needs; and (3) assess and report on the longer-term impacts of demand resource 

participation on wholesale price levels and volatility, grid congestion, and system 

reliability. 

b. Commission Determination

274. The Commission adopts the requirement that each RTO or ISO assess and report 

on any remaining barriers to comparable treatment of demand response resources that are 

within the Commission’s jurisdiction and to submit its findings and any proposed 

solutions, along with a timeline for implementation, to the Commission within six months 

of the Final Rule’s publication in the Federal Register. We further adopt the requirement 

that each RTO’s or ISO’s Independent Market Monitor must submit a report describing 

its views on these issues to the Commission. To ensure that minority views are 

adequately represented, the Commission requires that the RTO or ISO, in its report, 

 360 Public Interest Organizations at 8. 
Docket Nos. RM07-19-000 and AD07-7-000 - 150 - 

identify any significant minority views; this does not, however, require reporting every 

opinion of every individual stakeholder. 

275. The Commission appreciates the many thoughtful comments received in response 

to this proposal. RTOs and ISOs have a duty to remove unreasonable barriers to treating 

demand response resources comparably with other resources and the required report will 

help RTOs, ISOs, and the Commission to identify and address such barriers. The report 

should identify all known barriers, and provide an in-depth analysis of those that are 

practical to analyze in the compliance time frame given and a time frame for analyzing 

the remainder. As commenters have noted, this should include (but is not limited to) 

technical requirements as well as performance verification limitations. It need not 

contain, however, a formal cost-benefit analysis of each barrier and a proposal to 

overcome it. Public Interest Organizations suggest that RTOs and ISOs might hold 

regional conferences on this topic, and while we agree this may have merit, we leave to 

each region the means of developing its report. 

276. Energy efficiency and distributed generation are valuable resources, as 

commenters point out; however, the scope of this rule is limited to removing barriers to 

comparable treatment of demand response resources in the organized markets. Hence, 

we will not require RTOs and ISOs to study these resources in the report we require. 

Nevertheless, nothing here precludes RTOs and ISOs from analyzing barriers to energy 

efficiency measures and distributed generation in their markets and proposing revisions 

to their tariffs that integrate these measures into their markets. 
Docket Nos. RM07-19-000 and AD07-7-000 - 151 - 

B. Long-Term Power Contracting in Organized Markets

277. In this section of the Final Rule, the Commission establishes a requirement that 

RTOs and ISOs dedicate a portion of their web sites for market participants to post offers 

to buy or sell electric energy on a long-term basis. This requirement is designed to 

improve transparency in the contracting process to encourage long-term contracting for 

electric power. The Commission requires each RTO or ISO to submit a compliance 

filing describing actions the RTO or ISO has taken, or plans to take, to comply with the 

requirement and providing information on the bulletin board the RTO or ISO has chosen 

to implement. 

1. Background

278. Long-term power contracts are an important element of a functioning electric 

power market. Forward power contracting allows buyers and sellers to hedge against the 

risk that prices may fluctuate in the future. Both buyers and sellers should be able to 

create portfolios of short-, intermediate-, and long-term power supplies to manage risk 

and meet customer demand. Long-term contracts can also improve price stability, 

mitigate the risk of market power abuse, and provide a platform for investment in new 

generation and transmission. 

279. As the Commission noted in the NOPR, having an organized market in a region 

should facilitate long-term contracting by eliminating pancaked rates for long-distance 

power sales, eliminating loop flow problems within its footprint, and ensuring reliable 
Docket Nos. RM07-19-000 and AD07-7-000 - 152 - 

transmission operation over a large area.361 RTO and ISO transmission services also 

expand the size of the markets available to buyers and sellers of long-term power 

contracts, and provide independent and unified transmission scheduling and operation 

services over a large area. 

280. The Commission has already taken action in other areas to facilitate long-term 

contracting. In Order No. 681, the Commission adopted a Final Rule on long-term 

transmission rights for organized market regions designed to assure availability of longterm transmission at a predictable cost.362 The Commission then adopted transmission 

planning reforms in Order No. 890 to provide an open and transparent process for 

wholesale entities and transmission providers to plan for the long-term needs of their 

customers. Interconnection rules for large, small and wind generators in Order Nos. 

2003, 2006 and 661 have provided a uniform and transparent interconnection process and 

provided for interconnection with network integration service to facilitate long-term 

reliance on new generation.363 The Commission has also reformed capacity markets in 

 361 NOPR, FERC Stats. & Regs. ¶ 32,628 at P 130. 

362 Long-Term Firm Transmission Rights in Organized Electricity Markets, Order 

No. 681, FERC Stats. & Regs. ¶ 31,226 (2006), order on reh’g, Order No. 681-A, 

117 FERC ¶ 61,201 (2006). 

363 Standardization of Generator Interconnection Agreements and Procedures, 

Order No. 2003, FERC Stats. & Regs. ¶ 31,146 (2003), order on reh’g, Order No. 2003-

A, FERC Stats. & Regs. ¶ 31,160, order on reh’g, Order No. 2003-B, FERC Stats. & 

Regs. ¶ 31,171 (2004), order on reh’g, Order No. 2003-C, FERC Stats. & Regs. ¶ 31,190 

(2005), aff'd sub nom. Nat'l Ass'n of Regulatory Util. Comm'rs v. FERC, 475 F.3d 1277 

(D.C. Cir. 2007); Standardization of Small Generator Interconnection Agreements and 

Procedures, Order No. 2006, FERC Stats. & Regs. ¶ 31,180, order on reh’g, Order No. 

 (continued...) 
Docket Nos. RM07-19-000 and AD07-7-000 - 153 - 

several regions to shift reliance from short-term purchases to forward markets held 

sufficiently in advance of delivery (e.g., three years) to be more consistent with the time 

necessary to construct new generation.364

281. The Commission did not find that there is a fundamental problem with long-term 

contracting for electric power, either inside or outside of organized markets. The interest 

among buyers and sellers in engaging in long-term contracting fluctuates depending upon 

the balance of resources and demand in the market for power. Interest among buyers for 

long-term arrangements was low when excess generation was readily available. 

Although demand for long-term contracting by buyers has increased as reserve margins 

have shrunk, buyers are still able to enter into long-term contracts. These contracts may 

be at higher prices than in the past, but this is a result of market factors, such as changes 

in fuel prices and shifting supply and demand. Finding no fundamental problem 

preventing parties from contracting on a long-term basis, the Commission proposed to 

limit its action in this proceeding to improving transparency in long-term contracting in 

organized markets. 

 

2006-A, FERC Stats. & Regs. ¶ 31,196 (2005), order granting clarification, Order No. 

2006-B, FERC Stats. & Regs. ¶ 31,221 (2006), appeal pending sub nom. Consolidated 

Edison Co. of New York, Inc., et al. v. FERC Docket No. 06-1018, et al; Interconnection 

for Wind Energy, Order No. 661, FERC Stats. & Regs. ¶ 31,186, order on reh’g, Order 

No. 661-A, FERC Stats. & Regs. ¶ 31,198 (2005). 

364 Devon Power, LLC, 115 FERC ¶ 61,340, order on reh’g, 117 FERC ¶ 61,133 

(2006), aff’d in part and rev’d in part sub nom. Maine Pub. Utils. Comm’n v. FERC, 

520 F.3d 464 (D.C. 2008); PJM Interconnection, L.L.C., 117 FERC ¶ 61,331 (2006). 
Docket Nos. RM07-19-000 and AD07-7-000 - 154 - 

282. In the NOPR, the Commission stated that further transparency in long-term 

electric energy markets would facilitate efforts by both sellers and buyers to include longterm contracts in their energy portfolios. This is especially true for market participants 

that may not be aware of the full range of contract options available to them, including 

the full range of potential contract counterparties. While the market has the most 

important role to play in disseminating information, an RTO or ISO can also promote 

greater transparency and liquidity in long-term power markets,365 and thus help reduce 

possible over-reliance on spot markets. In the NOPR, the Commission proposed that 

regional organizations play a supporting role in encouraging voluntary contracting by 

providing an online forum in which potential buyers and sellers may exchange 

information.366

2. Commission Proposal

283. In the NOPR, the Commission proposed to require that RTOs and ISOs dedicate a 

portion of their web sites for market participants to post offers to buy or sell electric 

energy on a long-term basis.367 The Commission stated that the proposal for an RTO or 

ISO web site “bulletin board” for posting long-term offers to sell or buy electric energy is 

designed to facilitate the long-term contracting process by increasing the transparency of 

the availability of potential sellers and buyers for market participants. The Commission 

 365 Transcript of Conference at 117, Conference on Competition in Wholesale 

Power Markets, Docket No. AD07-7-000 (May 8, 2007). 

366 NOPR, FERC Stats. & Regs. ¶ 32,628 at P 137. 

367 Id. P 155. 
Docket Nos. RM07-19-000 and AD07-7-000 - 155 - 

did not propose to mandate the specific type of bulletin board that each RTO and ISO 

must post, but proposed to require each to work with its stakeholders to design a solution 

that works for its market participants.368 The Commission also encouraged RTOs and 

ISOs to work with stakeholders to facilitate long-term power contracting. 

284. The Commission proposed to require RTOs and ISOs to make a compliance filing 

within six months of the date of publication of the Final Rule in the Federal Register. 

This filing should explain the actions the RTO or ISO has taken or plans to take to 

comply with the long-term contracts bulletin board requirement and provide information 

on the bulletin board the RTO or ISO has chosen to implement.369 

285. The Commission also sought public comment on a number of questions related to 

its proposal, including comment on minimum necessary features and processes for the 

webpage and the proposal that the RTO or ISO should not be responsible for the content 

of the offers on its bulletin board. Further, the Commission solicited comment on 

provisions for the disclaimer of liability by the RTO or ISO and by market participants.370

 368 Id. P 156-57. 

369 Id. P 158. 

370 Id. P 159. 
Docket Nos. RM07-19-000 and AD07-7-000 - 156 - 

3. Comments

286. A majority of commenters either support371 or do not object372 to the 

Commission’s proposal to require RTOs and ISOs to implement bulletin boards to 

facilitate long-term power contracts. Most commenters note that the Commission should 

not impose conditions on the format of the bulletin board, but should instead leave the 

creation to RTOs and ISOs in conjunction with their stakeholders.373 Some commenters 

also state that the Commission should act to ensure that RTOs or ISOs should not be held 

liable for postings on their bulletin boards.374 For instance, NYISO states that the 

Commission should allow posted disclaimers against liability by the RTOs on their 

bulletin board web sites. Midwest ISO also requests that the Commission provide 

assurance that RTOs and ISOs will not be exposed to antitrust liability for providing a 

 371 See, e.g., APPA at 72; DC Energy at 8; EEI at 4; Exelon at 15; LPPC at 4; 

Midwest ISO at 18; NEPOOL at 19-20; New York PSC at 4; NIPSCO at 15; NRECA at 

47; NSTAR at 5; NYISO at 11; OMS at 7; Pennsylvania PUC at 16; Steel Producers at 

10; and Xcel at 11. NIPSCO notes that its support is contingent on the bulletin boards 

having common elements or generic features across all organized markets, and the boards 

not burdening the RTO. 

372 See, e.g., Ameren at 29-30; EPSA at 12; FirstEnergy at 12; Indianapolis P&L at 

4; Industrial Coalitions at 32-35; Industrial Customers at 21; North Carolina Electric 

Membership at 13-15; Ohio PUC at 16; Old Dominion at 19-20; OMS at 7-8; PJM at 2; 

and TAPS at 3. 

373 See, e.g., Ameren at 30; APPA at 72; CAISO at 19; DC Energy at 9; EEI at 20; 

EPSA at 12; Exelon at 15; NEPOOL Participants at 19-20; North Carolina Electric 

Membership at 13-15; NYISO at 12; Old Dominion at 19; PJM at 2; and Xcel at 11. 

374 See, e.g., Ameren at 30; CAISO at 19; Exelon at 15; Midwest ISO at 18; 

NRECA at 48; NYISO at 12; Ohio PUC at 16; Reliant at 11; and SPP at 7. 
Docket Nos. RM07-19-000 and AD07-7-000 - 157 - 

contracting forum. Finally, commenters generally believe that the cost of a bulletin board 

will be low for RTOs and ISOs.375

287. Those commenters who do not support the Commission’s proposal generally argue 

that a bulletin board would be an unnecessary requirement. Both CAISO and California 

Munis state that CAISO is busy with other projects, and that a bulletin board would be 

low on the list of necessary items.376 CAISO is concerned over the proposed deadline for 

implementation, and argues that any deadline should be after the launch of its MRTU. It 

also believes that regions should be allowed to be flexible on whether to develop bulletin 

boards and how many features the board should have. California PUC agrees that a 

federal requirement is unnecessary, and that the Commission should authorize, rather 

than require, action on bulletin boards. SPP also advocates that the Commission should 

make its proposal a voluntary one, rather than a regulatory requirement. Some 

commenters, such as EPSA, NIPSCO, Ohio PUC, Steel Producers and North Carolina 

Electric Membership, who do not object to the proposal, indicate that they do not believe 

that bulletin boards will have a significant effect on long-term contracting. FirstEnergy 

indicates that, although it does not object to the proposal, it believes that sufficient 

information on the market is already provided by private companies and thus RTOs do 

not need to be further involved. Reliant states that bulletin boards would not resolve any 

 375 See, e.g., Ameren at 30; CAISO at 19; EEI at 20; Midwest ISO at 18; and PJM 

at 2. 

376 CAISO at 19; California Munis at 18. 
Docket Nos. RM07-19-000 and AD07-7-000 - 158 - 

of the current impediments to long-term contracts, as there are already sufficient 

mechanisms in the market to provide information for buyers and sellers. 

288. Commenters’ suggestions for implementing the bulletin board requirement 

include: (1) a requirement that posts should not be viewed as binding offers but rather as 

voluntary postings;377 (2) a suggestion that price information not be required in postings 

to the bulletin board;378 (3) a requirement that any significant costs of the bulletin board 

should be borne by its users;379 (4) an expansion of the data posted to include percentage 

and volume of bilaterally contracted energy;380 (5) an expansion of the bulletin board to 

cover other products such as ancillary services;381 (6) a requirement that RTOs and ISOs 

collect and disseminate information on the usefulness of bulletin boards;382 (7) a 

requirement that bulletin boards provide common elements or generic features across all 

organized markets; and (8) a mandated cost analysis of the bulletin board by the 

RTO/ISO.383

 377 Ameren at 30-31. 

378 Xcel at 11-12. 

379 CAISO at 18-20; EEI at 21. 

380 Industrial Coalitions at 33-35. 

381 NEPOOL Participants at 18-21. 

382 Pennsylvania PUC at 16. 

383 Old Dominion at 19-20. 
Docket Nos. RM07-19-000 and AD07-7-000 - 159 - 

289. Midwest ISO states that it already has an early version of a portal in place on its 

web site, and that it would involve minimal costs to create a bulletin board for long-term 

contracts. Midwest ISO recommends that, as an intermediate measure prior to the 

implementation of a web portal, contracting parties provide essential terms – including 

price, quantity, term, and receipt and delivery points – to the RTO or ISO and fill out a 

form indicating the data they wish to be kept confidential.384

290. NEPOOL Participants raises some legal and other issues for the Commission to 

consider when developing its bulletin board requirement. These include: (1) ensuring 

that postings are not considered binding offers under the Uniform Commercial Code; (2) 

not allowing the board to substitute for regulated markets; and (3) ensuring that the same 

antitrust and market manipulation rules that apply to market behavior also apply to 

activity on the bulletin board.385

291. NSTAR states that it is concerned that data from the bulletin board containing 

prices for long-term power could influence market prices. Accordingly, it asks the 

Commission to consider additional requirements to ensure that information posted on the 

boards is from a representative cross-section of market participants, to reduce the impact 

of the bulletin board on market prices.386

 384 Midwest ISO at 19. 

385 NEPOOL Participants at 20. 

386 NSTAR at 5-6. 
Docket Nos. RM07-19-000 and AD07-7-000 - 160 - 

292. Industrial Customers state that the Commission should define “long-term” as 

substantially more than one year and consistent with building cycles of new or expanded 

production capacity. They argue that any entity making construction decisions on new 

facilities needs knowledge of prices going forward to make investment decisions. 

293. Many commenters argue that the Commission did not address in its proposed 

regulations the actual causes behind the lack of long-term contracts in the market. 

Several commenters point to the structure of markets within the RTO system, which they 

assert causes an over-reliance on spot markets and a lack of long-term contracts. They 

say this structure includes LMP pricing, which provides a disincentive for producers to 

contract for lower prices on a long-term basis. For instance, APPA points to studies 

including one performed by Synapse Energy Economics, Inc., indicating that there are 

structural barriers to long-term contracting in the organized markets. Other commenters 

point to the need for stability of market rules and uncertainty about climate change 

policies as key factors in keeping parties from contracting on a long-term basis.387 

Reliant indicates that the issue is actually a difference in perceptions between buyers and 

sellers about the appropriate price of energy and the allocation of risk between the buyers 

and sellers. NRECA points to several other issues that affect long-term contracting in 

organized markets, including price volatility, price risk, delivery risk and resource 

availability. Ohio PUC echoes some of these concerns, noting that risks with recovering 

capital costs are preventing new generation from being built in states with retail access, 

 387 See, e.g., SoCal Edison-SDG&E at 4; EPSA at 11-12. 
Docket Nos. RM07-19-000 and AD07-7-000 - 161 - 

and that unpredictable congestion charges and uncertainty surrounding the working of 

RTO markets are also hurting long-term contracting. 

294. Commenters suggest several actions that the Commission should take to remedy 

these broader concerns. Commenters, including NRECA, Industrial Coalitions and Blue 

Ridge, ask the Commission to do its own investigation of the bilateral contracting process 

and over-reliance on the spot markets. North Carolina Electric Membership notes that a 

requirement of “full support” from stakeholders for more complex RTO or ISO market 

design changes may increase the stability and predictability to these markets, which may 

facilitate longer term contracting. Constellation states that the Commission should 

promote rules to encourage contracting across seams and take measures to provide 

sufficient transparency, information and regulatory certainty to manage transactional risk. 

Cogeneration Parties argue that the Commission should take action to improve price 

transparency in organized markets, and assist in the creation of standard products and 

contracting terms for long-term contracting. SoCal Edison-SDG&E argue that local 

measures to improve regulatory stability would do more to support long-term contracting 

than a Commission rulemaking. They point to the California PUC proceeding to develop 

long-term resource adequacy requirements as one such local measure, and argue that the 

Commission should focus on the merits of individual RTO or ISO proposals rather than a 

nationwide rulemaking. Finally, TAPS notes that an important way to facilitate longterm contracts is to ensure that load-serving entities can access necessary transmission 

resources. However, TAPS is concerned by recent orders indicating that the Commission 
Docket Nos. RM07-19-000 and AD07-7-000 - 162 - 

may relieve RTOs of certain responsibilities they have under Order No. 681388 to plan for 

resource adequacy and maintain simultaneous feasibility of financial rights. It argues that 

if the Commission is serious about facilitating long-term contracts, it should require 

RTOs and ISOs to live up to the letter and spirit of Order No. 681. 

295. Several commenters call on the Commission to hold a technical conference and 

require a stakeholder process to address the lack of certain financial hedging instruments 

so as to reduce price uncertainty for long-term contracts. For instance, both California 

Munis and SMUD argue that buyers in CAISO lack options-type instruments for hedging 

LMP congestion costs and lack a means to hedge against the cost of marginal losses. 

Providing these hedges, they argue, would encourage long term contracting. 

296. Commenters raise a variety of other issues related to long-term contracting. 

Midwest Energy states that it is concerned about the impact of a Day-2 market on longterm contracts, and appreciates that the Commission is not imposing Day-2 market 

structures on all RTOs and ISOs. 

297. California PUC notes that it is presently addressing long-term contracting within 

its procurement proceedings. For instance, under the California PUC’s Resource 

Adequacy program, all California PUC jurisdictional LSEs are required to procure 

necessary capacity on a year-ahead basis. Additionally, California PUC requires LSEs to 

identify longer-term needs and procure energy necessary to meet those needs through a 

 388 Long-Term Firm Transmission Rights in Organized Electricity Markets, Order 

No. 681, FERC Stats. & Regs. ¶ 31,226 (2006), order on reh'g, Order No. 681-A, 

117 FERC ¶ 61,201 (2006). 
Docket Nos. RM07-19-000 and AD07-7-000 - 163 - 

request for offer process that includes both long and short-term contracts. California 

PUC questions the Commission’s legal basis for intervening in long-term contracting, 

stating that the NOPR does not explain the statutory authority for the Commission’s 

proposed involvement in long-term energy supply contracts between generators and 

LSEs. It notes that FPA section 215 does not authorize the Commission to set or enforce 

compliance with standards for resource adequacy, and that EPAct 2005 “expressly retains 

state authority to assure the reliability of the energy supply within their jurisdictions.”389 

It seeks assurance that the Commission does not intend to exercise jurisdiction over the 

wholesale energy market as a method of indirectly modifying California’s reliability 

processes. 

298. Both New York PSC and NARUC state that the Commission should not attempt to 

standardize long-term contracts. NARUC argues that standardization would hurt state 

policy objectives such as integrated resource planning, renewable portfolio standards and 

resource adequacy requirements. New York PSC notes that any standardized forward 

products should be developed through the RTO or ISO stakeholder process. 

299. PJM notes that it held a stakeholder forum in January 2008 to discuss greater 

opportunities for long-term contracting in PJM. This forum resulted in identification of 

areas for future action, which included: (1) education of policy makers and the public on 

the need for new infrastructure; (2) improved coordination of various agency and 

regulatory decision makers on market issues; (3) predictability and stability in regulatory 

 389 California PUC at 28 (citing 16 U.S.C. 824o(i)). 
Docket Nos. RM07-19-000 and AD07-7-000 - 164 - 

rules; (4) improvements in siting for transmission and generation; (5) ways of steering 

revenue to increase the amount of new generation; (6) more effective demand response 

programs to increase market elasticity and reduce potential for exercise of market power; 

(7) a portfolio of purchases to vary prices and terms for state-sanctioned auctions; (8) 

further examination of existing market models such as the AF&PA proposal; and (9) 

additional credit support for parties interested in long-term contracting, through methods 

such as syndication of credit risk and government guarantees.390

300. Finally, APPA notes that although it appreciates the effort that PJM put into 

holding its long-term contracting forums, APPA understands that no concrete proposals 

for improving long-term contracting have emerged as a result of the forums. 

Accordingly, APPA cannot endorse the idea of similar efforts by other RTOs as 

suggested by the Commission in the NOPR, given the scarce resources of RTOs and 

market participants. Instead, APPA supports preparation of an in-depth analysis of longterm contracting practices for each RTO region by the RTO’s MMU, given the MMU’s 

knowledge of conditions “on the ground.” This analysis should consider impediments to 

long-term contracting and measures that could be taken to support long-term contracts of 

sufficient length to support the building of new generation. 

4. Commission Determination

301. We will require each RTO and ISO to dedicate a portion of its web site for market 

participants to post offers to buy or sell power on a long-term basis. The Commission 

 390 PJM at 3-4. 
Docket Nos. RM07-19-000 and AD07-7-000 - 165 - 

defines “long-term” as one year or more for the purposes of this rule, but RTOs and ISOs 

may include offers for contracts of less than a year on their web sites as well. The web 

site should allow both buyers and sellers to post and read offers for long-term power 

transactions. A majority of commenters support this proposal, and we conclude that 

greater transparency from a bulletin board for long-term power sales will benefit longterm contracting. 

302. We are convinced by the comments that the costs involved for creation and 

upkeep of the bulletin board are likely to be minimal and are justified by the increased 

transparency for potential sellers and buyers, and should thus be recovered similarly to 

other web site costs. A few commenters suggest that bulletin board costs should be borne 

by its users. If an RTO or ISO in consultation with its stakeholders believes that costs of 

the bulletin board will be significant, it may explain in its compliance filing how it plans 

to recover the costs, including whether it plans to charge users of the bulletin board. 

303. The Commission is not mandating any specific form for the web site beyond the 

requirements above. We will instead leave the implementation to RTOs and ISOs and 

their stakeholders. This discretion includes decisions over the type and amount of data to 

be posted by participants, whether participants must include a proposed price in their 

posting, as well as password and security requirements. Commenters who have specific 

suggestions about the form and content of the web site bulletin boards, or concerns over 

cost issues, should raise these suggestions with their RTOs or ISOs through the 

stakeholder process. The compliance filing of each RTO or ISO will provide an 

opportunity for interested persons to comment to the Commission on each RTO’s and 
Docket Nos. RM07-19-000 and AD07-7-000 - 166 - 

ISO’s method of compliance, such as the legal and other concerns raised by NEPOOL 

Participants and others. The Commission does not find it necessary to make a generic 

determination about these concerns. 

304. The Commission agrees with commenters that RTOs and ISOs should not be held 

liable for the postings of contracting parties.391 Significant liability protection for 

message board operators is already provided under federal law by the safe harbor 

provisions of the Communications Decency Act.392 We anticipate that these provisions 

will apply to RTOs and ISOs. Consistent with comments received, however, we 

encourage RTOs and ISOs to post a disclaimer on their web sites indicating that they are 

not responsible for the content posted by users, and outlining the terms and conditions 

under which users may post offers to buy or sell under long-term agreements. 

305. In response to comments from NSTAR, the Commission is not persuaded to 

forego the advantages of posting long-term contract term proposals just because an entity 

might attempt to use the bulletin board inappropriately. Further, we see no reason to 

mandate in this proceeding specific limits on types of posting on RTO or ISO web sites. 

 391 The Commission does not see why having such a bulletin board should 

necessarily expose an RTO or ISO to antitrust liability, as suggested by Midwest ISO. 

However, the Commission suggests that RTOs and ISOs explain any such concerns in 

their compliance filings. 

392 47 U.S.C. 230(c)(1) (“No provider or user of an interactive computer service 

shall be treated as the publisher or speaker of any information provided by another 

information content provider.”). See, e.g., Universal Commun. Sys. v. Lycos, Inc., 

478 F.3d 413 (1st Cir. 2007) (dismissing a suit against a content provider for liability for 

posts on a community message board based on the safe harbor provisions of the 

Communications Decency Act). 
Docket Nos. RM07-19-000 and AD07-7-000 - 167 - 

However, any attempt by posters to use this new feature to manipulate the market price or 

market price indices will be subject to Commission penalty or referral to other agencies 

having jurisdiction.393

306. In response to the concerns raised by California PUC, New York PSC and 

NARUC, the Commission notes that it is not taking any action at this time to standardize 

long-term contracts, nor does the Commission intend this bulletin board posting 

requirement to be a reliability standard, to set a resource adequacy requirement, or to 

infringe on state regulatory jurisdiction. 

307. We anticipate that this requirement will enhance transparency and help foster 

long-term contracting without standardizing RTO and ISO approaches or intruding 

unduly into matters more appropriate for markets and the private sector. The comments 

provide strong support for the bulletin board proposal, and do not persuade us that there 

is any reason to delay implementation of this requirement, despite CAISO’s request that 

we postpone it until after MRTU is complete. Some of the other requirements 

commenters propose would require more standardization and set requirements that are 

better left to the free market and to the private sector. We do not wish to delay or 

undermine this process by imposing too many requirements. Therefore, the Commission 

will not require in this rulemaking other actions related to long-term contracting 

recommended by some commenters. 

 393 See Price Discovery in Natural Gas and Electric Markets, 104 FERC ¶ 61,121, 

at P 38 (2003).
Docket Nos. RM07-19-000 and AD07-7-000 - 168 - 

308. As discussed in the NOPR, many of the broader issues commenters raise herein 

regarding the structure and functionality of organized markets are beyond the scope of 

this proceeding and would require further development to be ripe for inclusion in a 

rulemaking.394 The Commission further explored many of the issues during the recent 

technical conference held to discuss the proposals of American Forest and Portland 

Cement Association, et al.395 The Commission continues to review the information it 

received at the technical conference for possible action. 

309. RTOs and ISOs are required to make a compliance filing within six months of the 

date of publication of this rule in the Federal Register. The filing should explain the 

actions the RTO or ISO has taken or plans to take to comply with the long-term contracts 

bulletin board requirement and provide information on the bulletin board the RTO or ISO 

has chosen to implement. The Commission appreciates concerns of commenters that 

RTOs and ISOs, such as CAISO, have market reforms in progress, and these entities may 

take into account the timetable of reforms in progress when developing their compliance 

plans. We find that the compliance period of six months is an adequate time to make any 

necessary adjustments to planned reforms and explain them in the compliance filings. 

 394 NOPR, FERC Stats. & Regs. ¶ 32,628 at P 153, 161. 

395 Supplemental Notice of Technical Conference, Capacity Markets in Regions 

with Organized Electric Markets, Docket No. AD08-4-000 (April 25, 2008). 
Docket Nos. RM07-19-000 and AD07-7-000 - 169 - 

C. Market-Monitoring Policies

310. In this section of the Final Rule, the Commission makes reforms to enhance the 

market monitoring function and thereby improve the performance and transparency of 

organized RTO and ISO markets. The two principal areas addressed are the 

independence and functions of the MMU, and information sharing. The Final Rule 

requires tariff provisions that will remove the MMU from the direct supervision of RTO 

or ISO management, and requires, in most instances, that the MMU report directly to the 

RTO or ISO board of directors. 

311. The Final Rule also imposes obligations on the RTOs and ISOs to provide the 

MMU with adequate tools with which to carry out its duties. The Final Rule broadens 

the reporting duties of the MMU, clarifies that it is to refer to Commission staff any 

instances of misconduct by the RTO or ISO, as well as by a market participant, and 

expands the MMU’s referral obligations to include perceived market design flaws as well 

as instances of tariff or rule violations. 

312. In the area of mitigation, the Final Rule separates the duties of internal and 

external MMUs in the case of RTOs and ISOs that employ a hybrid structure, and 

provides that for non-hybrid MMUs, mitigation by the MMU should center on 

retrospective mitigation and the calculation of inputs required for the RTO or ISO to 

conduct prospective mitigation. Given the critical nature of MMU duties, the Final Rule 

requires RTOs and ISOs to include in their tariffs ethical standards for their MMUs. The 

Final Rule also requires RTOs and ISOs to consolidate all of their MMU provisions into 

one section of their tariffs.
Docket Nos. RM07-19-000 and AD07-7-000 - 170 - 

313. In the area of information sharing, the Final Rule expands the category of 

recipients for the information gathered by the MMU, and broadens MMU reporting 

requirements. It also expands the abilities of state commissions to obtain additional and 

more tailored information from MMUs, while preserving confidentiality protections. The 

Final Rule also reduces the lag time for the release of offer and bid data. 

1. Background

314. Since the inception of organized energy markets, the Commission has required 

RTOs and ISOs to employ a market monitoring function. MMUs have consistently 

played a vital role in reporting on the state of the markets and ferreting out wrongdoing 

by market participants. In May of 2005, the Commission issued a Policy Statement on 

Market Monitoring Units,396 which set forth the tasks MMUs were expected to perform, 

and established a procedure for MMU referral of suspected violations to Commission 

staff. 

315. Concerns raised by interested entities in the context of individual RTOs and ISOs 

led the Commission to undertake a generic examination of MMUs at a technical 

conference held on April 5, 2007.397 At that conference, the issues receiving the bulk of 

the attention centered on the perceived need for, and suggested methods of achieving, 

independence on the part of MMUs so they can perform their assigned functions, and the 

 396 Market Monitoring Units in Regional Transmission Organizations and 

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

397 Notice and Agenda for the Conference, Review of Market Monitoring Policies, 

Docket No. AD07-8-000 (Mar. 30, 2007). 
Docket Nos. RM07-19-000 and AD07-7-000 - 171 - 

content and proper recipients of the MMUs’ market data and analysis. These issues 

accorded with the Commission’s perception of the areas within the market monitoring 

function that needed review and strengthening. 

316. In the ANOPR and the NOPR, the Commission proposed numerous reforms 

designed to strengthen MMU independence and broaden information sharing by the 

MMUs. Many of these proposed reforms have been carried forward to this Final Rule, 

while others have been modified or, in a few cases, eliminated, based on the comments 

received from interested entities. The resulting reforms set forth in the Final Rule 

provide the MMUs with enhanced ability to monitor the markets and provide interested 

entities with the ability to receive additional market information, thereby improving 

market performance and transparency. 

2. Independence and Function

317. In the NOPR, the Commission acknowledged the importance of MMU 

independence, and stated that there are several means by which to balance independence 

and accountability. The Commission proposed a balanced and flexible approach that 

included oversight protection, tariff safeguards and tools, the elimination of conflicts of 

interest, and certain changes in the functions MMUs are expected to perform. The 

Commission solicited comments on the proposed changes. 

a. Structure and Tools

i. Commission Proposal

318. The Commission proposed that each RTO and ISO decide for itself, through its 

appropriate stakeholder process, whether it will have an external, internal or hybrid 
Docket Nos. RM07-19-000 and AD07-7-000 - 172 - 

MMU structure. The Commission declined to remove MMUs from oversight by their 

RTOs and ISOs, as the MMU’s principal duties involve monitoring RTO and ISO 

markets and advising the RTO or ISO on market performance. The Commission noted 

that the fact that MMUs also have reporting obligations to outside parties does not change 

their relationship with the RTOs and ISOs, which are, by Commission policy, required to 

maintain a market monitoring function. 

319. The Commission further proposed that each RTO or ISO include in its tariff a 

provision imposing upon itself the obligation to provide its MMU with access to market 

data, resources, and personnel sufficient to enable the MMU to carry out its functions. 

The Commission noted that the RTO or ISO should, in addition, be mindful of these 

obligations in developing its market monitoring budget. Furthermore, to ensure 

independence of the MMU and its analyses, the RTO or ISO tariff should specifically 

provide that the MMU shall have access to the RTO’s or ISO’s database of market 

information. The tariff should also specify that any data created by the MMUs, including 

reconfiguring of the RTO or ISO data, be kept within the MMU’s exclusive control. 

ii. Comments

320. Constellation states the Commission’s proposals are on the right track.398

Dominion Resources and EPSA agree.399 Potomac Economics states that the 

Commission’s proposals appear generally to be consistent with the nature of the existing 

 398 Constellation at 16. 

399 Dominion Resources at 8; EPSA at 12-13. 
Docket Nos. RM07-19-000 and AD07-7-000 - 173 - 

relationship between Potomac Economics and the Midwest ISO, which allows Potomac 

Economics sufficient independence to monitor both the market participants and the 

market operator. Further, Potomac Economics, the Midwest ISO and state regulators all 

see the current structure as providing needed independence while ensuring 

responsiveness to regional needs.400

321. Most commenters agree that the Commission should allow each RTO or ISO to 

determine its own structural relationship with its MMU through its stakeholder 

process.401 

322. PG&E endorses the use of hybrid MMU structures (internal MMU reporting to 

RTO or ISO management and external MMU reporting to the RTO or ISO board), but 

emphasizes the RTO or ISO must meet the following conditions: (1) both MMUs must 

have access to all data and the ability to request data and information from market 

participants if needed to perform market analysis functions; (2) both MMUs should 

cooperate in assessing any issues regarding the markets, including sharing identification 

of market problems developed by either MMU, and sharing complaints or requests for 

investigation raised by any market participant to either MMU; and (3) both MMUs must 

 400 Potomac Economics at 7-8. 

401 Ameren, California PUC, EEI, EPSA, FirstEnergy, and North Carolina Electric 

Membership. 
Docket Nos. RM07-19-000 and AD07-7-000 - 174 - 

have adequate resources and authority to refer matters to the Commission and its Office 

of Enforcement.402

323. Industrial Consumers believe the Commission should mandate the hybrid structure 

for all RTOs or ISOs, reasoning that the external MMU, if not dependent for its main 

salary or contract on services performed for the RTO or ISO, is presumed to be 

independent. It cites the California ISO’s Market Surveillance Committee as a successful 

example.403 

324. Most commenters agree that the Commission should require each RTO or ISO to 

include a tariff provision imposing on itself the obligation to provide its MMU with 

access to market data, resources and personnel sufficient to enable the MMU to carry out 

its functions. They also agree that to ensure the MMU’s independence, the MMU should 

have access to the RTO’s or ISO’s database of market information. Further they agree 

that any data created by the MMUs should be kept within the exclusive control of the 

MMU.404 Three commenters state that the Commission should consider the provisions of 

a recent settlement agreement it approved as constituting “best practices.”405 Further, 

 402 PG&E at 14-15. 

403 Industrial Consumers at 21. 

404 Ameren, APPA, Exelon, California Munis, CAISO, EPSA, FirstEnergy, 

Industrial Consumers, ISO New England, Midwest Energy, Midwest ISO, Old Dominion, 

Pennsylvania PUC, PJM Power Providers, Reliant, and SPP. 

405 APPA, Exelon and Pennsylvania PUC (citing Allegheny Electric Cooperative, 

Inc., et al. v. PJM Interconnection, L.L.C., 122 FERC ¶ 61,257 (2008) (PJM MMU 

Settlement Order)). 
Docket Nos. RM07-19-000 and AD07-7-000 - 175 - 

APPA states that the Commission must specifically incorporate all of the MMU-related 

provisions of the PJM MMU Settlement Order into the Final Rule because the provisions 

now appear in a settlement agreement and have no precedential value.406 CAISO asks the 

Commission to clarify that “exclusive control” means that an MMU has the right to keep 

data it creates within its control, but has the option to share such data. CAISO states it 

appears this right is implicit in the Commission’s proposal, but the Commission should 

make it explicit.407 Reliant suggests that the Commission should clarify that MMUs 

should have full access to RTO or ISO operational information to determine if RTO 

operational decisions are negatively impacting appropriate price signals.408

325. APPA and Ohio PUC state that MMU offices should be at the RTO or ISO site.409 

APPA, California PUC and TAPS believe that the Commission should require a tariff 

provision directing an MMU to report to the Commission any concerns it has with 

inadequate access to market data, resources, or personnel. 

iii. Commission Determination

326. The Commission adopts the NOPR proposal that each RTO or ISO should decide 

for itself the structural relationship it desires for its MMU. Regional variances and 

 406 APPA at 6-7, 78-80. 

407 CAISO at 12-13. 

408 Reliant at 13. 

409 APPA at 80-81; Ohio PUC at 23. 
Docket Nos. RM07-19-000 and AD07-7-000 - 176 - 

preferences in this regard should be respected, and we decline to mandate any one 

structure for the MMU function. 

327. We therefore reject the suggestion from Industrial Consumers that we mandate a 

hybrid-type MMU structure consisting of both an internal and an external monitor. 

While the hybrid structure can provide many benefits, we have not observed that any 

RTOs or ISOs with purely internal or external MMUs suffer deficiencies in performance 

as a result. Nor would a hybrid MMU necessarily be more or less independent than an 

internal or an external MMU: hybrid MMUs receive funding from their RTOs or ISOs, 

just as do internal and external MMUs. Neither Industrial Consumers nor other 

commenters have presented examples of dysfunctional MMUs, much less a dysfunction 

that can be attributed to a particular organizational structure. 

328. We also adopt the NOPR proposal that RTOs and ISOs include provisions in their 

tariffs: (1) obliging themselves to provide their MMUs with access to market data, 

resources and personnel sufficient to enable them to carry out their functions; (2) granting 

MMUs full access to the RTO or ISO database; and (3) granting MMUs exclusive control 

over any MMU-created data. Without the proper tools, it would be impossible for 

MMUs to perform their functions. 

329. We clarify, in accordance with CAISO’s request, that MMUs may share data 

under their exclusive control, subject to pertinent confidentiality provisions. We also 

clarify, as requested by Reliant, that access to the RTO or ISO database includes access 

to RTO or ISO operational information. 
Docket Nos. RM07-19-000 and AD07-7-000 - 177 - 

330. We decline to adopt as “best practices” the provisions of the recent settlement 

agreement entered into by PJM and a number of interested parties concerning the 

structure, function and independence of PJM’s MMU (PJM/MMU Settlement 

Agreement).410 The provisions of that agreement were specific to one RTO, and 

represented a negotiated balancing of interests. It would be inappropriate to impose the 

specifics of that settlement on all other RTOs and ISOs, and especially to do so without 

notice and the opportunity to comment. However, we observe that the PJM/MMU 

Settlement Agreement is in accord with our determinations in this Final Rule regarding 

the appropriate MMU structure and tools.411 

331. We decline to require that MMU offices be at the RTO or ISO site. While such a 

location may well have its advantages, it is also possible that, in this age of electronic 

communications, other forms of access may be satisfactory. In any event, this is a level 

of detail that is best worked out on a case-by-case basis. 

332. We find it unnecessary to require inclusion of a tariff provision directing the 

MMU to report to the Commission any concerns it may have with inadequate access to 

market data, resources or personnel. As we noted in the NOPR, there are already 

 410 See PJM MMU Settlement Order, 122 FERC ¶ 61,257. 

411 In the event of any inconsistencies, the requirements imposed in this Final 

Rule, which have the force of regulation, would control. Indeed, the PJM/MMU 

Settlement Agreement itself so acknowledges, as the Commission noted in its order 

approving the settlement. Id. P 24. 
Docket Nos. RM07-19-000 and AD07-7-000 - 178 - 

adequate mechanisms for the MMU to bring any noncompliance in this regard to the 

Commission’s attention.412

b. Oversight

i. Commission Proposal

333. The Commission proposed in the NOPR that the MMU, for purposes of 

supervision over its market monitoring functions, should report to the RTO or ISO board 

rather than to management. The Commission further proposed that management 

representatives on the board be excluded from this oversight function. However, the 

Commission noted that, if RTOs and ISOs deem it appropriate, they may have the MMU 

report to management for administrative purposes, such as pension management, payroll 

and the like. The Commission also proposed that, if an RTO or ISO has a hybrid MMU 

structure with two market monitoring bodies, an internal and an external one, the RTO or 

ISO may have the internal market monitor report to management with respect to both its 

market monitoring and administrative functions, and the external market monitor report 

to the board. The Commission rejected the suggestion that the MMU should report to a 

body outside of the RTO or ISO structure. 

334. The Commission also declined to impose a blanket requirement that major 

changes in MMU status, such as termination of employment, be made subject to 

Commission review. Such requirements are included in the contractual arrangements of 

 412 NOPR at P 182. 
Docket Nos. RM07-19-000 and AD07-7-000 - 179 - 

certain RTOs or ISOs, but the Commission rejected imposing a “one size fits all” 

requirement on the remaining RTOs or ISOs absent their consent. 

ii. Comments

335. Commenters addressing the subject generally agreed that an MMU should report 

to an RTO or ISO board rather than to management.413 APPA cautions that an RTO or 

ISO board must be prepared to take appropriate oversight action when an MMU reports 

to it.414 FTC states that given the importance of MMU independence and recent concerns 

in this area, the Commission may wish to earmark this topic for periodic review, 

including an analysis of best practices both in the United States and abroad.415

336. With respect to the proposed exception for hybrid MMUs, five commenters 

support the proposal.416 For hybrids, most commenters agree that the internal monitor 

may report to management if the external monitor reports to the board. Another 

commenter, DC Energy, opposes this proposal, arguing that all market monitors should 

report to the board to ensure independence. TAPS states that the mix of duties between 

internal and external market monitors varies from region to region, with the external 

market monitor being “weak” in some cases and the internal market monitor performing 

 413 American Forest, APPA, CAISO, DC Energy, EPSA, FTC, Industrial 

Consumers, ISO New England, LPPC, Midwest ISO, New York PSC, North Carolina 

Electric Membership, NRECA, NYISO, Old Dominion, PJM Power Providers, Reliant, 

SPP and TAPS. 

414 APPA at 81. 

415 FTC at 30. 

416 CAISO; California PUC; EEI; NYISO; and Reliant. 
Docket Nos. RM07-19-000 and AD07-7-000 - 180 - 

the essential duties. TAPS proposes that the Commission require that the external market 

monitor be responsible for the MMU duties spelled out in the NOPR (e.g., identifying 

ineffective market rules, reviewing the performance of the market, and making referrals 

to the Commission). 

337. On the issue of reporting to a body other than the RTO or ISO, Ohio PUC believes 

that an external MMU should report to the RTO’s or ISO’s board of directors only as an 

interim step. It states that the Commission’s long-term goal should be total MMU 

independence, with the MMUs reporting as consultants to a Federal-State Joint Board on 

Market Monitor Oversight or to some other form of a joint-board construct, manned by a 

Commissioner and state commissioner or their designees. Ohio PUC believes this 

construct would provide MMU autonomy and relieve the board of directors of the RTO 

or ISO from arbitrating disputes between an RTO or ISO and the MMU.417 

338. Four commenters disagree with the Commission’s proposal not to impose a 

blanket requirement that major changes in the MMU’s employment arrangements be 

subject to Commission review and approval.418 APPA states that substantial changes 

such as contract termination and renewal for external market monitors, or major changes 

in employment arrangements for internal market monitors, should be subject to 

Commission review and approval. It also suggests that the Commission adopt the 

pertinent provision of the PJM/MMU Settlement Agreement as a “best practice,” 

 417 Ohio PUC at 16-21. 

418 APPA; California PUC; Steel Producers; and TAPS. 
Docket Nos. RM07-19-000 and AD07-7-000 - 181 - 

reasoning that this would give MMUs a measure of job security that might allow them to 

be more independent in their assessments.419 California PUC and Steel Producers agree 

that significant relational changes should be subject to Commission review, including 

changes to the structure of an MMU or the dismissal of key MMU personnel.420 TAPS 

states that Commission review of important changes would provide a backstop to ensure 

MMU independence, and would give market participants and the Commission a 

mechanism to assess whether an RTO or ISO has fulfilled its obligations toward the 

MMU. It argues that the Commission has not provided a valid reason not to require 

approval of such MMU changes.421

iii. Commission Determination

339. We adopt the NOPR proposal requiring MMUs to report to the RTO or ISO board 

of directors, with management representatives on the board excluded from this oversight 

function. Removing the MMU from reporting to management will give it the separation 

needed to foster independence. If occasion demands, we will revisit this decision. 

However, we decline to “earmark” it for periodic review as requested by the FTC. We 

also adopt the NOPR proposal allowing RTOs and ISOs, if they deem it appropriate, to 

permit the MMU to report to management for administrative purposes, such as pension 

management, payroll and the like. 

 419 APPA at 82. 

420 California PUC at 34; Steel Producers at 11-12. 

421 TAPS at 49. 
Docket Nos. RM07-19-000 and AD07-7-000 - 182 - 

340. Commenters generally agreed with our proposed exception for hybrid MMUs, in 

which we suggested that the internal market monitor may continue to report to 

management, while the external market monitor should report to the board. But TAPS 

points out that in some hybrid structures, the most important functions of the MMU are 

performed by the internal market monitor, with the external market monitor playing a 

much “weaker” role. We agree that such a division of labor presents a problem, and 

could result in the rule being swallowed by the exception. 

341. However, we decline to adopt TAPS’s suggested solution of requiring the external 

market monitor to assume responsibility for the core MMU duties spelled out in this 

order (identifying ineffective market rules, reviewing the performance of the markets, 

and making referrals to the Commission). This solution might impose upon the RTO or 

ISO an MMU structure that it does not want. Instead, we will require that if the internal 

market monitor is responsible for carrying out any or all of the above-cited core MMU 

functions, it must report to the board (as must the external market monitor). This solution 

allows the RTO or ISO to structure its MMU function in the way it deems most suitable, 

while also ensuring that the market monitor that performs the core MMU functions 

enjoys the independence from management that reporting to the board accomplishes. 

342. Ohio PUC suggests that reporting to the RTO or ISO board should be an interim 

step only, and that ultimately MMUs should report to a Federal-State Joint Board on 

Market Monitor Oversight. Not only does an arrangement of this type raise 

jurisdictional concerns, it is difficult to see how such a potentially cumbersome structure 

could oversee MMUs in a timely and responsive manner. It is also doubtful that such an 
Docket Nos. RM07-19-000 and AD07-7-000 - 183 - 

arrangement could effectively replicate the existing close exchange of data between the 

RTO or ISO and its MMU. Should the reforms we adopt in this Final Rule fail to achieve 

the needed independence we envision for MMUs, we will not hesitate to rectify the 

situation. 

343. Several commenters propose that changes in the RTO/ISO/MMU relationship, 

such as contract termination or the dismissal of key MMU personnel, should be made 

subject to Commission review.422 We noted in the NOPR that as of the date of its 

issuance, three of the RTOs and ISOs had agreements in place that provided for such 

review.423 Since that date a fourth has been added, that of PJM.424 

 422 To the extent commenters request that structural changes be made subject to 

Commission review, we note that such matters are governed by tariff and any change to 

the MMU structure (such as whether an MMU is internal, external or a hybrid) would 

require a tariff filing. 

423 Midwest ISO cannot terminate its agreement with its market monitor (an 

independent contractor) without Commission approval. Open Access Transmission and 

Energy Markets Tariff for the Midwest Independent Transmission System Operator, Inc., 

Attachment S-1, FERC Electric Tariff, Third Revised Volume No. 1, Second Revised 

Sheet No. 1659 (2005). SPP cannot terminate its agreement with its external market 

monitor without Commission approval. Southwest Power Pool Open Access 

Transmission Tariff, FERC Electric Tariff Fourth Revised Volume 1, Attachment AJ, 

§ 11, Second Revised Sheet No. 699 (2006). The same is true for ISO New England. 

Participants Agreement among ISO New England, Inc. and the New England Power 

Pool, et al., § 9.4.5. 

424 Settlement Agreement and Explanatory Statement of the Settling Parties, 

Docket Nos. EL07-56-000 and EL07-58-000 (December 19, 2007), Attachment M, PJM 

Market Monitoring Plan, III.F.3.e. This agreement was approved by the Commission in 

the PJM MMU Settlement Order. 
Docket Nos. RM07-19-000 and AD07-7-000 - 184 - 

344. These RTOs and ISOs have voluntarily consented to such review. In the absence 

of such consent, we decline to impose a blanket requirement that RTOs and ISOs make 

their MMUs’ contractual and employment arrangements subject to Commission review. 

Should the situation arise in which an RTO or ISO terminates its MMU in such a way as 

to violate its tariff requirements concerning MMU independence, the Commission will 

address such a violation on case-by-case basis. 

c. Functions

i. Commission Proposal

345. In the NOPR, the Commission proposed updating and expanding the core tasks 

that our May 2005 Policy Statement on Market Monitoring Units required MMUs to 

perform. We proposed that the MMU be responsible for evaluating market rules, tariff 

provisions and market design elements for their effectiveness, and proposing 

recommended changes; reviewing and reporting on the performance of the wholesale 

markets; and referring suspected wrongdoing to the Commission. 

346. In furtherance of its goal of ensuring independent analysis on the part of MMUs, 

the Commission also proposed that RTOs and ISOs include a provision in their tariffs 

specifying that they may not alter the reports generated by the MMUs or dictate the 

conclusions reached by the MMUs, although they may establish a reasonable mechanism 

for review and comment on MMU reports that are still in draft form. The Commission 

noted that this proposal will enable the MMU to receive potentially helpful comments, 

while removing the ability of the RTO or ISO to unreasonably influence or impede the 

MMU’s analysis. 
Docket Nos. RM07-19-000 and AD07-7-000 - 185 - 

ii. Comments 

347. All but two commenters support the Commission’s proposal regarding the three 

core functions of an MMU.425 ISO New England would add a fourth function, that of 

regular daily monitoring of the wholesale market in order to obtain timely access to 

information that would provide a broader context for evaluating particular types of 

conduct, and that could speed and enhance detection of manipulative behavior.426 TAPS 

would also add a fourth function, that of assessing whether RTO benefits flow to 

consumers. It suggests that the MMU could make this consumer-value assessment by 

examining, for example, whether in LMP markets investment in transmission, generation 

and demand response is occurring in areas with higher prices, and whether FTRs are 

available , and are being used, to hedge transmission congestion costs experienced by 

LSEs.427 

348. CAISO requests clarification that when an MMU evaluates existing and proposed 

market rules, the Commission expects it to employ its best judgment about effective use 

of resources, and does not expect a formal evaluation for every existing market rule.428 

California PUC agrees that an MMU should identify ineffective market rules and tariff 

 425 CAISO; California PUC; DC Energy; EEI; Industrial Consumers; ISO New 

England; Midwest ISO; North Carolina Electric Membership; NY TOs; PG&E; PJM; 

Reliant; SPP; and TAPS. 

426 ISO New England at 18. 

427 TAPS at 51-52. 

428 CAISO at 14. 
Docket Nos. RM07-19-000 and AD07-7-000 - 186 - 

provisions and recommend proposed rule and tariff changes; however, it suggests the 

MMU’s participation be limited to an advisory role.429 NY TOs and PJM state that 

MMUs should evaluate changes, but should not get involved in implementing changes.430 

PG&E believes the Final Rule should authorize MMUs to access data necessary to assess 

the impact of behavior outside of an RTO’s or ISO’s geographic footprint, commenting 

that such access is needed in California because the state is very dependent on imports. It 

also states that MMUs should report on the effectiveness and comprehensiveness of 

mitigation as part of their duties, even when they are not themselves directly involved in 

implementation of such mitigation.431

349. Two commenters agree with the Commission’s proposal that MMUs should limit 

dissemination of information in those cases where disclosure of a market design loophole 

could be exploited.432 APPA believes MMUs should disclose such information at an 

appropriate time, such as when tariff changes or software upgrades are adopted, in order 

to maintain transparency.433 Reliant requests clarification as to whether MMUs should 

 429 California PUC at 34-35. 

430 NY TOs at 3; PJM at 6. 

431 PG&E at 15-16. 

432 APPA; Reliant. 

433 APPA at 83. 
Docket Nos. RM07-19-000 and AD07-7-000 - 187 - 

provide the RTO or ISO, stakeholders and the Commission with their views as to whether 

existing operations interfere with appropriate market signals.434

350. All three commenters addressing the subject agree that MMUs should report 

violations of Standards of Conduct (18 CFR Part 158) or Affiliate Restrictions rules (18 

CFR 35.39) rules if uncovered in the ordinary course of business.435 California PUC 

states that violations should be referred to the appropriate state commission as well as to 

the Commission.436

351. Commenters agree that RTOs should not be allowed to alter reports generated by 

an MMU.437 APPA does not support a tariff provision allowing MMUs to submit their 

reports in draft form to RTOs for review and comment. It states that the Commission 

approved a specific prohibition against such review in the PJM/MMU Settlement 

Agreement, and should adopt such a prohibition in this proceeding.438 

352. Old Dominion suggests that if the MMU disagrees with a tariff change that the 

RTO or ISO proposes to the Commission, the RTO or ISO should file both its proposal 

and that of the MMU.439

 434 Reliant at 12-13. 

435 California PUC; EPSA; and Midwest ISO. 

436 California PUC at 36-37. 

437 APPA; NRECA; NSTAR; Old Dominion; PJM; and SPP. 

438 APPA at 83-84. 

439 Old Dominion at 21-22. 
Docket Nos. RM07-19-000 and AD07-7-000 - 188 - 

iii. Commission Determination

353. We adopt the MMU functions proposed in the NOPR, with clarifying rewording. 

These functions expand and update the functions already performed by MMUs in 

accordance with the Policy Statement and codify the protocols for referrals to the 

Commission discussed therein.440 The revised functions should provide MMUs with 

ample authority to evaluate any needed changes to the markets and bring them to the 

attention of concerned entities, to review and report on the performance of the markets, 

and to refer suspected wrongdoing to the Commission. 

354. As we have previously acknowledged: 

MMUs perform an important role in assisting the Commission in enhancing 

the competitiveness of ISO/RTO markets. Competitive markets benefit 

customers by assuring that prices properly reflect supply and demand 

conditions. MMUs monitor organized wholesale markets to identify 

ineffective market rules and tariff provisions, identify potential 

anticompetitive behavior by market participants, and provide the 

comprehensive market analysis critical for informed policy decision 

making.[441] 

Thus, the MMU functions we adopt are as follows: 

(1) evaluating existing and proposed market rules, tariff provisions and 

market design elements, and recommending proposed rule and tariff 

changes not only to the RTO or ISO, but also to the Commission’s Office 

of Energy Market Regulation staff and to other interested entities such as 

state commissions and market participants, with the caveat that the MMU is 

not to effectuate its proposed market design itself (a task belonging to the 

RTO or ISO), and with the further caveat that the MMU should limit 

distribution of its identifications and recommendations to the RTO or ISO 

 440 Policy Statement, 111 FERC ¶ 61,267 at Appendix A. 

441 Id. P 1. 
Docket Nos. RM07-19-000 and AD07-7-000 - 189 - 

and to Commission staff in the event it believes broader dissemination 

could lead to exploitation, with an explanation of why further dissemination 

should be avoided at that time; 

(2) reviewing and reporting on the performance of the wholesale markets to the RTO or 

ISO, the Commission, and other interested entities such as state commissions and market 

participants; and 

(3) identifying and notifying the Commission’s Office of Enforcement staff 

of instances in which a market participant’s behavior, or that of the RTO or 

ISO, may require investigation, including suspected tariff violations, 

suspected violations of Commission-approved rules and regulations, 

suspected market manipulation, and inappropriate dispatch that creates 

substantial concerns regarding unnecessary market inefficiencies. 

355. We decline to add as a fourth function ISO New England’s proposal regarding 

daily monitoring of the wholesale market, as this function is included in the existing 

requirement to review and report on the performance of the wholesale markets. 

356. CAISO requests clarification that the Commission does not expect an MMU to 

make a formal evaluation of every existing market rule. We agree. The MMU’s role is 

one of monitoring, not auditing, and we do not expect it to make a systematic and 

comprehensive review of every one of the thousands of existing market rules. For this 

reason, we decline to adopt TAPS’s suggested fourth function of assessing whether RTO 

or ISO benefits flow to consumers. Finally, we expect MMUs to be vigilant in 

identifying problems and bringing them to the attention of the RTO or ISO, the 

Commission, and other interested entities. 

357. We agree that the MMU’s role in recommending proposed rule and tariff changes 

is advisory in nature, and that the MMU should not become involved in implementing 

rule and tariff changes (unless a tariff provision specifically concerns actions to be 

undertaken by the MMU itself). Both the filing of proposed rule and tariff changes, and 
Docket Nos. RM07-19-000 and AD07-7-000 - 190 - 

the implementation of rule and tariff changes, are within the purview of the RTO or ISO. 

However, we do expect the MMU to advise the Commission, the RTO or ISO, and other 

interested entities of its views regarding any needed rule and tariff changes. Likewise, in 

the event an RTO or ISO files for a proposed tariff change with which the MMU 

disagrees, we expect the RTO or ISO to inform the Commission of that disagreement, 

although not necessarily to include a written MMU proposal with its filing. 

358. We also concur with PG&E that where data concerning activity outside the 

geographical footprint of the RTO or ISO would be helpful to the MMU in carrying out 

its functions, the MMU should seek out such data. Likewise, where an MMU believes 

market design flaws interfere with appropriate price signals, these flaws should be 

brought to the attention of concerned entities. And, where information about a market 

design flaw was not broadly disseminated because the MMU felt such information could 

alert market participants to a market loophole, such information can, and should, be 

provided once the danger of exploitation of the loophole is past. 

359. The California PUC requests that violations of the Standards of Conduct or 

Affiliate Restrictions should be reported to the appropriate state commission as well as to 

the Commission. We decline to adopt this proposal. These are violations of Commission 

rules, not of state rules or statutes, and therefore the Commission is the proper body to 

investigate them. 

360. We adopt the NOPR proposal that, by tariff, each RTO or ISO may require its 

MMU to submit its report in draft form to the RTO or ISO for review and comment, but 

may not alter the reports generated by the MMU or dictate the MMU’s conclusions. 
Docket Nos. RM07-19-000 and AD07-7-000 - 191 - 

RTOs or ISOs need not require submission of draft reports, but if they do, input from 

knowledgeable employees may serve to strengthen the end product or catch errors of fact 

or reasoning. In any event, the MMU is free to disregard any suggestions with which it 

disagrees. 

d. Mitigation and Operations

i. Commission Proposal

361. In order to strengthen MMU independence, the Commission proposed in the 

NOPR that MMUs be removed from tariff administration, including mitigation. This 

proposal was designed to free MMUs from a role that might make them subordinate to 

the RTO or ISO. The Commission regulates public utilities, and it is the public utilities 

that we hold accountable for tariff implementation. To the extent this function is 

performed by MMUs, the MMUs are assisting the RTOs and ISOs in the administration 

of their tariff, which places the MMUs in a subordinate position to the RTOs and ISOs. 

The proposal was also designed to remove the bias that might arise from the MMUs’ 

analyzing the health of the markets they themselves had affected. The Commission 

solicited comments on the activities that would be needed to make the transition to RTO 

or ISO-administered mitigation, on any difficulties the MMU might be anticipated to 

experience in monitoring mitigation performed by the RTO or ISO, and any additional 

sensitivities that commenters wished to raise regarding the proposal. 
Docket Nos. RM07-19-000 and AD07-7-000 - 192 - 

ii. Comments

362. Several commenters support the Commission’s proposal to remove MMUs from 

RTO and ISO tariff administration, including mitigation.442 However, many more oppose 

it.443 

363. The commenters who agree with the Commission’s proposal advance several 

arguments in support of it. Two entities cite two conflicts of interest that may arise when 

an MMU is involved in mitigation and tariff administration, the first occurring when an 

MMU both evaluates market performance and conducts mitigation,444 and the second 

occurring when an MMU assists in designing and finalizing a rule for filing with the 

Commission and subsequently evaluates the effectiveness of the rule in practice.445 

Another commenter states that an MMU should be limited to the three core functions the 

Commission enunciated in the NOPR, leaving it free to advise the Commission of 

perceived instances where the RTO or ISO itself has failed to conduct economic dispatch 

in an efficient manner.446 Other commenters state that the rules and actions related to 

 442 Ameren; EPSA; FirstEnergy; Industrial Consumers; PG&E; PJM; Reliant; 

SoCalEdison-SDG&E; and SPP 

443 American Forest; California PUC; Indianapolis P&L; Industrial Coalitions; 

Maine PUC; NARUC; NEPOOL Participants; New York PSC; North Carolina Electric 

Membership; Ohio PUC; Old Dominion; OMS; Potomac Economics; and Xcel. 

444 Ameren at 33; PJM at 4-6. 

445 Ameren at 33; PJM at 5-6. 

446 FirstEnergy at 14-15. 
Docket Nos. RM07-19-000 and AD07-7-000 - 193 - 

mitigation should be made explicit and, to the extent possible, be automated and 

implemented via bright-line tests, in order to eliminate discretion in their application.447 

364. The commenters who oppose the Commission’s proposal advance several 

arguments why RTOs and ISOs should not perform mitigation. Commenters suggest that 

the RTO or ISO staff and personnel who have designed and implemented the markets, 

and whose compensation is based upon those tasks, may have a vested interest in not 

identifying or correcting problematic behavior, and may have an interest in not imposing 

enforcement measures on what in effect are their customers, or in refraining from 

mitigating a member that threatens to leave the RTO or ISO.448 Other commenters 

remark that removing the MMU from mitigation activities may deprive the MMU of 

much of the hands-on administrative interaction with participants that is essential to 

consumer protection.449 One commenter suggests that a better way to address the issue is 

to issue additional orders limiting discretion in applying mitigation, rather than removing 

MMUs from mitigation activities.450 Other commenters argue that moving mitigation 

responsibility from an MMU to the RTO or ISO would deprive the MMU of timely, firsthand access to crucial information that could speed and enhance detection of 

 447 Reliant at 13; Potomac Economics at 8-9. 

448 American Forest at 6; California PUC at 37-38; Indianapolis P&L at 4; 

Industrial Coalitions at 21-22; Midwest ISO at 24-26; Ohio PUC at 24-25; and OMS at 

16-17. 

449 American Forest at 7; ISO New England at 19-22; and NARUC at 12-13. 

450 American Forest at 7. 
Docket Nos. RM07-19-000 and AD07-7-000 - 194 - 

manipulative behavior, noting that after-the fact mitigation (settlement price adjustment) 

would not be a function of the market that the MMU would be able to view once it was 

removed from tariff administration.451 ISO New England states that mechanistic 

application of mitigation criteria by RTOs or ISOs would not readily address shifts in 

bidding behaviors, and that as market participants continuously search for more profitable 

bidding strategies, the discretion of a skilled MMU to investigate unusual bidding 

behavior inhibits experimentation with deviant strategies and enhances deterrence.452 

ISO New England states that the Commission’s conflict of interest concern is inconsistent 

with grounding MMU independence and objectivity in its code of conduct and 

contractual obligations, and notes that the MMU has nothing to gain financially from 

mitigation.453 ISO New England and Maine PUC state that moving the mitigation 

activity to the RTO or ISO could require additional operational staff to perform tasks that 

MMU employees can accomplish on an integrated basis and more efficiently, thereby 

increasing RTO or ISO costs.454 NYISO estimates that an additional five to eight 

 451 ISO New England at 20-21; Xcel at 12-13. 

452 ISO New England at 21. 

453 Id. at 21-22 (citing ISO New England Inc., 119 FERC ¶ 61,045, at P 123 

(2007), reh’g granted in part and denied in part, 120 FERC ¶ 61,087 (2007)); NEPOOL 

Participants at 23 (citing ISO New England Inc. 106 FERC ¶ 61,280, P 187 (2004), reh’g 

granted in part and denied in part, 109 FERC ¶ 61,147 (2004); Order Authorizing RTO 

Operations; 110 FERC ¶ 61,111 (2005); order on reh’g, 111 FERC ¶ 61,344 (2005); 

ISO New England Inc., 120 FERC ¶ 61,087, at P 52 (2007)). 

454 ISO New England at 22; Maine PUC at 7. 
Docket Nos. RM07-19-000 and AD07-7-000 - 195 - 

employees would be required because of the need to duplicate some functions in order for 

the MMU to monitor the RTO or ISO’s conduct of mitigation.455

365. Indianapolis P&L states that moving the mitigation function to the RTO or ISO 

raises the potentially serious problem of retaliation, because if RTO or ISO stakeholders 

disagree with the direction in which the RTO or ISO wishes to move, the RTO or ISO 

could be tempted to use the market mitigation power as a tool of persuasion.456 OMS 

states that in the absence of a specific showing that an MMU is incapable of applying 

mitigation measures appropriately, the Commission should respect the decision of the 

RTO or ISO and stakeholders in this regard. It also observes that RTOs and ISOs have 

greater incentive than MMUs not to mitigate, as an entity might be inclined to withdraw 

from membership in response. It does not regard a referral to the Commission of an 

RTO’s or ISO’s failure to properly mitigate as a sufficient remedy, as such referrals are 

kept confidential.457

366. SoCal Edison-SDG&E support the Commission’s proposal only if the following 

conditions occur: (1) adequate assurance of effective mitigation is provided; (2) MMUs 

have full access to data used for mitigation; and (3) MMUs are allowed to participate in 

all activities used to develop mitigation rules and specific mitigated bid levels for 

 455 NYISO at 16. 

456 Indianapolis P&L at 4. 

457 OMS at 8-9. 
Docket Nos. RM07-19-000 and AD07-7-000 - 196 - 

individual generators.458 PG&E supports it only if: (1) RTO and ISO tariffs are modified 

to include sufficient staff resources to perform mitigation; (2) mitigation staff are free 

from the influence of other RTO staff; and (3) mitigation staff has the right to report to 

the Commission and its Office of Enforcement any loopholes or deficiencies in 

mitigation design or implementation.459

367. EEI, ISO New England, Maine PUC and New York PSC oppose the proposal for 

cases where the RTO or ISO has a hybrid MMU structure.460 Midwest ISO opposes the 

proposal when it is applied mechanically to all RTOs and ISOs.461 NRECA states that 

any changes in the Final Rule should not weaken mitigation, should not supersede the 

PJM/MMU Settlement Agreement, and should follow the Final Rule in Order No. 697.462 

CAISO notes that its internal monitor does not administer mitigation, but does administer 

an Enforcement Protocol related to late fees and the untimely submission of outage 

 458 SoCal Edison-SDG&E at 4. 

459 PG&E at 17. 

460 EEI at 24-25, ISO New England at 19-22; Maine PUC at 7; and New York PSC 

at 6-8. 

461 Midwest ISO at 24-26. 

462 Market-Based Rates For Wholesale Sales Of Electric Energy, Capacity, And 

Ancillary Services By Public Utilities, Order No. 697, FERC Stats. & Regs. ¶ 31,252, at 

P 241 (2007), order on reh’g, Order No. 697-A, 73 FR 25,832 (May 7, 2008), FERC 

Stats. & Regs. ¶ 31,268 (2008). 
Docket Nos. RM07-19-000 and AD07-7-000 - 197 - 

reports and meter data,463 and seeks guidance as to whether these activities would 

constitute “tariff administration” under the Final Rule.464 TAPS does not oppose the 

proposal, but thinks MMUs can function better doing mitigation.465

368. Potomac Economics and APPA offer compromise positions and clarifications. 

APPA suggests that the MMU continue to review bids, but refrain from participating 

directly in drafting proposed changes to the mitigation rules; rather, the MMU would 

comment on the proposed rules and, if necessary, become a separate intervenor in a 

Commission proceeding if one were to occur.466 

369. Potomac Economics observes that the aspects of mitigation that the Commission 

appears to find objectionable are those that are applied prospectively to participant offers 

and thus affect market outcomes (such as altering the prices of offers or altering the 

physical parameters of offers such as ramp rates and start-up time). Potomac Economics 

proposes that the Commission clarify that the RTO or ISO should be responsible for 

implementing these prospective mitigation measures, while the MMU be allowed to be 

responsible for implementing retrospective measures such as calculation of after-the-fact 

mitigation true-ups for billing purposes and settlement price adjustments. Potomac 

 463 Calif. Indep. Sys. Operator Corp., 106 FERC ¶ 61,179, at P 154; order on 

reh’g, 107 FERC ¶ 61,118; reh’g denied, 109 FERC ¶ 61,089 (2004); order on reh’g, 

110 FERC ¶ 61,333 (2005). 

464 CAISO at 15-16. 

465 TAPS at 52-53. 

466 APPA at 84-85. 
Docket Nos. RM07-19-000 and AD07-7-000 - 198 - 

Economics also suggests that MMUs continue to be responsible for the production of 

inputs into the mitigation process, such as reference levels and the identification of 

system constraints, which rely on the MMUs’ intimate knowledge of the market and their 

software capabilities. Potomac Economics believes that this bifurcation of labor would 

avoid the wasteful duplication of software, staff and expertise that would be needed for 

the RTO or ISO to mirror all of the MMU’s mitigation capabilities, that it contends the 

MMU would have to retain in order to satisfy its market monitoring obligations.467

iii. Commission Determination

370. The proposal in the NOPR to remove MMUs from tariff administration, and in 

particular from mitigation, engendered heated disagreement amongst the commenters. 

Several supported the proposal, although the majority disagreed with removing the MMU 

from mitigation. The Commission has given careful consideration to the comments, and 

acknowledges that there are valid concerns on both sides. 

371. As we observed in the NOPR, and as many commenters noted as well, there is an 

inherent conflict of interest in an MMU conducting mitigation and also opining on the 

state of the market, the health of which may in part reflect the results of its mitigation. 

We also observed that by supporting RTOs and ISOs in tariff administration, MMUs 

become subordinate to the RTO or ISO, thus weakening their independence. 

372. Many commenters, however, raise substantial concerns over removing MMUs 

from mitigation, including the following: (1) there is a greater conflict of interest for the 

 467 Potomac Economics at 8-10. 
Docket Nos. RM07-19-000 and AD07-7-000 - 199 - 

RTO or ISO to administer mitigation, as it has a vested interest in keeping its market 

participants happy, especially the larger players who can threaten to leave the RTO or 

ISO if they choose; (2) the MMU serves as a useful buffer between the RTO or ISO and 

the market participants, performing what is often viewed as a hostile act; (3) there is an 

inherent tension between mitigation and the RTO or ISO goal of promoting new markets; 

(4) the MMU is better equipped by training and market access to detect the need for 

mitigation; (5) removing the MMU from mitigation would distance it from the market 

insights it needs to perform its monitoring functions; (6) if removed from tariff 

administration, the MMU would not have access to the mitigation settlement process and 

thus could not adequately monitor the RTO’s or ISO’s mitigation performance; (7) there 

would be much duplication of costs, since the MMU would have to retain most of its 

mitigation capabilities in order to monitor the RTO’s or ISO’s conduct of mitigation; (8) 

there would be extensive transition costs and software licensing concerns; and (9) there is 

no empirical evidence of an existing problem with the MMUs performing mitigation. 

373. We find many of the objections raised by commenters meritorious. However, we 

remain concerned that the unfettered conduct of mitigation by MMUs makes them 

subordinate to the RTOs and ISOs and raises conflict of interest concerns. Therefore, we 

adopt a compromise approach, one that strikes the appropriate balance between allowing 

modified participation by the MMUs in mitigation, while protecting against the conflict 

of interest and subordination inherent in their unfettered participation. 

374. As the first element of this approach, we direct that in the event an RTO or ISO 

employs a hybrid MMU structure, it may authorize its internal MMU to conduct 
Docket Nos. RM07-19-000 and AD07-7-000 - 200 - 

mitigation. An internal MMU is a part of the RTO or ISO, and allowing it to conduct 

mitigation adequately separates it from the monitoring duties of the external market 

monitor and places mitigation within the RTO or ISO itself. However, this solution only 

works if the external market monitor is charged with the responsibility of reviewing the 

quality and appropriateness of the mitigation conducted by the internal market monitor. 

We therefore require that in the event an RTO or ISO with a hybrid MMU structure 

permits its internal market monitor to conduct mitigation, it must assign its external 

market monitor the responsibility, and give it adequate tools, to monitor the quality and 

appropriateness of that mitigation. 

375. As the second element of our approach, we find useful Potomac Economics’ 

distinction between prospective and retrospective mitigation. It is only prospective 

mitigation that affects the operation of the market, and therefore it is only prospective 

mitigation that creates a potential conflict of interest for an MMU. Therefore, we direct 

that RTOs and ISOs may allow their MMUs, regardless of whether it uses a hybrid 

structure, to conduct retrospective mitigation. For these purposes, we consider 

prospective mitigation to include only mitigation that can affect market outcomes on a 

forward-going basis, such as altering the prices of offers or altering the physical 

parameters of offers (e.g., ramp rates and start-up times) at or before the time they are 

considered in a market solution. All other mitigation would be considered retrospective. 

We also determine that the MMU may provide the inputs required by the RTO or ISO to 

conduct prospective mitigation, including determining reference levels, identifying 

system constraints, cost calculations and the like. This will enable the RTO or ISO to 
Docket Nos. RM07-19-000 and AD07-7-000 - 201 - 

utilize the considerable expertise and software capabilities developed by their MMUs, 

and reduce wasteful duplication. 

376. As noted by Potomac Economics and by PJM in its supplemental comments, a 

number of our orders specifically lodge elements of mitigation and administration within 

the MMUs. Many of these may properly be considered retroactive mitigation, and the 

RTOs’ or ISOs’ tariffs would not need to be adjusted to remove these responsibilities 

from the MMU’s purview. Should there be any question of categorization, whether for 

existing or proposed tariff provisions, the RTO or ISO may seek guidance from the 

Commission in its compliance filing. 

377. We also direct that purely administrative matters, such as those identified by 

CAISO (enforcement of late fees and the untimely submission of outage reports and 

meter data), should be conducted by the RTO or ISO, rather than the MMU. Such 

activities are remote from the core duties that this Final Rule assigns to the market 

monitoring function. 

378. We also direct that the tariffs of RTOs and ISOs clearly state which functions are 

to be performed by MMUs, and which by the RTO or ISO. This separation of functions 

will serve to eliminate RTO or ISO influence over the MMUs, and remove the concern 

that MMU assistance in mitigation makes it subordinate to the RTO or ISO. 

379. Finally, we direct the RTOs and ISOs to review their mitigation tariff provisions 

with a view to making them as non-discretionary as possible, whether performed by the 

MMU or by the RTO or ISO, and to reflect any needed changes in their compliance 

filings. This will go a long way toward removing the ability of either entity to act in a 
Docket Nos. RM07-19-000 and AD07-7-000 - 202 - 

discriminatory manner, and will facilitate the monitoring and review of mitigation 

activities. 

e. Ethics

i. Commission Proposal

380. In the NOPR, the Commission proposed that development of particular ethics 

standards to be applied to MMUs should be left in the first instance to the discretion of 

the RTOs and ISOs. However, the Commission noted that these standards should include 

certain minimum requirements, as follows: (1) employees shall have no material 

affiliation (to be defined by the RTO or ISO) with any market participant or affiliate; (2) 

employees shall not serve as an officer, employee, or partner of a market participant; (3) 

employees shall have no material financial interest in any market participant or affiliate 

(allowing for such potential exceptions as mutual funds and non-directed investments); 

(4) employees shall not engage in any market transactions other than the performance of 

their duties under the tariff; (5) employees shall not be compensated, other than by the 

RTO or ISO, for any expert witness testimony or other commercial services to the RTO 

or ISO or to any other party in connection with any legal or regulatory proceeding or 

commercial transaction relating to the RTO or ISO or to the RTO or ISO markets; (6) 

employees may not accept anything of value from a market participant in excess of a de

minimis amount, to be decided on by the RTO or ISO; and (7) employees must advise 

their supervisor (or, in the case of the MMU manager, advise the RTO or ISO board) in 

the event they seek employment with a market participant and must disqualify themselves 
Docket Nos. RM07-19-000 and AD07-7-000 - 203 - 

from participating in any matter that would have an effect on the financial interest of such 

market participant.468

ii. Comments 

381. All commenters addressing the subject agree that ethical standards should be 

imposed on MMU employees.469 All but one of these commenters agree that the 

standards should appear in a tariff provision, thus making the MMU subject to an 

enforcement action. However, FirstEnergy, stating that it is opposed to collecting from 

RTO or ISO members any penalties assessed to an RTO or ISO, prefers that the MMU 

adopt ethics standards internally and implement them by managing and disciplining its 

employees.470 APPA and Ohio PUC suggest adding a provision to the standards covering 

post-employment activities.471 Midwest ISO states its market monitor performs 

independent work for other entities under Commission-approved monitoring plans, and 

requests clarification that the minimum guidelines the Commission proposes would not 

prohibit other employees of the MMU’s firm from performing independent monitoring 

 468 The Commission noted that some external MMUs may currently have business 

associations that would be prohibited under these proposed minimum requirements, such 

as unrelated consulting work for participants in its RTO’s or ISO’s markets. If that is the 

case, the Commission proposed that the RTO or ISO should propose a suitable transition 

plan in its compliance filing. NOPR, FERC Stats. & Regs. ¶ 32,628 at n.200. 

469 Ameren; APPA; CAISO; California PUC; DC Energy; EEI; FirstEnergy; 

Industrial Consumers; ISO New England; Midwest ISO; North Carolina Electric 

Membership; NRECA; Ohio PUC; PG&E; PJM Power Providers; Potomac Economics; 

Reliant; SPP; and TAPS. 

470 FirstEnergy at 15-16. 

471 APPA at 86; Ohio PUC at 25-26. 
Docket Nos. RM07-19-000 and AD07-7-000 - 204 - 

for other entities. Potomac Economics, the Midwest ISO’s MMU, requests the same 

clarification, noting that the work is not done on behalf of the company.472 NRECA 

asserts that ethics standards should include civil penalties.473 

382. Potomac Economics proposes that the Commission should include the phrase 

“other than the RTO or ISO” after the first clause in proposed minimum requirement (5), 

as omission of the phrase would prohibit compensation of MMU employees for any 

expert witness testimony or other commercial services on behalf of the Commissionapproved RTO or ISO, thus preventing the MMU from performing many of the required 

market monitoring functions.474

iii. Commission Determination

383. There was widespread agreement among the commenters that ethics standards 

should be imposed, and the importance of such standards calls for their inclusion in the 

RTO’s or ISO’s tariff, subject to enforcement by the Commission. (The manner of such 

potential enforcement, including whether civil penalties might be imposed and the avenue 

by which any such penalties might be collected, is beyond the scope of this Final 

 472 Midwest ISO at 26-27; Potomac Economics at 13. 

473 NRECA at 53-54. 

474 Potomac Economics at 11-13. 
Docket Nos. RM07-19-000 and AD07-7-000 - 205 - 

Rule.475) Therefore, we direct that each RTO and ISO include in its tariff the minimum 

ethics standards set forth in the NOPR, with certain modifications as set forth below. 

384. We note that the requirements we impose are minimums, and an RTO or ISO is 

free to propose more stringent ones. Therefore, the appropriate place to request 

additional requirements, such as the suggested extension of the standards to postemployment activities, would be in stakeholder meetings, or before the Commission 

when the RTO or ISO makes its tariff compliance filing. 

385. Midwest ISO and Potomac Economics request clarification that the ethics 

standards do not prohibit employees of the MMU from performing monitoring for entities 

other than RTOs or ISOs. We clarify that if the employing entity is not a market 

participant in the particular RTO or ISO for whom the MMU already performs market 

monitoring, such engagement is permissible. However, if the employing entity is a 

market participant in the RTO or ISO for whom the MMU already performs market 

monitoring, the proposed work would entail the same conflict of interest as would any 

other consulting services. We are cognizant of the fact that if an MMU currently has 

such engagements in place, it will take a certain amount of time to unwind the association 

or make other suitable arrangements. We direct the RTO or ISO to apprise the 

Commission of such engagements in its compliance filing, and to propose a transition 

 475 See Revised Policy Statement on Enforcement, 123 FERC ¶ 61,156 (2008) 

(discussing the factors to be considered in determining what, if any, remedies are to be 

imposed in the case of violations of Commission rules and regulations). 
Docket Nos. RM07-19-000 and AD07-7-000 - 206 - 

plan for dealing with them in a manner consistent with the aims expressed in this Final 

Rule, as the Commission proposed in the NOPR.476

386. We agree with Potomac Economics that the NOPR’s regulatory text 

inappropriately omitted the phrase “other than the RTO or ISO” after the first clause of 

proposed minimum ethical requirement (E). (The phrase was included in the body of the 

NOPR itself). We direct that the RTO and ISO tariffs should include the omitted phrase, 

and we correct the regulatory text in this Final Rule. 

387. We also note that both the body of the NOPR and the regulatory text refer to 

“employees,” whereas the intent of the provision encompasses both the MMU itself as 

well as its employees. We therefore direct the RTOs and ISOs to specify that their 

MMU ethics standards apply to the MMU itself as well as to its employees. 

f. Tariff Provisions

i. Commission Proposal

388. The Commission proposed in the NOPR that RTOs and ISOs be required to 

include in their tariffs, and centralize in one section, all of their MMU provisions. We 

noted that including all MMU provisions in the tariff will ensure they are made subject to 

the compliance requirements that attach to tariff provisions, and thus will give to 

interested parties notice and an opportunity to intervene when a tariff filing is made. 

389. The Commission also proposed that RTOs and ISOs include an MMU mission 

statement in the introductory portion of its MMU tariff section, setting forth the goals to 

 476 NOPR, FERC Stats. & Regs. ¶32,628 at P 200. 
Docket Nos. RM07-19-000 and AD07-7-000 - 207 - 

be achieved by the MMU, including the protection of both consumers and market 

participants by the identification and reporting of market design flaws and market power 

abuses. 

390. The Commission further proposed that the RTOs and ISOs meet these 

requirements at the time they make their compliance filings in connection with this 

proceeding. 

ii. Comments 

391. Commenters support the proposal to locate all MMU provisions in one section of 

the RTO or ISO tariffs.477 Two commenters agree these provisions should include a 

mission statement.478 APPA states the best starting point for this kind of statement is 

Attachment M to the PJM/MMU Settlement Agreement.479 FirstEnergy opposes the 

option of leaving existing MMU provisions in their current location in addition to placing 

them in a new section of the tariff, since it believes this would be administratively 

inconvenient and has the potential to create inconsistencies.480 PG&E does not oppose 

 477 Ameren; APPA; California PUC; Constellation; DC Energy; EEI; FirstEnergy; 

Industrial Consumers; ISO New England; Midwest ISO; North Carolina Electric 

Membership; Old Dominion; PG&E; Reliant; SPP; and Xcel. 

478 APPA at 87; EEI at 25. 

479 APPA at 87. 

480 FirstEnergy at 14. 
Docket Nos. RM07-19-000 and AD07-7-000 - 208 - 

posting MMU provisions elsewhere than in the MMU section, so long as appropriate 

cross-referencing is made.481

iii. Commission Determination

392. We adopt the NOPR proposal and direct RTOs and ISOs to include in their tariffs, 

and centralize in one section, all of their MMU provisions. We also direct RTOs and 

ISOs to include a mission statement in the introductory portion of their MMU tariff 

section, which is to set forth the goals to be achieved by the MMU, including the 

protection of both consumers and market participants by the identification and reporting 

of market design flaws and market power abuses. 

393. We adopt the suggestion that RTOs and ISOs may include various MMU 

provisions elsewhere in their tariff as well as in the centralized MMU section, if they 

believe context and clarity so require. However, we are sympathetic to the concern that 

this duplicative listing may create confusion. Therefore, we require RTOs and ISOs, if 

they make such a duplicative listing, to clearly note that the provision in question is also 

found in the centralized MMU section. We also direct the RTO or ISO to include in its 

tariff a provision stating that in the event of any inconsistency between provisions in the 

centralized MMU section and provisions set forth elsewhere, the provisions in the 

centralized MMU section control. Of course, the RTO or ISO should attempt to avoid 

any such inconsistencies. 

 481 PG&E at 18-19. 
Docket Nos. RM07-19-000 and AD07-7-000 - 209 - 

394. We direct RTOs and ISOs to include their centralized MMU tariff sections in their 

compliance filings to be made in connection with this Final Rule. 

3. Information Sharing

a. Enhanced Information Dissemination

i. Commission Proposal

395. The Commission carried forward proposals in the NOPR that had been advanced 

in the ANOPR, and which were designed to enhance the dissemination of information by 

MMUs in several areas. Specifically, the Commission proposed that MMUs report on 

aggregate market performance on no less than a quarterly basis to Commission staff, to 

staff of interested state commissions, and to the management and board of directors of the 

RTOs or ISOs. The Commission also proposed the MMUs make one or more of their 

staff members available for regular conference calls with representatives from the 

Commission, state commissions and the RTO or ISO. In the NOPR, the Commission 

stated that the type of information to be released by the MMU may most fruitfully 

continue to be developed on a case-by-case basis, so long as it generally consists of 

market analyses of the type regularly gathered by the MMUs in the course of business, 

and so long as it remains subject to appropriate confidentiality restrictions. 

396. The Commission proposed that market participants be included in the 

dissemination of reports, which could be accomplished via posting them on the RTO or 

ISO web site. However, the Commission stated that including market participants on 

conference calls would be unwieldy, and proposed limiting participation on such calls to 
Docket Nos. RM07-19-000 and AD07-7-000 - 210 - 

Commission staff, RTO and ISO staff, staff of interested state commissions, and staff of 

state attorneys general should they express a desire to attend. 

397. While the Commission noted that quarterly reports should not be as extensive as 

the annual state of the market report, it also stated that the annual state of the market 

reports have proven to be useful documents, and proposed that the RTOs and ISOs 

include in their tariffs a requirement for the MMUs to produce them, with the same 

dissemination (or broader, if desired) as the quarterly reports. 

398. The Commission also proposed that the time period for the release of offer and bid 

data be reduced to three months, but that an RTO or ISO could propose a shorter period 

with accompanying justification or, if it demonstrates a potential collusion concern, a 

four-month lag period or some other mechanism to delay the release of a report if the 

release were otherwise to occur in the same season as reflected in the data. 

399. Additionally, the Commission proposed to retain the practice of masking the 

identity of participants when releasing offer and bid data. The Commission further 

proposed that the RTO or ISO include in its compliance filing a justification of its policy 

regarding the aggregation or lack thereof of offer data and of cost data, discussing the 

manner in which it believes its policy avoids participant harm and the possibility of 

collusion, while fostering market transparency. 
Docket Nos. RM07-19-000 and AD07-7-000 - 211 - 

ii. Comments

400. Commenters in general support information sharing policies for MMUs,482 and 

many commenters noted that the Commission struck a good balance between the need for 

information and the limitations of the MMUs.483 

401. Several commenters generally support the approach of developing the types of 

material to be disseminated on a case-by-case basis.484 EEI supports this flexible 

approach as long as the information is developed in the ordinary course of business by 

the MMU and is subject to the same confidentiality restrictions that are applied to release 

of information as determined by each RTO or ISO, or the Commission.485 Midwest 

Energy comments that as regulators of retail markets, state commissions should be aware 

of how the market is functioning.486 New York PSC states that the Commission should 

clarify that its proposed rule is the minimum standard for the dissemination of 

information and the MMUs that currently provide information to state commissions 

under working procedures will not be limited by the proposal.487 

 482 See, e.g., DC Energy; EEI; EPSA; Exelon; NEPOOL Participants; and Northeast 

Utilities.

483 See, e.g., EEI; EPSA.

484 See, e.g., EEI; FirstEnergy; Midwest Energy; Ohio PUC; and PJM Power 

Providers. 

485 EEI at 26. 

486 Midwest Energy at 4-5. 

487 New York PSC at 10. 
Docket Nos. RM07-19-000 and AD07-7-000 - 212 - 

402. APPA does not oppose this proposal but comments that a provision like the one in 

PJM’s tariff, which allows the MMU to respond to requests for studies or reports by 

states, should be included in all RTO/ISO/MMU tariff sections.488 PG&E believes that to 

the extent that state commissions need information about markets and market monitoring 

reports, it should be made clear that if the MMUs have data available as part of their 

overview of markets or preparation of reports, such data should be made available to state 

commissions for their use in analysis and oversight of market efficiency and trends.489 

Joint Commenters support an evaluation of the type of data each RTO or ISO should 

provide, stating that RTOs and ISOs can further improve their markets by describing in 

their compliance filings additional information they will disseminate.490 Joint 

Commenters urge the Commission to require each RTO or ISO to engage in a stakeholder 

process to develop a detailed document governing the identification of the type of 

additional information the RTO or ISO will disseminate, and to describe the information 

to be disseminated in the compliance filing. Joint Commenters recommend that the 

Commission require each RTO or ISO to apply the following criteria: (1) RTOs and 

ISOs should provide information to the extent it reasonably can be expected (a) to 

facilitate improved market transparency, reliability or efficiency; (b) to assist 

stakeholders in detecting market design or software flaws and/or suspected market 

 488 APPA at 87. 

489 PG&E at 20. 

490 Joint Commenters at 5. 
Docket Nos. RM07-19-000 and AD07-7-000 - 213 - 

manipulation; or (c) to assist market participants in their transaction activity; (2) provided 

that (a) the dissemination of the information will not harm the competitive dynamics of 

the market and (b) it is feasible from a resource allocation standpoint for the RTO to 

disseminate the information.491

403. NARUC believes that the Commission’s proposal is a mistake, commenting that 

the Commission should provide explicit standards that assure that the states have the 

same access to data as does the Commission.492 NARUC comments that (1) by granting 

such access, the Commission can leverage market oversight while, as explicitly 

acknowledged in the NOPR, giving state regulators access to data they need to fulfill 

their statutory responsibilities; (2) states need underlying data imbedded in aggregate 

information to verify and analyze MMU findings; and (3) states also recognize the need 

to protect from public disclosure information that could harm market participants or 

facilitate collusion.493 

404. Commenters support the proposal to include market participants in the 

dissemination of reports.494 NRECA, while supporting the proposal, is concerned that 

these reports may be insufficient if they do not provide the underlying data and 

assumptions used by the MMU to reach its conclusions, on the ground recipients may 

 491 Id.

492 NARUC at 13-14. 

493 Id. 

494 See, e.g., APPA; California PUC; Midwest ISO; Old Dominion; and NSTAR. 
Docket Nos. RM07-19-000 and AD07-7-000 - 214 - 

only be getting the RTO’s or ISO’s “spin” on the situation. NRECA suggests that the 

Commission should ensure the MMU reports provide sufficient information or provide a 

process whereby stakeholders can obtain access, subject to appropriate confidentiality 

restrictions, to the data and findings underlying MMU reports.495 NSTAR strongly 

supports including market participants in the dissemination of information on market 

abuses, and states that the reporting should be transparent as a deterrent and so market 

participants can assess how well the markets are working and whether changes are 

necessary.496 

405. Several commenters do not support the Commission’s proposal to limit access by 

market participants to conference calls.497 APPA recommends that conference calls be 

archived and posted on the RTO or ISO web site for market participants who cannot be 

on the call.498 Steel Producers and TAPS comment that the exclusion of market 

participants from such conference call is inappropriate, and that RTO or ISO stakeholder 

conference calls with numerous participants are commonplace.499 

 495 NRECA at 54-55. 

496 NSTAR at 8. 

497 See, e.g., APPA; Steel Producers; and TAPS. 

498 APPA at 88. 

499 Steel Producers at 12; TAPS at 57. 
Docket Nos. RM07-19-000 and AD07-7-000 - 215 - 

406. Commenters generally supported the Commission’s proposal and conclusions 

regarding quarterly and state of the market reports.500 APPA comments that certain 

annual state of the market reports are both over-inclusive with the amount of data 

reported and under-inclusive in terms of relevant data provided, and that MMUs should 

strive for quality as well as quantity in the data provided. EPSA supports the 

Commission's conclusion that the quarterly reports should not be as extensive as the 

annual state of the market reports.501 

407. Most commenters supported the reduction in lag time for offer and bid data to 

three months.502 Several others wanted a shorter lag time: one month,503 one week or 

less,504 or immediate disclosure.505 Several commenters suggested giving RTOs and 

ISOs flexibility to propose shorter or longer times.506 Citing two studies, APPA argues 

 500 See, e.g., EPSA; California PUC . 

501 EPSA at 14-15. 

502 See, e.g., EEI; California PUC; Industrial Consumers; ISO New England; Joint 

Commenters; Midwest ISO; North Carolina Electric Membership; NRECA; Reliant; 

SCE-SDG&E; and SPP. 

503 Industrial Consumers at 23. 

504 TAPS at 53-56. 

505 APPA at 89-91. 

506 EEI at 26-27 (citing regional factors); California PUC at 44; Joint Commenters 

at 4; and North Carolina Electric Membership at 19 (citing the need to prevent collusion); 

National Grid at 9; and SoCalEdison-SDG&E at 4. 
Docket Nos. RM07-19-000 and AD07-7-000 - 216 - 

that system lambdas should be disclosed at the same time as bid and offer data.507 If the 

Commission requires a shorter period of time to release offer and bid data, EEI argues it 

should maintain and enhance the masking and aggregation features.508 Although it 

supports the three-month period, Midwest ISO prefers leaving the decision to the 

stakeholders.509 

408. PG&E states that it is important that information about offer and bid data be 

increasingly available as prices and price caps rise, with disclosure of bid data 

sufficiently timely to permit review of bids before the necessity to undertake any 

challenge to such sales. PG&E also states that there is a need for increased market 

transparency when prices hit established bid or price caps, as such bidding may be 

designed to manipulate market prices and take advantage of temporary conditions. 

PG&E requests the Commission to consider modifying its disclosure requirements to 

provide for greater market transparency for bids at caps, with discretionary authority to 

disclose participants who bid in the region of any applicable price cap.510

 507 APPA at 89-91 (citing McCullough and Stewart, Ann, The Missing Benchmark 

in Electricity Deregulation, McCullough Research (Dec. 20, 2007); Dunn, William, Data 

Required for Market Oversight—A Concept Paper for the Electric Market Reform 

Initiative of the American Public Power Association, Sunset Point LLC (Dec. 8, 2007) 

(Dunn Study)). 

508 As an example, bid data should be aggregated in categories of size and the 

coding used to describe bidders should be changed periodically. EEI at 26-27. 

509 Midwest ISO at 28-29. 

510 PG&E at 20-22. 
Docket Nos. RM07-19-000 and AD07-7-000 - 217 - 

409. TAPS proposes immediate disclosure, arguing that competitive markets thrive on 

information, not secrecy. More information in the hands of a larger number of 

competitors, in its opinion, would reduce the likelihood of collusion. TAPS cites 

competitive electric markets operating successfully in Australia, England and Wales, 

where the markets provide near real-time and historical data, including bid and offer data. 

TAPS also asserts that large generation-portfolio holders already know their offers for 

each of their multiple resources, and allowing RTOs or ISOs to make it available for free 

and more quickly would enable smaller market participants to compete on a level playing 

field and assist with market monitoring.511 

410. A few commenters opposed the Commission’s proposal to reduce the lag time 

from six to three months.512 Ameren states that six months is a more appropriate time 

period to protect commercially sensitive data and guard against abuse.513 Constellation 

does not support the reduction in lag time for release of information, but says if the 

Commission decides to do so, it should apply this policy to all areas of the market and 

require MMUs to post bid and offer data for demand and virtual markets under the same 

confidentiality provisions.514 Ohio PUC states that the entities most likely to use the data 

are the market participants themselves, and believes there is little protection offered by 

 511 TAPS at 53-56 (citing the Dunn Study). 

512 See, e.g., Ameren; Constellation; and Ohio PUC. 

513 Ameren at 36. 

514 Constellation at 17. 
Docket Nos. RM07-19-000 and AD07-7-000 - 218 - 

masking the bidders’ identities. It agrees with the Commission’s analysis of the tradeoffs 

in reducing the lag period.515 

411. All but two commenters support masking participant identity.516 Ameren 

emphasizes the need to protect sensitive market data.517 Dominion Resources and EEI 

oppose unmasking, Dominion Resources stating that masking is needed to avoid the 

possibility of bid or offer fixing, collusion, or other behavior detrimental to the market.518 

California PUC suggests unmasking after two years; it also proposes to change masking 

on January 1 of each year to prevent market participants from being able to figure out the 

market participants in current data.519 SPP requests guidelines from the Commission on 

aggregating the data to protect the participant’s identity.520 Ameren proposes a 

mechanism where MMUs could give parties who have submitted false or inaccurate data 

the opportunity to correct any inaccuracies before the report is made final and submitted 

to the Commission.521 

 515 Ohio PUC at 28. 

516 See, e.g., Ameren; California PUC; Dominion Resources; EEI;; ISO New; 

England; Midwest ISO; SoCal Edison and SDG&E; and SPP. 

517 Ameren at 36. 

518 Dominion Resources at 8; EEI at 26. 

519 California PUC at 44. 

520 SPP at 9. 

521 Ameren at 36-37. 
Docket Nos. RM07-19-000 and AD07-7-000 - 219 - 

412. Two commenters oppose masking bidders’ identities. Ohio PUC and OMS 

believe there is little protection offered by such masking, arguing that the more 

sophisticated market participants will infer those identities and thus gain some further 

advantage over less sophisticated market participants. These commenters further assert 

that allowing third-party analysts to access data would increase the number of parties 

examining the bid and offer data to determine if collusive behavior exists.522 APPA 

states that market bid and offer data should not be kept confidential, and the term 

“commercially sensitive” should not be used as a blanket exception.523

iii. Commission Determination

413. We adopt the proposal made in the NOPR, with certain modifications. The 

Commission’s goal of broadening information sharing by the MMUs met with 

widespread approval, with a number of commenters expressing the opinion that the 

Commission had struck the right balance between the need for information on the one 

hand while recognizing the MMUs’ inability to provide unrestricted and unlimited 

amounts and types of information on the other. 

414. The information to be disseminated should consist of market trends and the 

performance of the wholesale market, with details to be developed on a case-by-case 

basis. In response to our request for comments on whether there were a generic standard 

or test that could be used to determine what specific information should be provided to 

 522 Ohio PUC at 28; OMS at 9-10. 

523 APPA at 93. 
Docket Nos. RM07-19-000 and AD07-7-000 - 220 - 

state commissions, Joint Commenters propose a two-part test, which we find generally 

helpful. However, the test does not include some of the confidentiality protections we 

have determined to be necessary, and we decline to adopt it. We also hesitate to require 

RTOs and ISOs to include in their tariffs specific details of the types of information that 

an MMU might find useful to provide, or that stakeholders might request. The nature of 

the information that may be helpful may vary from region to region, and may well evolve 

over time. Therefore, while an RTO or ISO is free to propose in its tariff details of the 

information it desires its MMU to provide, we will not require any particular menu. We 

are confident that MMUs will be responsive to reasonable requests from interested 

parties, subject to time and resource commitments. 

415. Moreover, the degree of inclusion of underlying data and assumptions is an area 

also best dealt with on a case-by-case basis. It is not to be expected that MMUs would 

include all the raw data in their possession. However, we would expect that they would 

provide, or make available on request, sufficient data to enable users of their reports to 

reasonably test the validity of their conclusions. 

416. We also clarify that our proposed rule is not intended to limit existing 

arrangements between MMUs and state commissions regarding the provision of 

information, subject to appropriate restrictions related to confidentiality concerns. Such 

arrangements are an example of the sort of case-by-case determination we envision 

developing in the area of information dissemination. 

417. We disagree with NARUC’s suggestion that explicit standards be put in place 

guaranteeing that states have the same access to data as does the Commission. While we 
Docket Nos. RM07-19-000 and AD07-7-000 - 221 - 

favor the enhanced dissemination of information to the states, there are some matters that 

are uniquely within the purview of the Commission, such as referrals by MMUs of 

suspected tariff violations or manipulation. We therefore decline to adopt such explicit 

standards. 

418. We agree with EPSA that quarterly reports should not be as extensive as the 

annual state of the market reports. It was not our intention that MMUs should be 

required to spend all their time on report preparation, which could easily be the case if 

quarterly reports were too extensive. Rather, we envision such quarterly reports as 

serving the function of timely updates to the annual state of the market report, 

emphasizing issues of concern. The details of what should be included in these reports 

can be worked out by the MMUs with input from interested stakeholders. We also agree 

with APPA that quality rather than quantity is crucial, and urge MMUs to ensure that the 

data they include in both their quarterly and their annual reports meets the anticipated 

needs of the extended community that will make use of them. 

419. Several commenters object to the Commission’s suggestion that market 

participants be excluded from conference calls regarding market updates. They note that 

stakeholder conference calls are commonplace, and see no reason why a similar practice 

should not be adopted with respect to MMU briefings. Upon reflection, we agree that the 

current state of the technology permits such calls with little difficulty. Therefore, we 

determine that market participants should not be excluded from such calls, absent 

pressing technical concerns in any given situation. 
Docket Nos. RM07-19-000 and AD07-7-000 - 222 - 

420. Our proposal to reduce the lag time for release of offer and bid data to three 

months was supported by most commenters. Some commenters requested a shorter lag 

time or immediate release. Others proposed the release of additional information, such as 

system lambda. 

421. Our proposal cuts the current lag time for most RTOs and ISOs in half. Because 

this is a substantial change, RTOs and ISOs should become accustomed to the new 

release time and observe its effects before committing to an even shorter time. However, 

as we proposed in the NOPR, we permit the RTOs and ISOs to propose a shorter time, 

with accompanying justification, or a longer time of four months if they can demonstrate 

a collusion concern. Alternatively, they may propose an alternative mechanism if release 

of a report were otherwise to occur in the same season as reflected in the data. These 

options provide the flexibility requested by commenters. 

422. We assume the data to be released would consist not only of physical offers and 

bids but demand and virtual offer and bids as well. However, if RTOs and ISOs object to 

such inclusion, they may address it in their compliance filings. Likewise, if they desire to 

release additional data such as system lambda, they may propose it in their filings. 

423. We adopt the NOPR proposal to retain the masking of identities. The objection 

that sophisticated market participants may be able to infer identities of those submitting 

offers and bids does not resolve confidentiality concerns; if anything, it argues for more 

protection, rather than less. We decline to establish a time period for the eventual 

unmasking of identities, but invite RTOs and ISOs to propose a period when such 

unmasking might be permitted, if they believe it to be desirable. 
Docket Nos. RM07-19-000 and AD07-7-000 - 223 - 

424. We therefore adopt the proposals advanced in the NOPR, modified as indicated. 

Each RTO and ISO is to include in its tariff a requirement that the MMU is to prepare an 

annual state of the market report on market trends and the performance of the wholesale 

market, as well as less extensive quarterly reports, all of which are to be disseminated to 

Commission staff, to staff of interested state commissions, to the management and board 

of directors of the RTOs or ISOs, and to market participants, with the understanding that 

dissemination may be accomplished by posting on the RTO’s or ISO’s web site. MMUs 

are also to make one or more of their staff members available for regular conference 

calls, which may be attended, telephonically or in person, by Commission and state 

commission staff, by representatives of the RTO or ISO, and by market participants. The 

information to be provided in the MMU reports and in the conference calls may be 

developed on a case-by-case basis, but is generally to consist of market data and analyses 

of the type regularly gathered and prepared by the MMU in the course of its business, 

subject to appropriate confidentiality restrictions. We also determine that the lag time for 

the release of offer and bid data be reduced to three months; however, an RTO or ISO 

may propose a shorter period with accompanying justification. Furthermore, if the RTO 

or ISO demonstrates a potential collusion concern, it may propose a four-month lag 

period or, alternatively, some other mechanism to delay release of the data if it were 

otherwise to occur in the same season as reflected in the data. The identity of market 

participants is to remain masked, although the RTO or ISO may propose a time period for 

eventual unmasking. The RTO or ISO is to include in its compliance filing a justification 

of its policy regarding the aggregation or lack thereof of offer data and of cost data, 
Docket Nos. RM07-19-000 and AD07-7-000 - 224 - 

discussing the manner in which it believes its policy avoids participant harm and the 

possibility of collusion, while fostering market transparency. 

b. Tailored Requests for Information

i. Commission Proposal

425. In the NOPR, the Commission carried forward the ANOPR proposal allowing 

state commissions to make tailored requests for information from MMUs regarding 

general market trends and performance, not to include information designed to aid state 

enforcement actions against individual companies. The Commission also proposed that a 

state commission could, on a case-by-case basis, request the Commission to authorize the 

release of otherwise proscribed data, if the state commission demonstrated a compelling 

need for the information and could insure adequate protections for commercially 

sensitive material. The Commission proposed that before an MMU be allowed to release 

information pertaining to a particular market participant, that the participant be given the 

opportunity to object and to correct any inaccurate information proposed to be released, 

and that the availability of this protection be included in the RTO or ISO tariff. The 

Commission also proposed that RTOs and ISOs develop, and include in their tariffs, 

confidentiality provisions that would protect commercially sensitive material, but which 

would not be so restrictive as to permit the release of little if any information. 
Docket Nos. RM07-19-000 and AD07-7-000 - 225 - 

ii. Comments 

426. Several commenters generally support the Commission’s proposal regarding 

tailored requests for information.524 APPA comments that the Commission should not 

bar MMUs from providing such assistance to the states if MMUs believe they can do so 

without harming their own mission.525 ISO New England states it has an information 

policy that already allows it to release confidential market information to state 

commissions under certain circumstances and subject to non-disclosure protections.526 

Duke Energy is concerned with giving the MMUs too much discretion and potentially 

imposing an unreasonable burden on them, but states that the guiding parameters set out 

by the Commission make the proposal more acceptable.527 FirstEnergy states the MMU 

should share analyses and information with state commissions only when directly 

necessary to support state regulatory obligations, and agrees that tailored requests from 

state commissions should not detract from the MMU’s core duties and must be made in 

light of budget and time limitations.528

427. The California PUC agrees that requests by state commissions should not overly 

burden the MMUs but comments that this need not be the case, noting that in California, 

 524 See, e.g., PJM Power Providers; SoCalEdison-SDG&E. 

525 APPA at 92-93. 

526 ISO New England at 26. 

527 Duke Energy at 11. 

528 FirstEnergy at 16. 
Docket Nos. RM07-19-000 and AD07-7-000 - 226 - 

CAISO and the California PUC have been able to work out the wording, scope and 

timing of the California PUC information requests in a reasonable and cooperative 

manner, including the protection of sensitive commercial information with a 

nondisclosure agreement. The California PUC and PG&E also comment that the MMU’s 

core function of reviewing and reporting on the performance of wholesale markets should 

be understood to include reporting to state commissions, and assert that data used in 

making MMU assessments of market efficiency or competitiveness, reports to CAISO 

management or boards, or reports to the Commission should be available to state 

commissions as well.529

428. EEI and Reliant support allowing the MMUs to be receptive to requests for 

information, as long as the information pertains to market trends and is developed in the 

ordinary course of business. EEI and Reliant comment that it is not reasonable for the 

MMUs to provide new studies or analysis beyond their annual and quarterly reports, and 

assert that state commissions may not treat MMUs as private consultants to perform 

studies. These commenters also assert that states have their own enforcement programs 

and should not rely on the MMU. Reliant suggests that, if a state commission requesting 

MMU information cannot agree with the RTO’s or ISO’s confidentiality provisions, the 

Commission should clarify that the MMU should not be required to disclose information 

to the state commission.530

 529 See, e.g., California PUC; PG&E. 

530 See, e.g., EEI; Reliant. 
Docket Nos. RM07-19-000 and AD07-7-000 - 227 - 

429. The Kansas CC agrees with the Commission’s proposal not to require MMUs to 

provide information to aid in state enforcement efforts or actions against individual 

utilities. However, it suggests that sensitive market information could be provided to 

state commissions in a manner that would uphold the confidential nature of the 

information and protect the market. The Kansas CC requests that the Commission 

consider alternative solutions that will preserve confidentiality, while providing state 

commissions with information necessary to fulfill their statutory and regulatory 

charges.531 

430. The Ohio PUC, noting the interconnectedness of retail rates to wholesale markets, 

proposes a test to determine the type of information that should be disseminated to state 

commissions. In its view, if a state commission asks for it, and the MMU has it or can 

get it without undue burden, it should be provided subject to confidentiality provisions.532 

431. Several commenters do not support various aspects of the Commission’s proposal 

on tailored requests from state commissions. The California PUC contends that the 

restrictions would cripple state market monitoring, and asks the Commission how it 

would distinguish between information designed to aid state enforcement actions from 

information designed to allow states to monitor the market.533

 531 Kansas CC at 2. 

532 Ohio PUC at 27, 29. 

533 California PUC at 48-49. 
Docket Nos. RM07-19-000 and AD07-7-000 - 228 - 

432. NARUC states that imposing the proposed limitations on state access to 

information is inefficient and unnecessary, observing that states operate in the public 

interest. NARUC argues that requiring unnecessary proceedings over specific requests, 

at taxpayer or ratepayer expense, is not good policy, and asserts that state commissions 

have demonstrated their ability to maintain the integrity of commercially sensitive 

materials.534

433. The New York PSC states that limiting its ability to obtain such information is 

unnecessary and unsupported by the record in this proceeding, contending that the 

Commission has not demonstrated that providing information to state commissions for 

state enforcement purposes violates any provision of law or policy, and noting that the 

purpose of the information may not be apparent in any event. It suggests that in the event 

the MMU is concerned about budgetary and time limitations, it could simply provide the 

state commission with the raw data and allow the state commission to employ its 

resources to derive the information or analysis sought. It proposes that if a state 

commission is able to maintain the information on a confidential basis, the MMU should 

be allowed to determine whether to provide the requested information.535

434. OMS disagrees with the Commission that its proposed restrictions on information 

access by state commissions are reasonable. It asserts that the NOPR proposal limiting 

state commission requests to the MMU to “general market trends and performance” 

 534 NARUC at 15. 

535 New York PSC at 10-12. 
Docket Nos. RM07-19-000 and AD07-7-000 - 229 - 

represents a significant reduction in the information its members already receive in 

accordance with the Midwest ISO’s tariff. OMS states that the Commission should 

respect the arrangement currently in place for the Midwest ISO, and permit that 

arrangement to be expanded, as necessary, to meet the need of OMS and its state 

commission members. OMS also asserts that state commissions should not be put in a 

position of merely having to trust the findings of the MMU, but rather, should be 

provided with the data and information necessary to evaluate and verify the MMU’s 

findings. It also states that the Commission’s proposal to prohibit state commissions 

from seeking information from the MMU that would aid state enforcement is 

unreasonable, as many state commissions do not have access to the data and information 

necessary to initiate investigative actions that might eventually lead to enforcement 

actions.536

435. Other commenters provided suggestions and points of clarification. The FTC 

encourages the Commission to devise ways that would allow MMUs to provide services 

to state and federal agencies even when the MMU does not have the extra resources. For 

example, it suggests that the Commission could authorize fees to be paid by state and 

federal agencies for services that primarily assemble and organize existing MMU data, 

which is similar to how other agencies deal with FOIA requests.537 The California PUC 

comments it is unclear if “information regarding general market trends and performance” 

 536 OMS at 13-14. 

537 FTC at 31. 
Docket Nos. RM07-19-000 and AD07-7-000 - 230 - 

would be limited to aggregated data or if the state commissions would also have access to 

raw data. It also states that this proposal would restrict existing access to data, and would 

require states to obtain Commission authorization and make a showing of a “compelling 

need” for that information.538 CAISO states that the Commission should clarify whether 

its proposal applies only to requests or also to subpoenas and court orders.539 TAPS 

opposes giving state commission staffs preferential treatment in the ability to make 

requests for information from the MMU.540

436. Several of the commenters support the provision regarding the development of 

confidentiality provisions, with limitations. The California PUC asserts that the language 

is too vague, and suggests it be revised to read "The RTO should develop confidentiality 

provisions in their tariffs that will protect commercially sensitive material, but will be no 

more restrictive than necessary to protect that information." The California PUC also 

notes that the California PUC and CAISO have an established practice for sharing market 

information that preserves confidentiality of data, and argues that the proposed 

limitations are unnecessary and would disrupt already existing state access to market 

data.541 

 538 California PUC at 47-48. 

539 CAISO at 16-17. 

540 TAPS at 57. 

541 California PUC at 46, 49. 
Docket Nos. RM07-19-000 and AD07-7-000 - 231 - 

437. The Maine PUC stresses the need for a greater level of information sharing by ISO 

New England with state commissions. It proposes that where there are protections in 

place to ensure that confidential information remains confidential when disclosed to a 

state commission, the Commission should direct ISO New England to share confidential 

information with the state commissions in the same or similar manner to its information 

sharing with the Commission.542 

438. The Ohio PUC and PJM request clear rules and definitions relating to confidential 

information. The Ohio PUC states that the Commission should require RTOs or ISOs to 

revisit the definitions of “Confidential Information” in their tariffs, asserting that in the 

cases of PJM and the Midwest ISO, confidential information is whatever a market 

participant declares it to be. PJM is concerned about the treatment of confidential 

information, such as cost data, particularly in the area of aggregated data that may be 

“reverse engineered.” PJM states that the release of these data, in conjunction with other 

industry information not necessarily known or even available to PJM, could inflict 

commercial harm on a market participant and adversely impact the competitiveness of the 

market. PJM requests clear, bright-line rules regarding the treatment of confidential 

information, noting it must deal with large volumes of such information that frequently 

are the subject of requests from numerous public and private entities.543 

 542 Maine PUC at 8-9. 

543 See, e.g., Ohio PUC; PJM. 
Docket Nos. RM07-19-000 and AD07-7-000 - 232 - 

439. Reliant and SPP are concerned about the treatment of confidential materials once 

in the hands of the state commissions. Reliant is of the view that state commissions 

should be required to identify the person who will have access to the information, the 

person who will be the official custodian for the information, and the purpose for the 

request. It states that a state official should be required to sign a non-disclosure 

agreement as a pre-condition of receiving data and, in situations where the state cannot 

guarantee data confidentiality, such as in the case where a state’s public records 

regulations might require disclosure, such data should not be shared. SPP is concerned 

that unless the state commission can provide proof that information can and will be kept 

confidential, that SPP should not be required to provide that information to the state 

commission, and asks that the Commission address the issue of relieving the RTO or ISO 

from any liability.544 

440. PJM Power Providers states that given the serious potential consequences 

associated with an improper release of sensitive market data, the Commission should go 

to great lengths to ensure the confidentiality of this information.545 

441. Commenters generally agree with the proposal to permit market participants the 

opportunity to contest any data specific to them that the MMU proposes to release. Duke 

Energy supports allowing market participants an opportunity to contest information, but 

comments that market participants should also have an opportunity to respond to data and 

 544 See, e.g., Reliant; SPP. 

545 PJM Power Providers at 18. 
Docket Nos. RM07-19-000 and AD07-7-000 - 233 - 

not just contest them, as they may want to provide context to data even if they do not 

wish to dispute them.546 FirstEnergy agrees that affected utilities should be given notice 

and have the opportunity to comment.547 

442. Several commenters support the Commission’s proposal to allow state 

commissions to request release of data from the Commission, with limitations or 

additions. EEI supports the Commission releasing data if the state demonstrates a 

compelling need and cannot obtain the data from any other source, and if the 

Commission can adequately protect commercially sensitive data.548 APPA believes that 

state entities (including commissions, state attorney generals, legislators, governors, and 

relevant electric retail regulatory authorities for public power systems) and third parties 

should be allowed to request information on a case-by-case basis directly from an MMU; 

if the MMU believes it can provide the needed information it should not have to go 

through the Commission, and only in the event the requestor is refused the information 

by the MMU, would it be necessary to petition the Commission.549 Duke Energy 

comments that affected market participants should have recourse to appeal an MMU 

decision to the Commission, just as a requester can petition the Commission.550 

 546 Duke at 11-12. 

547 FirstEnergy at 16. 

548 EEI at 28. 

549 APPA at 94. 

550 Duke at 12. 
Docket Nos. RM07-19-000 and AD07-7-000 - 234 - 

443. Other commenters strongly oppose the Commission’s proposal regarding 

submitting a request for the release of otherwise proscribed information. NARUC 

believes the proposal is likely to hamper proper state oversight, and argues that the 

Commission should not impose a gatekeeper function to evaluate state commission 

information needs or the legitimacy of their requests. NARUC argues this can only waste 

both state and federal resources and ratepayer funds on unnecessary proceedings.551 

444. The Ohio PUC questions how enforcement can occur without access to market 

information, which it argues the Commission currently controls. It asserts that the 

Commission must reevaluate its position on this matter to ensure that state commissions 

have timely access to market information and possess all the necessary tools to make 

certain that customers’ interests are protected against market abuses and manipulation. It 

also suggests that it could take entity-specific information subject to a confidentiality 

agreement, and then use that information to pursue its own discovery under state law, in 

order to pursue an enforcement action.552 OMS states that state commissions should not 

be required to petition the Commission for access to data and information that it feels 

should be theirs in the first place. OMS strongly urges the Commission to reconsider its 

position in this regard.553 

 551 NARCU at 15-16. 

552 Ohio PUC at 35. 

553 OMS at 14-15. 
Docket Nos. RM07-19-000 and AD07-7-000 - 235 - 

445. OPSI does not agree with the Commission’s proposal and recommends that any 

rules adopted in this proceeding reflect the data availability practices established in the 

PJM/MMU Settlement Agreement. 

iii. Commission Determination

446. The enhanced information sharing provisions we adopt in this Final Rule 

significantly expand the materials that state commissions may receive. However, we are 

cognizant that state commissions might from time to time desire additional information 

pertinent to their particular needs. Therefore, we adopt the NOPR proposal that state 

commissions may make tailored requests for information from the MMUs, so long as the 

request is limited to information regarding general market trends and the performance of 

the wholesale market. This limitation is needed in light of the limited resources of the 

MMUs, whose first order of business is evaluating market design, monitoring the 

markets, and referring suspected wrongdoing to the Commission. If this limitation were 

not imposed, the MMU could rapidly become an unpaid consultant for the states, and 

would be unable to perform its core functions. 

447. We are cognizant of the observations by EEI and Reliant that state commission 

requests for information, which would necessarily be in addition to the information 

already produced in the MMUs’ annual and quarterly reports, may place an unreasonable 

burden on the MMUs. We therefore direct that the MMUs, in the first instance, 

determine whether a request would be unduly burdensome. If so, it need not perform the 

requested study. 
Docket Nos. RM07-19-000 and AD07-7-000 - 236 - 

448. Many comments centered on the need for the confidentiality of the materials 

provided by the MMU, and the means by which confidentiality concerns could be 

addressed. Inasmuch as the material to be provided in response to tailored requests for 

information will consist of market trends and the performance of the wholesale market, 

such confidentiality concerns may not prove to be as great a stumbling block as some 

suggest. Where information to be provided raises confidentiality concerns, the 

information may nonetheless be provided, if appropriate non-disclosure agreements are 

executed. We direct the RTOs and ISOs to develop confidentiality provisions for their 

tariffs, and adopt the California PUC suggestion that such provisions be designed so as 

to protect commercially sensitive material, but be no more restrictive than necessary to 

protect that information. It will be up to each RTO or ISO, together with its 

stakeholders, to propose the confidentiality provisions they deem most appropriate, and 

to propose them to the Commission in a tariff filing. 

449. We note that our directive regarding the ability of state commissions to make 

tailored requests for information is designed to increase the dissemination of 

information, not restrict it. As we have indicated elsewhere, 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, unless the information 

violates confidentiality restrictions regarding commercially sensitive material, is 

designed to aid state enforcement actions, or impinges on the confidentiality rules of 

the Commission with regard to referrals, it may be produced, so long as it does not 

interfere with the MMU’s ability to carry out its core functions. 
Docket Nos. RM07-19-000 and AD07-7-000 - 237 - 

450. We decline to require MMUs to turn over raw data if they do not have the time to 

comply with a tailored request for information. If the MMU determines that raw data 

may be provided, appropriately redacted to meet confidentiality concerns, it may do so. 

However, it is quite possible that gathering, organizing, reviewing, and explaining such 

data might prove nearly as time consuming as responding in a narrative fashion to a 

request for information. The MMU is not a consultant for the states, and should not be 

placed in the position of having to respond to every request for information submitted to 

it. 

451. We also decline to eliminate our restriction on the state commissions’ ability to 

request information designed to aid state enforcement actions. Of course, if a state 

receives information regarding general market performance, and chooses to pursue a 

more focused study with its own resources, there is no prohibition to its doing so. The 

key considerations here are the burden placed on the MMU, the nature of the material to 

be provided, and the need for confidentiality. The MMU will be in the best position to 

determine if the material requested would be unduly burdensome to produce. And the 

RTO or ISO confidentiality provisions, as well as those of the Commission, will govern 

whether the state commission can receive information of a confidential nature. 

452. A state commission need not turn an MMU into an arm of its investigatory 

processes in order to carry out its duties. If a state has information suggesting the need 

for an investigation, it can use the full panoply of its powers and resources to pursue the 

matter on its own. We know from long experience that investigations are very time and 
Docket Nos. RM07-19-000 and AD07-7-000 - 238 - 

resource-intensive, and were states to enlist the MMU’s assistance in this regard, it would 

leave the MMU with little ability to carry out its core functions. 

453. We note, however, that from time to time Commission staff investigates matters of 

mutual interest to state commissions. It has been staff’s practice to work cooperatively 

with the states in such cases, bearing in mind the confidentiality of materials obtained by 

Commission staff in the course of an investigation. We direct staff to continue its 

practice in this regard. 

454. Whether requested information is designed to aid an enforcement action can 

generally be answered by the particularized nature of the request and the extent of the 

questions. As we have stated, the information to be provided in response to a tailored 

request for information should consist of market trends and the performance of the 

wholesale market. At least one comment reinforces the need for caution in this regard. 

The comment suggested that a state body could take entity-specific information subject to 

a confidentiality agreement and then use that information to pursue its own discovery. 

This end run around the confidentiality provisions might raise liability concerns on the 

part of both the MMU and the RTO or ISO, and possibly the Commission itself, and 

underscores the need to be sensitive to requests designed to support enforcement actions. 

455. We adopt the NOPR proposal that market participants be given the opportunity to 

contest any data specific to them. We also adopt the proposed expansion of this 

provision to include the right to provide context to the data, so long as the process does 

not unduly delay release of the information. 
Docket Nos. RM07-19-000 and AD07-7-000 - 239 - 

456. CAISO asks that we clarify whether our proposal applies only to requests or also 

to subpoenas and court orders. We clarify that our proposal applies to requests. Whether 

subpoenas or court orders are to be honored or contested lies outside the scope of this 

Final Rule and is a matter to be addressed by the MMU and by the RTO or ISO, in 

consultation with their attorneys. 

457. We decline to adopt the FTC’s suggestion that state and federal agencies be given 

the ability to obtain data from the MMU through the payment of fees. Such a fee 

arrangement could raise conflict of interest concerns. More significantly, however, it 

would reduce the MMU to the position of a consultant for hire, a role which would 

necessarily distract it from its core functions. 

458. We also adopt our NOPR proposal permitting state commissions to petition the 

Commission for the release of otherwise proscribed information. This provision is 

intended as a safety net to increase the ability of states to receive information, not as a 

further restriction. State commissions are free to direct their requests to the MMUs in the 

first instance, but such requests should comply with the restrictions we note above. If 

they do not, waiver of such restrictions is up to the Commission, not to the MMUs. 

459. Therefore, we carry forward our proposal from the NOPR, modified as noted 

herein. MMUs are to entertain from state commissions tailored requests for information 

regarding general market trends and the performance of the wholesale market, but not for 

information designed to aid state enforcement actions. Granting or refusing such requests 

will be at the MMU’s discretion, based on agreements worked out between the RTO or 

ISO and the states, or otherwise based on time and resource availability. Release of any 
Docket Nos. RM07-19-000 and AD07-7-000 - 240 - 

confidential information is to be subject to the confidentiality provisions in the RTO’s or 

ISO’s tariff, and to the Commission’s confidentiality restrictions. RTOs and ISOs are to 

develop confidentiality provisions that will protect commercially sensitive material, but 

which will be no more restrictive than necessary to protect that information. State 

commissions are also free to petition the Commission for the release of information that 

does not fall within the parameters noted. And market participants are free to contest the 

factual content of information to be released, or to provide context for it, so long as such 

material does not unduly delay release of the information. 

c. Commission Referrals

i. Commission Proposal

460. In the NOPR, the Commission noted that its rules require that information 

regarding its investigations be kept nonpublic unless, in any given case, the Commission 

authorizes that it be publicly disclosed. We proposed that the existing provisions 

regarding the confidentiality of MMU referrals to the Commission, as well as the 

confidentiality of the progress and results of its own investigations, be retained. The 

Commission also noted that it intended to continue the practice of Commission staff 

providing the MMUs with generic feedback regarding enforcement issues. 

ii. Comments 

461. Several commenters support the Commission’s proposal.554 APPA also suggests 

that the Commission has the obligation to act as quickly as possible, so other government 

 554 See, e.g., APPA, EEI, Midwest ISO, Reliant, and SPP. 
Docket Nos. RM07-19-000 and AD07-7-000 - 241 - 

entities with a legitimate interest in the matter are kept informed.555 ISO New England 

comments that the proposed referral provisions are generally consistent with, but more 

detailed than, ISO New England’s existing rules concerning the obligation of its MMU to 

identify and report on market design flaws and to refer potential market manipulation to 

the Commission.556 

462. Many commenters urge the Commission to reconsider its position that state 

commissions not be informed when an MMU refers a matter to the Commission.557 

Some commenters assert that several states maintain sufficient safeguards against public 

disclosure of information, and any assumptions regarding the potential mishandling of 

confidential information are misdirected and should be discounted.558 The California 

PUC and NRECA comment that the Commission should provide information to the 

MMUs and state commissions about matters an MMU has referred to the Commission, 

because it would help increase confidence that the Commission investigates attempts to 

manipulate the market.559 The Ohio PUC maintains that there must be a free exchange of 

 555 APPA at 94. 

556 ISO New England at 27. 

557 See, e.g., California PUC, NARUC, New York PSC, NRECA, Ohio PUC, and 

OMS. 

558 See, e.g., New York PSC, Ohio PUC, and OMS. 

559 California PUC at 52-53. 
Docket Nos. RM07-19-000 and AD07-7-000 - 242 - 

market data among the RTO or ISO, the MMU, and state commissions to ensure markets 

are flourishing and to avoid manipulation.560 

463. NARUC comments that the Commission should inform affected state 

commissions of MMU referrals because the commissions need information about specific 

market participants both to properly exercise their own regulatory authority and to avoid 

potentially inconsistent outcomes and duplicative efforts.561 The New York PSC 

comments that it is vital that state commissions be able to demonstrate that the presence 

of a competitive market does not disable the state from protecting retail ratepayers, and 

that the state commission is capable of carrying out its statutory obligation in a 

competitive market.562 

464. NRECA believes that an appropriate balance can be struck with respect to 

information and emphasized that it is not seeking the release of the names of individual 

entities or any competitively sensitive information but is merely requesting statistical 

information on, for example, numbers of entities referred, typed of infractions, and the 

resolution of referrals.563 OMS comments that state commissions could be effective allies 

with the Commission in the investigation and evaluation of the market participant 

behavior that led the MMU to make the referral, and the Commission’s concern that 

 560 Ohio PUC at 32. 

561 NARUC at 16. 

562 New York PSC at 13-15.

563 NRECA at 56. 
Docket Nos. RM07-19-000 and AD07-7-000 - 243 - 

informing state commissions of MMU referrals might discourage market participants 

from self-reporting objectionable behavior is not applicable to MMU referrals, as these 

referrals happen only because a market participant has failed to self-report.564

iii. Commission Determination

465. We adopt the NOPR proposal retaining the confidentiality of MMU referrals to the 

Commission, as well as the confidentiality of any investigations that result from such 

referrals. By Commission rule, all information and documents obtained during the course 

of an investigation are non-public. They may not be released except to the extent the 

Commission directs or authorizes in a given instance, unless the material is already made 

public during an adjudicatory proceeding or disclosure is required by the Freedom of 

Information Act.565 There are sound policy reasons for this rule. As we noted in the 

NOPR, release of such confidential information would impede the willingness of market 

participants to cooperate in the investigation and to self-report in the future. It could also 

injure innocent persons who might be erroneously implicated or adversely affected by 

simply being associated with an investigation. 

466. The Commission can only answer for its own abilities to keep material 

confidential, and cannot put itself in the position of having to interpret the extent of 

protections afforded by all the relevant state rules, statutes, and case law that govern 

disclosure. Nor can it expose itself to the potential liability it might incur by turning over 

 564 OMS at 11. 

565 18 CFR 1b.9. 
Docket Nos. RM07-19-000 and AD07-7-000 - 244 - 

confidential materials, should such materials be misused by agencies or individual state 

employees over whom the Commission has no control. 

467. We also are not persuaded that release of information about MMU referrals would 

avoid potentially inconsistent outcomes and duplicative efforts. For that to be true, one 

would have to assume that the scope of jurisdiction and the governing laws of the states 

in question are identical to those of the Commission, which is clearly not the case. 

468. We are sympathetic to NRECA’s request for statistical information, and agree 

that, to the extent we can make our enforcement actions more transparent, it is desirable 

to do so. To that end, we recently announced that the staff of the Office of Enforcement 

will prepare and publicly release annual reports summarizing its enforcement activities 

for the preceding year, to be released at the close of our fiscal year, September 30.566 The 

first such report was released on November 14, 2007.567 In addition, it is the practice of 

Commission staff to provide the MMU with generic feedback regarding enforcement 

issues, and we will ensure that staff continues to do so. 

469. We therefore decline to alter our rule and policy regarding the confidential nature 

of MMU referrals to the Commission. 

 566 Revised Policy Statement on Enforcement, 123 FERC ¶ 61,156, at P 12 (2008). 

567 Report on Enforcement, Docket No. AD07-13-000 (2007). 
Docket Nos. RM07-19-000 and AD07-7-000 - 245 - 

4. Pro Forma Tariff

a. Commission Proposal

470. In the NOPR, the Commission declined to propose a pro forma tariff for the MMU 

sections of an RTO or ISO OATT, instead proposing that RTOs and ISOs conform their 

tariffs to the requirements set forth in this Final Rule. The Commission also proposed 

that each RTO or ISO include protocols for the referral of tariff, rule, and market 

manipulation violations to the Office of Enforcement, and for the referral of perceived 

market design flaws and recommended tariff changes to the Office of Energy Market 

Regulation. 

b. Comments

471. A limited number of entities filed comments on the Commission’s proposal. The 

Midwest ISO agrees that requiring each RTO or ISO to conform its tariff to the 

requirements of the Final Rule is preferable to a pro forma tariff.568 EEI agrees that the 

Commission has appropriately permitted RTOs and ISOs flexibility to tailor their market 

monitoring provisions to their own regional variations.569 APPA suggests that the 

Commission use, as a possible template for the relevant tariff provisions, the revised 

Attachment M to the PJM tariff approved in the PJM MMU Settlement Order.570 SPP 

believes that it already complies with the majority of the proposals the Commission has 

 568 Midwest ISO at 27. 

569 EEI at 24. 

570 PJM MMU Settlement Order, 122 FERC ¶ 61,257. 
Docket Nos. RM07-19-000 and AD07-7-000 - 246 - 

set forth in this proceeding, but will comply with any revisions that may be required by 

the Final Rule.571

472. The California PUC, on the other hand, states that it does not support a pro forma

tariff because of its objections to several of the MMU proposals in the NOPR, 

particularly the issues surrounding state access to data.572

c. Commission Determination

473. Given the degree of discretion this Final Rule allows RTOs and ISOs to structure 

their relationship with their MMUs in the manner they deem most suitable, a pro forma

MMU tariff section would be impractical. Therefore, we will not impose one. 

474. We also decline to adopt PJM’s MMU tariff section, Attachment M, as a template 

for a centralized MMU tariff section. That document is particularized to the needs of that 

RTO, and we therefore will not require other RTOs and ISOs to follow it. We agree, 

however, that some uniformity is desirable, particularly for market participants who 

operate in multiple regions, and for regulators who often have occasion to compare and 

contrast tariff provisions amongst the various RTOs and ISOs. 

475. We therefore suggest, but do not require, that RTOs and ISOs consider structuring 

their MMU tariff sections to include the following general categories, preferably in this 

general order: Introduction and Purpose; Definitions; Independence and Oversight; 

Structure; Duties of Market Monitor; Duties of RTO or ISO; Data Access, Collection, 

 571 SPP at 10. 

572 California PUC at 53. 
Docket Nos. RM07-19-000 and AD07-7-000 - 247 - 

and Retention; Information Sharing; Ethics; RTO- or ISO-Specific Provisions; Protocol 

on Referrals of Investigations to the Office of Enforcement; Protocol on Referrals of 

Perceived Market Design Flaws and Recommended Tariff Changes to the Office of 

Energy Market Regulation. 

476. We note that in our Policy Statement on Market Monitoring Units,573 we 

prescribed the form and contents of an MMU referral to the Office of Enforcement. We 

likewise include in this Final Rule updated protocols for such referrals, as well as 

protocols for referrals to the Office of Energy Market Regulation of perceived market 

design flaws and recommended tariff changes. 

D. Responsiveness of RTOs and ISOs to Customers and Other 

Stakeholders

477. In this section of the Final Rule, the Commission requires RTOs and ISOs to 

establish a means for customers and other stakeholders to have a form of direct access to 

the board of directors, and thereby to increase the boards of directors’ responsiveness to 

these entities. (By responsiveness, we mean an RTO or ISO board’s willingness, as 

evidenced in its practices and procedures, to directly receive concerns and 

recommendations from customers and other stakeholders, and to fully consider and take 

actions in response to the issues that are raised.) The Commission requires each RTO or 

ISO to submit a compliance filing demonstrating that it has in place, or will adopt, 

practices and procedures to ensure that its board of directors is responsive to customers 

 573 Policy Statement, 111 FERC ¶ 61,267 at Appendix A. 
Docket Nos. RM07-19-000 and AD07-7-000 - 248 - 

and other stakeholders. The Commission will assess each RTO’s or ISO’s filing using 

four criteria: (1) inclusiveness; (2) fairness in balancing diverse interests; (3) 

representation of minority positions; and (4) ongoing responsiveness. 

478. The Commission also directs each RTO and ISO to post on its web site its mission 

statement or organizational charter. The Commission encourages each RTO and ISO to 

set forth in these documents the organization’s purpose, guiding principles, and 

commitment to responsiveness to customers and other stakeholders, and ultimately to the 

consumers who benefit from and pay for electricity services. 

1. Background

479. Neither Order No. 888574 nor Order No. 2000575 mandated specific RTO board 

governance requirements. In Order No. 2000, the Commission stated that, given the 

early stage of RTO formation, it would be counterproductive to impose a one-size-fits-all 

approach to governance when RTOs may have varying structures based on their regional 

 574 Promoting Wholesale Competition Through Open Access Non-Discriminatory 

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

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

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

888-B, 81 FERC ¶ 61,248 (1997), order on reh’g, Order No. 888-C, 82 FERC ¶ 61,046 

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

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

(2002). 

575 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). 
Docket Nos. RM07-19-000 and AD07-7-000 - 249 - 

needs.576 Therefore, the Commission indicated that it would review governance proposals 

on a case-by-case basis.577 The Commission also emphasized the importance of 

stakeholder input regarding both the creation of RTOs and ongoing operations.578 The 

Commission added that, in the case of a non-stakeholder board, it is important that the 

board not become isolated.579

480. In the ANOPR, the Commission noted stakeholders’ concerns that RTOs and ISOs 

are not sufficiently responsive to customers and other stakeholders, and that those parties 

should have some form of effective direct access to the RTO or ISO board of directors.580 

The Commission inquired whether RTOs and ISOs should be required to create and 

institute practices and procedures to ensure that customers and other stakeholders have 

such access.581 The Commission also made a preliminary proposal that the goal of 

 576 The Commission noted that existing ISOs have varying forms of governance. 

Some used a two-tier form of governance with a non-stakeholder board and advisory 

committees of stakeholders while one, CAISO, employed a decision making board 

consisting of both stakeholders and non-stakeholders. Order No. 2000-A, FERC Stats. & 

Regs. at 31,073. 

577 Id. at 31,073-74.

578 Id.

579 Id.

580 ANOPR, FERC Stats. & Regs. ¶ 32,617 at P 148. 

581 Id. P 149. 
Docket Nos. RM07-19-000 and AD07-7-000 - 250 - 

enhancing customer and other stakeholder access to the board could be achieved by either 

a board advisory committee or a hybrid board.582

2. Commission Proposal

Responsiveness Obligation and Proposed Criteria

481. In the NOPR, the Commission proposed to require that customers and other 

stakeholders have some form of effective direct access to the RTO or ISO board of 

directors. The Commission indicated that while it viewed the board advisory committee 

as particularly suitable for enhancing responsiveness, it anticipated that each RTO or ISO 

and its stakeholders would develop practices and procedures that best suit their needs.583 

The Commission reiterated its position that a one-size-fits-all approach may not be 

beneficial given the varying structure and needs of each regional entity. It therefore 

proposed to establish a set of four criteria for RTOs and ISOs designed to ensure that 

RTO and ISO boards are responsive to their customers and other stakeholders.584 

482. In order to demonstrate that RTOs and ISOs meet the responsiveness obligation, 

the Commission proposed to require each one to submit a compliance filing showing that 

it has in place or will adopt practices and procedures to ensure responsiveness. The 

 582 Id. P 151, 153. The Commission explained that a hybrid board would be 

composed of both independent members and stakeholder members, with each member 

holding a seat on the board and participating fully in board decisions with an equal vote. 

Id. P 152. 

583 Id. P 277. 

584 NOPR, FERC Stats. & Regs. ¶ 32,628 at P 275. 
Docket Nos. RM07-19-000 and AD07-7-000 - 251 - 

Commission proposed to assess the filed practices and procedures of each RTO and ISO 

using four criteria: 

• Inclusiveness - The business practices and procedures must ensure that any 

customer or other stakeholder affected by the operation of the RTO or ISO, or its 

representative, is permitted to communicate its views to the RTO’s or ISO’s board 

of directors. 

• Fairness in Balancing Diverse Interests - The business practices and procedures 

must ensure that the interests of customers or other stakeholders are equitably 

considered and that deliberation and consideration of RTO and ISO issues are not 

dominated by any single stakeholder category. 

• Representation of Minority Positions - The business practices and procedures must 

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

particular issue, minority positions are communicated to the RTO’s or ISO’s board 

of directors at the same time as majority positions. 

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

stakeholder input into the RTO’s or ISO’s decisions as well as mechanisms to 

provide feedback to stakeholders to ensure that information exchange and 

communication continue over time. 

483. The Commission proposed that each RTO or ISO compliance filing would be 

required to be submitted within six months of the date the Final Rule is published in the 
Docket Nos. RM07-19-000 and AD07-7-000 - 252 - 

Federal Register, and stated that it would assess whether each filing satisfies the proposed 

requirement and issue additional orders as necessary.585 

3. Comments

484. Most of the commenters support the Commission’s proposal and the four 

responsiveness criteria that the Commission proposed in the NOPR.586 Many also 

express support for the Commission not proposing a one-size-fits-all solution, but instead 

allowing regions flexibility in meeting the criteria.587 The comments fall loosely into 

three categories: (1) whether to establish an obligation for responsiveness; (2) whether 

the four responsiveness criteria are appropriate or need greater specificity; and (3) 

whether additional criteria should be required. 

485. Among the RTOs and ISOs, CAISO, Midwest ISO, NYISO, PJM and SPP argue 

that they already have responsiveness policies that they believe satisfy the Commission’s 

proposed criteria. Some stakeholders concur that their RTO’s or ISO’s policies meet the 

proposed criteria.588 APPA is skeptical that the proposals would have any effect, arguing 

 585 Id. P 92. 

586 See, e.g., Ameren; Comverge; Constellation; EEI; Exelon; Indianapolis P&L; 

Midwest ISO; New York PSC; NYISO; PJM; and PG&E. 

587 See, e.g., Ameren; ATC; Constellation; Midwest ISO; NYISO; PJM; and SoCal 

Edison-SDG&E. 

588 See Ameren and ATC discussing Midwest ISO; California PUC discussing 

CAISO; New York PSC discussing NYISO; and NEPGA, NEPOOL and NU discussing 

ISO New England. 
Docket Nos. RM07-19-000 and AD07-7-000 - 253 - 

that the RTOs and ISOs would likely say that their practices are already sufficiently 

responsive.589

486. Many commenters present examples of RTO or ISO practices that are not fully 

effective. For example, IID notes that during consideration of CAISO’s proposal to 

subsidize the financing of certain interconnection facilities, CAISO did not adopt any of 

the specific tariff language IID recommended or sufficiently explain why it was rejecting 

so many of IID’s suggestions.590 TANC opines that time frames for stakeholder review 

of CAISO initiatives are too short and therefore appear to diminish the value of 

stakeholder input. As a result, TANC submits that the Commission should require RTOs 

and ISOs to employ methods of interacting with stakeholders that are intended to achieve 

consensus on issues and that incorporate stakeholders early in the decision-making 

process.591

487. Connecticut and Massachusetts Municipals encourage the Commission to not 

solely rely on an inclusive stakeholder process to ensure that organized wholesale electric 

markets and market administrators are providing, or facilitating the provision of, reliable 

electric service at the lowest reasonable cost. They do not agree that developing a 

stakeholder process that meets the four criteria will alleviate the need for the Commission 

 589 APPA at 9, 97. 

590 IID at 5. 

591 TANC at 12. 
Docket Nos. RM07-19-000 and AD07-7-000 - 254 - 

to conduct its own investigation into the justness and reasonableness of proposed rates, 

charges, market rules, and design changes.592

488. Several commenters make recommendations about the four criteria proposed by 

the Commission. For instance, Ameren urges the Commission to make sure that the third 

criterion, representation of minority positions, is not allowed to outweigh the second 

criterion, fairness in balancing diverse interests. One way to do this, Ameren argues, 

would be to ensure that entities that will ultimately incur a major portion of the costs 

related to the changes to RTO or ISO market rules have a proportionate say in the 

development of these rules and any related modifications, through bicameral voting.593

489. TAPS asserts that the balancing criterion invites greater deference to wellrepresented classes to the detriment of other customers that the FPA requires the 

Commission to protect. CAISO requests that the Commission consider clarifying one of 

the four proposed criteria, fairness in balancing diverse interests, regarding how an RTO 

or ISO would be expected to establish generically that the consideration given to diverse 

interests is equitable.594

490. Constellation asks the Commission to clarify its definition of the term “customer” 

in its statement that “access by customers and other stakeholders to the board based on 

these criteria will provide them with the opportunity to ensure that their concerns are 

 592 Connecticut and Massachusetts Municipals at 9-10. 

593 Ameren at 15-16, 37-40. 

594 CAISO at 10. 
Docket Nos. RM07-19-000 and AD07-7-000 - 255 - 

considered.” It states that the term customer could be applied to non-jurisdictional 

entities such as retail customers, and the Commission has already ensured that state 

agencies that regulate the retail market have access to RTO and ISO boards.595

491. Other commenters recommend more detail regarding the application of the 

proposed criteria. For example, APPA suggests new mandates for RTO and ISO 

stakeholder processes to help meet the proposed criteria:596 mandated direct stakeholder 

access to RTO and ISO boards at frequent intervals; presentation of minority positions on 

RTO and ISO proposals directly to the board by minority stakeholders; consideration of 

the use of both stakeholder advisory committees and hybrid boards; open RTO and ISO 

board meetings, with agendas made public in advance and opportunity for stakeholder 

comment on agenda items; elimination of “self-perpetuating” RTO and ISO boards; 

directors elected by stakeholder vote, with multiple candidates for each seat and 

stakeholder input into the slate selection; and administration of customer satisfaction 

surveys by outside entities. ATC wants a formalized mechanism within an RTO’s or 

ISO’s main stakeholder committee for communicating minority views of stakeholder 

sectors to an RTO’s or ISO’s board of directors. 

492. SMUD states that RTOs and ISOs should be required to demonstrate that: (1) 

there is evenly divided industry sector representation, (2) no one sector (or entity) can 

dominate the process, (3) votes are taken to measure stakeholder sentiment, (4) there is a 

 595 Constellation at 19. 

596 APPA at 10, 102. 
Docket Nos. RM07-19-000 and AD07-7-000 - 256 - 

formal process for the RTO or ISO to consider adoption of stakeholder initiatives and (5) 

before the RTO or ISO can reject a stakeholder position supported by a supermajority of 

stakeholders, it must articulate its reasons in writing, including in any filing it makes with 

the Commission.597

493. Others suggest new criteria for improving responsiveness, such as providing 

opportunities for customer and other stakeholder feedback on budgets and costs. The 

Maine PUC argues that ISO New England has insufficient cost incentives, and that the 

Commission should consider requiring RTOs and ISOs to place a stronger emphasis on 

cost-containment in administration and development of wholesale electric markets.598 

North Carolina Electric Membership and NRECA suggest an additional criterion: 

reliable service at just and reasonable rates. According to NRECA, the Commission’s 

goals in creating RTOs and ISOs require that these entities ensure accountability to 

stakeholders for keeping costs down while maintaining a high level of service quality. 

NRECA also states that the Commission should require RTOs and ISOs to present annual 

budget information to customers and stakeholders, along with adequate detail, transparent 

assumptions and calculations of estimates, and cost support. It further recommends that 

the Commission require RTOs or ISOs with formula rates to develop their budget 

presentations for stakeholders and customers using the format required for a filing with 

the Commission to change previously approved rates. NRECA states that the RTO’s or 

 597 SMUD at 9. 

598 Maine PUC at 8. 
Docket Nos. RM07-19-000 and AD07-7-000 - 257 - 

ISO’s budgeting process should ensure that customers and other stakeholders have a 

timely opportunity for review of the budget proposals offered and that each RTO or ISO 

should submit to the Commission ,as an informational filing, all of the budget materials 

provided to stakeholders for review.599

494. Ameren suggests that RTOs and ISOs should be required to post longer-term 

budgets, such as five-year budgets, so that market participants can better monitor the 

costs and benefits of participating in RTO and ISO Day 2 markets.600 NRECA states that 

the NOPR is silent with respect to the matter of transparency in RTO and ISO budgets. 

Old Dominion also requests that the Commission reinstate the proposals contained in the 

ANOPR that would have improved transparency in the budget process. 601

495. Some commenters ask for a formal cost-benefit review of any significant action. 

Connecticut and Massachusetts Municipals request that the Commission require RTOs 

and ISOs to perform cost-benefit studies in support of proposed rates, charges, and 

related rules. FirstEnergy also recommends that significant new RTO or ISO proposals 

should require a formal cost-benefit analysis before being submitted to the stakeholder 

process. If these proposals are implemented, they argue, post-implementation costbenefit analyses should be employed to see if actual benefits have materialized. RTO or 

ISO initiatives that fail to produce stakeholder benefits or achieve their stated objectives 

 599 NRECA at 59. 

600 Ameren at 15-16, 37-40. 

601 Old Dominion at 5. 
Docket Nos. RM07-19-000 and AD07-7-000 - 258 - 

should be modified, or if necessary, rescinded.602 LPPC also suggests that the 

Commission should require cost-benefit analyses to be filed in conjunction with any 

significant capital expenditures or tariff changes. These cost-benefit analyses would be 

submitted with the annual budgets for approval by the Commission in the case of capital 

expenditures, or with section 205 filings for tariff changes.603

496. Other commenters want improvements regarding notice of meetings and time to 

review new proposals. TANC asserts that the Commission should set minimal standards 

as to what constitutes sufficient notice for convening stakeholder meetings and 

conference calls, for the submission of stakeholder comments, and for subsequent 

consideration of those comments prior to the RTO or ISO taking action. 604 ATC calls for 

a minimum amount of time afforded to stakeholders to review and provide suggestions 

and feedback on final versions of RTO or ISO filings before they are submitted to the 

Commission. California Munis suggests that unless there is a physical threat to system 

reliability or an exigent market condition, no stakeholder meeting should be held without 

two weeks, and preferably four weeks, minimum notice. It also argues that major market 

design and policy meetings should not be held the same day, and preferably not on backto-back days. It further suggests that policy white papers should be available no less than 

two weeks before the relevant stakeholder meeting. 

 602 FirstEnergy at 17. 

603 LPPC at 19. 

604 TANC at 13. 
Docket Nos. RM07-19-000 and AD07-7-000 - 259 - 

497. Other commenters want feedback from the RTO or ISO on how their views were 

taken into account in the decision-making process. ATC calls for establishment of a 

formal “feedback loop” that would provide greater transparency in how stakeholder 

views are received, reviewed, and considered in an RTO’s or ISO’s decision-making 

process. TANC argues that the Commission should require RTOs and ISOs to explain 

how they considered comments during their decision-making processes.605 TANC also 

asks the Commission to require the RTO or ISO to answer specific questions that would 

describe the stakeholder process employed for developing tariff revisions, and how 

customer and other stakeholder concerns were rectified. 

498. Other commenters call for periodic reviews of the effectiveness of stakeholder 

processes. LPPC suggests having a periodic survey of customer satisfaction. ATC 

recommends that RTOs and ISOs be required to submit annual reports to the Commission 

detailing their adherence to the proposed responsiveness criteria. These reports would 

provide the Commission with an ongoing mechanism for assessing whether an RTO or 

ISO is following its approved practices for adhering to the Commission’s responsiveness 

criteria, whether those practices maintain their effectiveness in meeting stakeholders’ 

needs, and whether these practices should be changed.606 California Munis believes that 

RTOs and ISOs should be required to make a regular showing to the Commission 

reviewing their stakeholder processes. NSTAR also encourages the Commission to 

 605 Id. at 20. 

606 ATC at 10. 
Docket Nos. RM07-19-000 and AD07-7-000 - 260 - 

require RTOs and ISOs to undergo a periodic, independent review of its stakeholder 

processes including sector membership qualifications, voting weights, and other 

measures. It contends that the Commission should oversee the review rather than leave it 

to the stakeholders. This review and recommendation should then be used to make 

constructive changes to the stakeholder processes to ensure that all parties are properly 

represented.607

499. Other commenters want RTOs and ISOs to adopt one another’s best practices. For 

example, NRECA states that the Commission should add a criterion for RTOs and ISOs 

to follow best practices. NRECA describes the PJM liaison committee meeting process, 

which allows for direct board access by requiring board member attendance at such 

meetings, and criteria for vote reporting. NRECA further states that requiring board 

member participation in substantive committee meetings would provide opportunity for 

improved communications between stakeholders and the board. 608

500. Other commenters have further suggestions for improving responsiveness to the 

needs of customers and other stakeholders. Joint Commenters urge the Commission to 

adopt three additional requirements for RTOs and ISOs to include in their compliance 

filings: (1) improved dissemination of information, (2) well-designed independent 

operational audits of RTOs and ISOs with stakeholder input, and (3) clarification of the 

 607 NSTAR at 11. 

608 NRECA at 60. 
Docket Nos. RM07-19-000 and AD07-7-000 - 261 - 

need to adhere to manuals and market rules except under clearly predefined 

circumstances.609 LPPC suggests requiring the annual publication of a strategic plan. 

4. Commission Determination

501. Based on the various aspects of the proposed responsiveness criteria that the 

comments address, we discuss three topics in order: whether to establish an obligation 

for responsiveness and whether the four responsiveness criteria are appropriate; whether 

the criteria need greater specificity; and whether additional criteria should be required. 

a. Responsiveness Obligation and Appropriateness of the 

Four Responsiveness Criteria

502. The Commission adopts its proposal from the NOPR and establishes by rule an 

obligation for each RTO and ISO to make reforms, as necessary, to increase its 

responsiveness to the needs of customers and other stakeholders. As further detailed 

below, each RTO and ISO must explain in a filing to the Commission how it is fulfilling, 

or will fulfill, this obligation. The Commission will assess each RTO’s or ISO’s filing 

using the responsiveness criteria discussed below. 

503. Although some commenters argue that this requirement is not needed or that 

RTOs and ISOs are already sufficiently responsive, we find this requirement necessary. 

For those RTOs and ISOs that may already be satisfying customer needs adequately, this 

formal requirement will help to focus the attention of RTO and ISO boards and senior 

management on improvements in this area of great concern to their customers and other 

 609 Joint Commenters at 3. 
Docket Nos. RM07-19-000 and AD07-7-000 - 262 - 

stakeholders. As RTOs and ISOs developed, the Commission emphasized that their 

decision-making processes must be independent of control of any market participant or 

class of participants. RTO and ISO independence remains fundamental, and we will 

preserve it; however, we find that RTOs and ISOs must provide an avenue for customers 

and other stakeholders to present their views on RTO and ISO decision-making, and to 

have those views considered. Establishing practices and procedures that would allow 

RTO and ISO boards to be responsive to the concerns of customers and other 

stakeholders is important to providing these entities with confidence in RTOs’ and ISOs’ 

independent governance processes. 

504. We will adopt the four responsiveness criteria as proposed in the NOPR. Based 

on the comments received, we conclude that each of the four criteria has a role in helping 

us to assess each separate dimension of responsiveness. We also require each RTO and 

ISO to submit a compliance filing demonstrating how it is responsive to customers and 

other stakeholders, and we will assess each demonstration based on the four criteria 

adopted herein. 

505. In adopting the four criteria, we have carefully sought to balance customers’ and 

other stakeholders’ need for effective access to the boards of RTOs and ISOs, with the 

need for the independent management of each RTO and ISO. Upon consideration of the 

comments, the Commission finds that the four criteria are appropriate, balanced, and 

suitably tailored to improve the responsiveness of RTOs and ISOs to customers and 

stakeholders. 
Docket Nos. RM07-19-000 and AD07-7-000 - 263 - 

506. The first criterion, inclusiveness, is intended to ensure that existing or newlydeveloped practices and procedures, are adequate to bring the views of all customers or 

other stakeholders before the board. Meeting this criterion will demonstrate that the RTO 

or ISO actively provides for presenting customer and other stakeholder issues, concerns, 

or proposals to its boards. 

507. The second criterion, fairness in balancing diverse interests, requires that each 

RTO and ISO ensures that its practices and procedures for decision making consider and 

balance the interests of their customers and stakeholders, and ensures that no single 

stakeholder group can dominate. This is necessary to ensure that the RTO or ISO may 

make well-informed decisions that reflect the full range of competing interests that may 

be affected. 

508. The third criterion, representation of minority interests to the RTO and ISO 

boards, is also critical to ensure that customers and other stakeholders have confidence in 

the decisions that come out of RTO and ISO processes. This criterion will ensure that the 

minority views of customers and stakeholders are forwarded, at the same time as the 

majority views, to the boards during the deliberation process. The Commission has often 

been notified that RTO and ISO decisions have been made based only on the single view 

of the majority vote. While the Commission will not intrude on the governance and 

decision-making process of RTO and ISO boards and management, it will require that 

those processes provide for appropriate consideration of minority interests. 

509. Finally, through the fourth criterion, ongoing responsiveness, the Commission will 

require that RTOs and ISOs continue over time to consider customer and other 
Docket Nos. RM07-19-000 and AD07-7-000 - 264 - 

stakeholder needs as the architecture or market environment of the RTO or ISO changes. 

This criterion is necessary to ensure that responsiveness continues into the future. As 

with the overall operations of each RTO and ISO, responsiveness to customers and other 

stakeholders should continually be evaluated for improvement. 

510. In response to comments, we clarify that compliance with each criterion must not 

diminish or limit the requirements for compliance with the remaining criteria. For 

example, in response to Ameren, we note that the third criterion does not mandate that 

minority interests overrule majority decisions, rather it requires that the board be made 

aware of the minority position where necessary. Taken together, the criteria require that 

RTO and ISO boards be fully aware of the positions of customers and other stakeholders 

to ensure that issues are fully and fairly vetted. 

b. Specificity of the Responsiveness Criteria

511. While some commenters state that the four responsiveness criteria should be more 

specific,610 others support the criteria as proposed, and we conclude that the Commission 

struck the appropriate balance in the NOPR. The Commission’s approach in addressing 

the responsiveness of RTO and ISO boards is to create a regulatory obligation for RTOs 

and ISOs to provide greater access in order to better serve the needs of customers and 

other stakeholders, and to leave the detailed implementation of this obligation for the 

RTOs and ISOs to work out with their own customers and other stakeholders. 

 610 See, e.g., APPA; ATC; California Munis; NRECA; and SMUD. 
Docket Nos. RM07-19-000 and AD07-7-000 - 265 - 

512. As was discussed in the NOPR, and the ANOPR prior to that, during the evolution 

of RTOs and ISOs, the Commission has allowed each RTO and ISO to develop the 

necessary operational practices that best suit the needs of its customers and other 

stakeholders. Differing market designs, governance structures, and existing stakeholder 

processes should be balanced with the need for independent decision making to provide 

the greatest benefits to customers and other stakeholders. To create a more expansive set 

of one-size-fits-all rules would undo that long-held determination. 

513. As a result, we do not agree with those commenters who contend that the criteria 

should be made more specific or set out in more detail. To the contrary, the requirements 

in this Final Rule will achieve the Commission’s goal: RTOs and ISOs will be obligated 

to demonstrate that they are responsive to the needs of customers and other stakeholders 

through a direct collaboration among the RTOs and ISOs and their constituencies. 

Therefore, to specify how an RTO or ISO would be expected to demonstrate compliance 

with the criteria, as requested by some commenters, would not be consistent with our 

stated objective in this section of the Final Rule. Upon each RTO’s or ISO’s submittal of 

its compliance filing, parties will be free to raise responsiveness issues specific to each 

RTO or ISO that they believe have not been resolved satisfactorily. With regard to 

Constellation’s request, we clarify that we define “customer” as is defined in the RTO’s 

or ISO’s tariff. 

514. Each RTO or ISO should consider in a collaborative process prior to the submittal 

of compliance filings the issues or methods that customers and other stakeholders want to 

raise that they believe will be helpful in satisfying the responsiveness criteria. As 
Docket Nos. RM07-19-000 and AD07-7-000 - 266 - 

suggested in comments filed on the NOPR, such issues and/or methods may include, but 

need not be limited to, changes of stakeholder processes, board selection methodologies, 

and monitoring and reporting on the effectiveness of the RTO or ISO in meeting the 

responsiveness criteria. 

c. Additional Criteria

515. We do not agree that additional criteria for responsiveness are necessary at this 

time. Many of the criteria commenters propose would require specific mandates from the 

Commission on items that could be resolved by RTOs and ISOs through their own 

stakeholder procedures. For example, establishing cost-containment requirements or 

requiring the application of cost/benefit analyses for each RTO or ISO decision in and of 

themselves are not measures of responsiveness, but rather are practices and procedures 

that are best developed through the collaborative efforts of each RTO or ISO and their 

respective customers and other stakeholders. Our objective in requiring RTOs and ISOs 

to demonstrate their responsiveness to customers and other stakeholders is to ensure that 

the RTOs and ISOs, in collaboration with their customers and other stakeholders, work 

toward developing regional solutions suited to the region’s needs. 

5. Board Advisory Committee and Hybrid Board

516. In the NOPR, the Commission emphasized that various approaches may satisfy the 

responsiveness criteria and encouraged each RTO or ISO to develop an approach that 

best suits its own governance structure and stakeholder needs. The Commission asked 

for comments on two proposed approaches for achieving board responsiveness—a board 

advisory committee composed of stakeholders and a hybrid board that includes both 
Docket Nos. RM07-19-000 and AD07-7-000 - 267 - 

independent and stakeholder members. The Commission indicated that a board advisory 

committee would be a particularly strong approach to improving RTO and ISO 

responsiveness.611

a. Comments

517. Commenters generally express support for the board advisory committee as a 

method of ensuring board responsiveness.612 They argue that the advisory committee is 

the better method of balancing the interests of stakeholders without sacrificing the 

independence of RTO or ISO boards. Others argue, however, that advisory boards do not 

always allow for meaningful input from stakeholders because they do not have decisional 

authority. 

518. National Grid urges the Commission to resist the inclination to micromanage RTO 

and ISO governance structure. It states that stakeholders who voluntarily participate in 

an RTO or ISO should be able to develop their own governance.613 National Grid states 

that the governance structures already in place among RTOs and ISOs are products of 

stakeholder agreements and the Commission should not overturn these compromises.614 

 611 NOPR, FERC Stats. & Regs. ¶ 32,628 at P 277. 

612 See, e.g., DRAM at 27; Duke Energy at 2-3; Exelon at 16-17; FirstEnergy at 

17; ITC at 12-13; Midwest ISO at 38; NARUC at 19; Old Dominion at 5; OMS at 17-18; 

Pennsylvania PUC at 20; PJM Power Providers at 12 (board liaison committee); and 

Steel Producers at 14. 

613 National Grid at 9. 

614 Id. at 10. 
Docket Nos. RM07-19-000 and AD07-7-000 - 268 - 

519. Several RTOs and ISOs note their support for the advisory board concept by 

pointing to their own existing advisory boards. For example, the Midwest ISO’s 

Advisory Committee consists of 23 representatives from nine stakeholder groups. The 

Advisory Committee is required to consider separately any measure that is the product of 

a close vote in committee.615 PJM states that it successfully worked with its stakeholders 

to develop and implement a Liaison Committee in 2007. PJM describes the Liaison 

Committee structure as an attempt to respect the Board’s independence in decision 

making while ensuring accountability and clear communication with the membership. 616

520. Commenters provide several suggestions to the Commission on how best to 

structure an advisory board. NARUC suggests that the Commission require that these 

advisory committees have open positions for state commissions and state consumer 

advocates.617 PJM Power Providers recommends that the Commission encourage RTOs 

or ISOs that select an advisory board approach to recognize diversity as an essential 

attribute for compliance with the Commission’s criteria. 

521. PJM Power Providers also suggests that representation on the advisory board 

should be subject to term limits to ensure diversity over time.618 PJM Power Providers 

urges that the Commission encourage representation on the advisory board to be limited 

 615 Midwest ISO at 38. 

616 PJM at 8. 

617 NARUC at 19. 

618 PJM Power Providers at 11. 
Docket Nos. RM07-19-000 and AD07-7-000 - 269 - 

to a defined period with rotating membership. PJM Power Providers recommends that no 

entity or its affiliates be permitted to have more than one representative on the board 

advisory committee simultaneously. The Midwest ISO TOs suggest that the advisory 

committee structure be changed so that transmission owners have a percentage of votes 

commensurate with the costs they would bear on major expenditures. DRAM agrees 

with the use of a representative board advisory committee and supports equal 

representation for demand resources.619 IID recommends the establishment of an 

advisory committee to the CAISO Board comprising voluntary representatives from 

neighboring balancing authority areas bordering or internal to the CAISO.620 

522. ATC suggests that the Commission should require stakeholder sector 

representatives to explain the degree to which a vote they cast was supported by their 

sector’s members, and why any minority within a sector disagreed with the majority 

position. ATC also recommends that RTOs and ISOs and their stakeholders should be 

allowed to propose exactly how sectors’ minority views on main stakeholder committee 

votes should be conveyed to RTO and ISO boards.621

523. Others comment on board selection and composition. The Pennsylvania 

Commission suggests that the Commission may wish to increase board responsiveness to 

 619 DRAM at 27. 

620 IID at 8-9. 

621 ATC at 9. IID also suggests that the Commission’s oversight would be aided 

by requiring RTOs and ISOs to report both majority and minority stakeholder positions to 

the Commission when they file proposed changes to their rates and tariffs. 
Docket Nos. RM07-19-000 and AD07-7-000 - 270 - 

stakeholders through modifications to the board nominating and selection process. It 

says that one approach might be to require that all board nominees be selected from an 

outside consultant’s list by a nominating committee that is largely or entirely composed 

of stakeholder representatives, and/or representatives of the states that the RTO or ISO 

serves. The Pennsylvania Commission further offers that the Commission should 

consider prohibiting RTO or ISO management from being part of, or participating in the 

deliberations of, the board member nominating committee; this will avoid obligating 

board members to management for their nomination or retention.622 

524. NSTAR states that while there are requirements for business and technical 

expertise to serve on the ISO New England board, there is no requirement that any of the 

members have any experience serving the customers who ultimately pay for the entire 

market. As a result, NSTAR requests that the Commission consider providing guidance 

on the composition of boards to include more consumer representatives.623 The Ohio 

Commission recommends that the Commission require each RTO and ISO to include on 

its board at least one individual with extensive state regulatory experience.624 Moreover, 

it states that the Commission should compel the RTO’s or ISO’s board to work with the 

relevant regional state advisory committee. 

 622 Pennsylvania PUC at 19. 

623 NSTAR at 10. 

624 Ohio PUC at 38. 
Docket Nos. RM07-19-000 and AD07-7-000 - 271 - 

525. Regarding hybrid boards, commenters are split on whether a hybrid board 

represents a valid approach to ensuring board responsiveness. Some commenters argue 

that a hybrid board is a good alternative to a board advisory committee, and would 

provide a good way for stakeholders to have input on RTO and ISO decision making. 

Many more commenters, however, argue that the Commission should not allow hybrid 

boards. They point to the potential to endanger the independence of the RTO or ISO 

board and to create conflict of interest for stakeholder board members. 

526. TAPS supports the hybrid board approach and says that, with adequate 

protections, appropriately structured hybrid boards are a better means of achieving a 

responsive, accountable RTO or ISO than another board advisory committee of 

stakeholders.625 TAPS also notes that, by making stakeholders vested partners in board 

decision making, hybrid boards can change the dynamic of the RTO or ISO, which, it 

claims, often pits stakeholders against the RTO or ISO. Industrial Consumers also 

support the hybrid board approach, and suggest that stakeholder members be split equally 

between representatives of supplier and consumer interests.626 

527. Other commenters object to the idea of hybrid boards. Industrial Coalitions state 

that hybrid boards would be unlikely to provide adequate representation for end-use 

customers, and would further diminish customers’ already limited voice in RTO and ISO 

governance. Industrial Coalitions argue that the proposed criteria for hybrid boards are 

 625 TAPS at 64. 

626 Industrial Consumers at 24. 
Docket Nos. RM07-19-000 and AD07-7-000 - 272 - 

not sufficient to prevent conflicts of interest on the part of board members.627 Also, 

NARUC argues that a hybrid board conflicts with the goal of RTO and ISO 

independence, and would be unwieldy and ineffective.628 

528. Duke Energy argues that hybrid boards could create the appearance of, and 

provide the opportunity for, undue preference in favor of stakeholder board members.629

ITC argues that mandating or allowing hybrid boards would be a mistake, as this would 

sacrifice RTO and ISO independence. ITC states that as long as the Commission allows 

hybrid boards, there will be tremendous pressure on RTOs and ISOs to form a hybrid 

board, or else be seen as being “unresponsive” by stakeholder groups. ITC argues that 

hybrid boards would violate the principles outlined in Order No. 890, and would allow 

stakeholders with no interest in new development to block transmission projects. ITC 

also states that hybrid boards will make it more difficult to develop appropriate 

transmission pricing systems; for example, stakeholder board members may seek to serve 

their own interests through allocation of new project costs to others. 

529. The Pennsylvania PUC also notes concern regarding stakeholder board members 

when the board may be required to review competitively sensitive information in making 

 627 Industrial Coalitions at 24-32. 

628 NARUC at 18-19. 

629 Duke Energy at 2-3. 
Docket Nos. RM07-19-000 and AD07-7-000 - 273 - 

decisions. It states that it is unclear how, or whether, non-independent members would 

be prevented from reviewing such material. 630 

530. FirstEnergy opposes giving particular stakeholder constituencies preferential 

rights or privileges under the name of responsiveness, and states that attempts by state 

commissions to elevate their stakeholder status to advice and approval over RTO or ISO 

initiatives represent a serious threat to RTO and ISO independence.631

531. OMS argues that allowing market participants to hold seats on an RTO or ISO 

board would jeopardize independence. OMS explains that stakeholder board members 

can be expected to act in the interests of the companies with which they are affiliated.632 

OMS is also concerned that the members of a hybrid board would create directors unable 

to fully and fairly exercise their business judgment consistent with general corporate 

governance law.633

532. PJM concurs that hybrid boards are a poor solution given the legal and practical 

pitfalls associated with these structures.634 PJM concludes that the NOPR does not 

 630 Pennsylvania PUC at 18. 

631 FirstEnergy at 17. 

632 OMS at 15. 

633 Id. at 15-16. 

634 PJM at 9. 
Docket Nos. RM07-19-000 and AD07-7-000 - 274 - 

demonstrate how the inherent conflicts in fiduciary duties (as well as issues of access to 

confidential data) would be resolved through a hybrid board structure.635

533. The California PUC is sympathetic to the Commission’s objectives to improve 

customer access to RTO and ISO boards of directors and believes that the Commission’s 

proposal of flexibility on this issue is appropriate. However, it states that the requirement 

that RTOs and ISOs establish a board advisory committee is preferred over the hybrid 

board approach and the CAISO already has such a mechanism in place and could easily 

demonstrate to the Commission that it already satisfies the objectives of the NOPR on 

this issue. 636 The California PUC also states that it is questionable whether the 

Commission has the legal authority to take the type of actions to reform RTO and ISO 

boards of directors that are being considered in the NOPR and urges the Commission to 

proceed only by means of an RTO- or ISO-specific adjudicative process under section 

206 of the Federal Power Act. It states that the creation of a hybrid board of directors 

would violate Order Nos. 888 and 2000, and that the Commission lacks legal authority to 

impose any reform pertaining to the makeup of the board of directors of a state-created 

ISO.637

 635 Id. at 10. 

636 Id. at 56. 

637 California PUC at 54. 
Docket Nos. RM07-19-000 and AD07-7-000 - 275 - 

b. Commission Determination

534. The Commission will not require RTOs or ISOs to adopt a specific form of board 

structure – whether board advisory committee, hybrid board, or other – in this rule or 

when evaluating their compliance filings to determine whether their existing or proposed 

structures and procedures are appropriately responsive to customers and other 

stakeholders. The Commission agrees with commenters that a one-size-fits-all approach 

is not appropriate, given the different needs of each region. As the Commission noted in 

the NOPR, it views the board advisory committee as a particularly strong mechanism for 

enhancing responsiveness, and expects each RTO and ISO to work with its stakeholders 

to develop the mechanism that best suits its needs. 

535. The Commission will not require, as proposed by the Ohio Commission, that at 

least one member of RTO or ISO boards have state regulatory experience. Similarly, the 

Commission will not require, as proposed by NARUC, that board advisory committees 

have open positions for state commissions and state consumer advocates. However, these 

suggestions may be considered by RTOs and ISOs during their own deliberations on 

compliance with this Final Rule. 

536. In response to the comments of California PUC, the Commission notes that the 

approach adopted in this Final Rule to require each RTO or ISO to submit a compliance 

filing demonstrating that it has in place or will adopt practices and procedures to ensure 

that its board of directors is responsive to customers and other stakeholders is within its 
Docket Nos. RM07-19-000 and AD07-7-000 - 276 - 

jurisdictional authority.638 The Commission is not mandating a specific approach such as 

a hybrid board of directors in this rulemaking, but is instead establishing a responsiveness 

objective that each RTO or ISO may meet in its own way. 

537. Several commenters argue that the Commission should not allow hybrid boards 

for legal or practical reasons, including concerns over the independence of RTO and ISO 

boards. The Commission denied similar requests to disallow hybrid boards in Order No. 

2000, noting that RTOs take many different forms to reflect the various needs of each 

region.639 The Commission found that a case-by-case review of each RTO board 

structure was best, with the general guidance that any board including market participants 

should ensure that no one class would be allowed to veto a decision reached by the rest of 

the board and that no two classes could force through a decision that is opposed by the 

rest of the board.640 We choose to follow our decision on hybrid boards in Order No. 

2000 here. As the Commission has found in other circumstances, a hybrid governance 

structure may be constructed in a way that allows for the expertise of various groups to 

inform the decision-making process, while still remaining independent such that no 

 638 See Order No. 2000, FERC Stats & Regs ¶ 31,089 at 31,039. 

639 Id. at 31,073-74. 

640 Id.
Docket Nos. RM07-19-000 and AD07-7-000 - 277 - 

individual market participant is given undue influence over the decisions of the board.641 

Our ruling here is not meant to imply that all hybrid board structures are acceptable. 

RTOs or ISOs wishing to adopt a hybrid board will have to show in their compliance 

filings that their proposals are consistent with the principles of Order No. 2000 and other 

relevant precedent. Commenters are free to raise any specific objections to a hybrid 

board proposal in response to the RTO’s or ISO’s compliance filing, and the Commission 

will be able to determine the validity of those objections against a concrete proposal from 

the RTO or ISO, if any such proposal is made. 

6. Supermajority Requirement

538. In the NOPR, the Commission requested comment on whether RTOs and ISOs 

should be encouraged (or required) to base their process for selecting non-independent 

members of a board advisory committee, or the board itself, on a supermajority vote of 

eligible stakeholders.

a. Comments

539. The few commenters that address the issue are split on whether the Commission 

should require members of advisory boards or hybrid boards to be chosen by a 

supermajority of stakeholders. Some commenters are skeptical of using a supermajority. 

Others, such as Steel Producers, believe that it could be beneficial for ensuring that 

 641 See Western Systems Coordinating Council, 96 FERC ¶ 61,348, at 62,296 

(2001) (approving a hybrid board for WECC). While the WECC is not an RTO, the 

Commission applied a similar standard to the formation of the WECC board as it applied 

to RTOs in Order No. 2000.) 
Docket Nos. RM07-19-000 and AD07-7-000 - 278 - 

minority perspectives are heard, as those elected to the board by a supermajority would 

be more likely to be responsive to viewpoints beyond those of their own company or 

stakeholder segment. Steel Producers argue that a supermajority voting requirement 

would provide “minority” stakeholders a meaningful voice and prevent one group of 

stakeholders from selecting a disproportionate number of board members.642

540. A few commenters suggest that supermajority requirements may be more useful 

for choosing representatives for specific market sectors; members of each market sector 

would be allowed to choose their own representatives by a supermajority rather than 

having voting among the RTO or ISO as a whole.643 Other commenters argue that the 

Commission should leave the decision on whether to require a supermajority to regional 

preference. 

541. On the other hand, Comverge is concerned that the use of a supermajority vote to 

choose board representatives would make it difficult to reconcile minority positions with 

demand response interests and suggests that the Commission consider support for 

separate board advisory committees that are intended primarily to represent demand 

response and demand-side resources.644

542. Xcel believes that the Commission should narrowly define “stakeholder” to ensure 

that a stakeholder is not simply any person in the room. For example, in some organized 

 642 Steel Producers at 14. 

643 See APPA; California Munis. 

644 Comverge at 24. 
Docket Nos. RM07-19-000 and AD07-7-000 - 279 - 

markets, e.g., the Midwest ISO, the advisory structure permits each stakeholder sector to 

ballot only within its own sector, which reduces the risk of one sector dominating the 

overall ballots.645 

543. SMUD indicates that its comments on the ANOPR urged adoption of requirements 

that: (1) the RTO or ISO give stakeholders a formal voting process to express their 

views, and (2) the RTO or ISO explain when it ignores supermajority sentiments.646 

SMUD claims that the NOPR’s more vague requirements are insufficient; thus specific 

directives should be set forth in any final action. 

544. PJM suggests that a supermajority requirement is not a necessary or sufficient one, 

and argues that the Commission should instead encourage RTOs or ISOs that choose to 

establish an advisory board to recognize diversity as an essential attribute for compliance 

with the Commission’s guidelines. 

545. Finally, ITC notes that a supermajority requirement, as suggested in the NOPR, 

may or may not be beneficial for hybrid boards and would further politicize the board 

selection process. Additionally, ITC argues that because advisory committees do not 

have decision making authority, a supermajority would not be necessary or appropriate 

for choosing advisory committee members.647

 645 Xcel at 14. 

646 Id. at 12. 

647 ITC at 12-13. 
Docket Nos. RM07-19-000 and AD07-7-000 - 280 - 

b. Commission Determination

546. The Commission will leave it to each RTO or ISO, in consultation with its 

customers and other stakeholders, whether to select by supermajority vote members of 

any board advisory committee or any non-independent board member. When 

determining whether to implement a supermajority requirement, RTOs and ISOs should 

consider the goals of achieving a voice for minority interests while also having a 

workable process. 

7. Posting Mission Statement or Organizational Charter on Web

Site

547. In the NOPR, the Commission proposed to require that each RTO and ISO post on 

its web site a mission statement or charter for its organization. The Commission 

encouraged each RTO and ISO to set forth in either the mission statement or the 

organizational charter its 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. 

a. Comments

548. Most commenters who discuss the topic indicate that they support the 

Commission’s proposed requirement for RTOs or ISOs to post a mission statement or 

organizational charter on their web sites. Both CAISO and NYISO report that they 

already post mission statements on their web site.648 

 648 CAISO at 12; NYISO at 18. 
Docket Nos. RM07-19-000 and AD07-7-000 - 281 - 

549. Other commenters provide additional thoughts on RTO and ISO mission 

statements on a more general level. Constellation also supports having a requirement that 

each RTO and ISO publish a mission statement setting forth the organization’s purpose, 

guiding principles, and commitment to responsiveness to customers and other 

stakeholders. It advocates that the mission statement should reflect and include the 

minimum characteristics and functions that the Commission has required for each RTO 

and ISO in Order No. 2000.649 

550. North Carolina Electric Membership requests that the Commission require RTOs 

and ISOs revisit their mission statements to ensure that the statements are consistent with 

the Order No. 2000 core objectives. It asserts that paramount among the core objectives 

should be the twin goals of facilitating open access to the transmission grid and providing 

reliable electric service at an affordable cost to consumers. North Carolina Electric 

Membership adds that the mission statements should also set forth defined roles for the 

RTO and ISO boards and management, as well as defined roles for stakeholders in 

accomplishing the objectives set forth in those statements. Old Dominion also sees value 

in defining within the mission statement the roles of the board, RTO and ISO 

management and stakeholders to provide the clarity necessary to be sure that the 

organization is aligned with the RTO’s and ISO’s mission.650 

 649 Constellation at 19. 

650 Old Dominion at 5. 
Docket Nos. RM07-19-000 and AD07-7-000 - 282 - 

551. NRECA and Old Dominion argue that RTOs and ISOs should be required to 

include their mission statements in their tariffs and that the mission statements should 

include a focus on lowering costs for transmission and wholesale power customers. 

NRECA notes that absent from the mission statements currently posted on many RTO 

and ISO web sites is a focus on ensuring that overall costs to consumers are consistent 

with the objective of ensuring just and reasonable rates for consumers.651 

552. Steel Producers note that an RTO’s or ISO’s mission statement and/or charter 

should not be utilized by the RTO and ISO, its stakeholders, or market participants to 

limit the range or scope of potential issues that the RTO or ISO and/or its respective 

stakeholder group(s) may need to address. They conclude that mission statements and 

charters should provide guidance, but should not foreclose discussion and action on 

pertinent matters of interest. 652

553. TAPS asserts that “the Final Rule should require each RTO to file a mission 

statement that makes it accountable to consumers for meeting the purposes of the Federal 

Power Act.”653 TAPS argues that the Federal Power Act’s purpose is to ensure that 

electricity consumers pay the lowest prices possible for reliable service. TAPS concludes 

that by establishing consumer value as a core goal for RTOs and ISOs, the Commission 

 651 NRECA at 62. 

652 Steel Producers at 14-15. 

653 TAPS at 60. 
Docket Nos. RM07-19-000 and AD07-7-000 - 283 - 

would align the goals of these regional organizations with the objectives of state 

regulators, federal policy makers, and consumers. 

554. SMUD states that the NOPR failed to further discuss the issue of whether RTOs 

and ISOs should be required to publish a strategic plan, as was raised in the ANOPR. 

SMUD avers, however, that such a requirement is implicit in the NOPR discussion where 

RTOs and ISOs would be required to show that they have satisfied the criteria, including 

responsiveness to stakeholders. SMUD requests that the Commission clarify that its 

intent was to require RTOs and ISOs to publish strategic plans. 

555. FirstEnergy opposes an RTO or ISO mission statement that deviates from the 

contractual and tariff obligations under which the RTO or ISO currently operates, and 

states that any effort to adopt such a statement would be problematic, and a source of 

additional and unneeded controversy among RTO and ISO stakeholders. 654

b. Commission Determination

556. The Commission will require each RTO and ISO to post on its web site a mission 

statement or organizational charter. The Commission encourages each RTO and ISO to 

include in its mission statement, among other things, the organization’s purpose, guiding 

principles, and commitment to responsiveness to customers and other stakeholders, and 

ultimately to the consumers who benefit from and pay for electricity services. The 

mission statement or organizational charter may include additional information, such as 

elements from the RTO or ISO governing documents. The Commission does not expect 

 654 FirstEnergy at 17. 
Docket Nos. RM07-19-000 and AD07-7-000 - 284 - 

that any explicit statement of the responsiveness objective would conflict with existing 

elements of the RTO’s or ISO’s mission. 

557. We find that this requirement will improve communication between RTOs and 

ISOs and their stakeholders and the community at large, as well as provide a statement of 

goals by which the RTO’s and ISO’s progress may be judged. If any RTO or ISO 

believes that there is a conflict between this requirement and the existing mission 

statement, contracts or tariff, the RTO or ISO may address this conflict in its compliance 

filing. In response to SMUD, we clarify that publication of a strategic plan is not implicit 

in the responsiveness obligation. 

8. Executive Compensation

558. In the NOPR, the Commission encouraged, but did not propose to require, each 

RTO and ISO to ensure that its management programs, including, but not limited to, 

incentive compensation plans for executive managers, give appropriate weight to 

stakeholder responsiveness. 

a. Comments

559. Commenters generally agree that RTOs and ISOs should link compensation plans 

for executive managers to customer service measures of performance, as indicated by 

customer satisfaction surveys and complying with the responsiveness criteria. 

560. LPPC asks for establishment of objective criteria for performance and executive 

compensation.655 Additionally, North Carolina Electric Membership argues that the Final 

 655 LPPC at 18. 
Docket Nos. RM07-19-000 and AD07-7-000 - 285 - 

Rule should require RTOs and ISOs to demonstrate that their executive management 

incentive programs are tied to their mission statements, including a focus on improving 

customer service, properly managing their markets, being responsive and accountable to 

stakeholders and consumers, and providing consumers with reliable service at an 

affordable cost.656

b. Commission Determination

561. The Commission continues to encourage, but not require, each RTO and ISO to 

ensure that its management programs, including executive compensation, give 

appropriate weight to responsiveness to customers and other stakeholders. If the RTO or 

ISO board is well-informed about the needs of customers and various stakeholders, it will 

set criteria for performance, appropriate goals and targets for the organization and its 

management and institute measures for achieving those targets. By focusing our 

requirements on having a well-informed board, we decline to intrude further into board 

prerogatives regarding management compensation. 

9. Compliance Filing Requirement

562. In the NOPR, the Commission determined that each RTO or ISO must comply 

with this proposed requirement by submitting a filing that proposes changes to its board 

responsiveness practices and procedures to comply with the proposed criteria or that 

demonstrates its practices and procedures already satisfy the criteria for board 

 656 North Carolina Electric Membership at 25-26. 
Docket Nos. RM07-19-000 and AD07-7-000 - 286 - 

responsiveness.657 This filing would be submitted within six months of the date the Final 

Rule is published in the Federal Register. The Commission also stated that it will assess 

whether each filing satisfies the proposed requirement and issue additional orders as 

necessary. 

a. Comments

563. Most commenters support a compliance filing requirement. However, some 

commenters expressed concern that RTOs and ISOs will merely submit documentation 

asserting that their existing processes already satisfy the responsiveness criteria, without 

working seriously with stakeholders to ensure that stakeholder input is sought on 

compliance. The California PUC states that it believes that CAISO already meets the 

requirements of the NOPR and asks the Commission to refrain from taking any further 

action regarding the responsiveness of RTOs and ISOs to stakeholders and customers 

needs.658 

564. Industrial Coalitions state that the Final Rule should not delegate to the RTO or 

ISO stakeholder processes the task of working out the details of the Commission's 

proposals. Industrial Coalitions are concerned that the Commission's approach will delay 

resolution of these important matters, to the detriment of customers. Accordingly, 

 657 NOPR, FERC Stats. & Regs. ¶ 32,628 at P 276. 

658 California PUC at 56. 
Docket Nos. RM07-19-000 and AD07-7-000 - 287 - 

Industrial Coalitions urge the Commission to provide clear and consistent directives 

regarding the subject matter and timing of the RTO and ISO compliance filings.659

b. Commission Determination

565. The Commission requires each RTO or ISO to make a compliance filing that 

proposes changes to its responsiveness practices and procedures to comply with the 

responsiveness requirement or that demonstrates that its practices and procedures already 

satisfy the requirement for responsiveness. The compliance filing also must propose 

posting, or report the posting, of the RTO’s or ISO’s mission statement or organizational 

charter on its respective web site. This filing shall be submitted within six months of the 

date this Final Rule is published in the Federal Register. 

566. We recognize that many of the existing RTOs and ISOs have a form of committee 

(whether advisory board or stakeholder committee) that functions within the RTO or ISO 

governance structure to provide stakeholder feedback. Given the number of comments 

from interested parties seeking improvement to their interactions with RTO and ISO 

boards and the effectiveness of these committees, it is important that the compliance 

filings required herein follow from consultation with customers and other stakeholders 

regarding satisfaction with existing processes and the appropriateness of improved 

processes. In the end, however, the filing is the RTO’s or ISO’s to make; we urge them 

to seek consensus but realize that complete agreement is not always achievable. This 

 659 Industrial Coalitions at 4. 
Docket Nos. RM07-19-000 and AD07-7-000 - 288 - 

consultation process is worth additional time and effort, and should not cause an 

excessive delay, given the six-month time allowed for filing. 

567. Each RTO or ISO should explain in its compliance filing how it plans to satisfy, or 

currently satisfies, each responsiveness criterion. Furthermore, each RTO and ISO 

should include in its compliance filing, for each criterion, an explanation of the process 

(e.g., stakeholder meetings, technical conferences, board discussions) that the RTO and 

ISO used to develop its compliance filing demonstration and describe major dissenting 

views. In the event RTOs or ISOs, working with their customers and other stakeholders, 

complete the responsiveness compliance requirements in less than six months, they may 

file them ahead of the specified due date. The Commission will assess whether each 

filing satisfies the proposed requirement and issue additional orders as necessary. 

E. Other Comments

1. Comments

568. A few commenters address topics other than the specific proposals in the NOPR. 

For example, some suggest we require, or promote as part of the Final Rule, the review of 

RTO and ISO seams and rate levels, performance benchmarking, moratoriums on new 

RTO or ISO products and services, cost-benefit analyses,660 time-sensitive rates for 

transmission and other non-market services with marginal costs caused by on-peak 

 660 AMPA at 2-6; APPA at 10, 19, 102-03; Indianapolis P&L at 5; Industrial 

Coalitions at 23-24. 
Docket Nos. RM07-19-000 and AD07-7-000 - 289 - 

usage,661 interconnection requirements,662 tariff filings, and reviews related to the design 

and scope of independent operational audits of RTOs and ISOs.663 CAISO and the Cities 

filed reply comments in opposition to implementing time-sensitive rates.664

569. First Energy is opposed to RTOs and ISOs recovering from market participants 

penalties for NERC reliability violations caused by RTOs.665

570. Another commenter asked that the Commission avoid, to the extent possible, 

requiring compliance filings at times when RTOs and ISOs are focused on start up of 

new markets.666

571. In its comments, Sorgo expresses concern that the April 2007 Report to Congress 

on Competition in Wholesale and Retail Markets failed to address anticompetitive 

policies that may favor old power plants.667

572. Allied Public Interest Groups states that the Commission should direct RTOs and 

ISOs to give comparable consideration to demand response resources in regional 

 661 California DWR at 3, 21-36, and 38-39. 

662 American Forest at 2. 

663 Joint Commenters at 6-10. 

664 CAISO and the Cities at 3. 

665 FirstEnergy at 19. 

666 Ameren at 16. 

667 Sorgo at 1. The April 2007 Report to Congress on Competition in Wholesale 

and Retail Markets was developed by the Electric Energy Market Competition Task 

Force as directed by Section 1815 of the Energy Policy Act of 2005. 
Docket Nos. RM07-19-000 and AD07-7-000 - 290 - 

planning, and that regional planning should include scenario analyses evaluating the 

amounts of potentially available demand response resources.668

2. Commission Determination

573. The Commission appreciates the efforts involved in developing these comments 

and proposals submitted in this rulemaking. We note that these topics have already been 

addressed by the Commission in Order No. 890669 and Order No. 693.670 Accordingly, 

the Commission declines to expand the scope of this proceeding to encompass topics not 

presented in the NOPR. RTOs and ISOs and their stakeholders may address these topics, 

if they so choose, through their own processes for evolving RTO and ISO services and 

markets. 

IV. Applicability of the Final Rule and Compliance Procedures

A. NOPR Proposal

574. In the NOPR, the Commission proposed to apply the Final Rule to all RTOs and 

ISOs, and to require them to demonstrate compliance with the requirements in each of the 

 668 Allied Public Interest Groups at 13-14. 

669 Order No. 890 requires any public utility with an OATT to allow qualified 

demand response resources to participate in its regional transmission planning process on 

a comparable basis to generation resources and to allow qualified demand response to 

provide certain ancillary services. Order No. 890, FERC Stats. & Regs. ¶ 31,241 at P 

479, 494, and 888. 

670 Order No. 693 requires the Electricity Reliability Organization to revise its 

reliability standards so that all technically feasible resource options, including demand 

response and generating resources, may be employed in the management of grid 

operations and emergencies. Order No. 693, FERC Stats. & Regs. ¶ 31,242. 
Docket Nos. RM07-19-000 and AD07-7-000 - 291 - 

four sections of the Final Rule.671 The Commission proposed to require each RTO and 

ISO to file a report to the Commission within six months of the Final Rule’s effective 

date, or six months following its certification as an RTO or commencement of operations 

as an ISO. The Commission proposed that the compliance filing should describe whether 

the RTO or ISO already complies with the requirements of the Final Rule, or describe the 

entity’s plans to attain compliance, including a timeline with intermediate deadlines and 

appropriate proposed tariff and market rule revisions. The Commission noted that it 

would assess whether each filing satisfies the proposed requirements and issue further 

orders for each RTO and ISO, as necessary. 

B. Comments

575. The Commission received few comments on the applicability and compliance 

proposals. Ameren notes that the six-month period for compliance may coincide with the 

implementation period for the Midwest ISO’s Ancillary Services Market. Accordingly, 

Ameren argues that the Commission should avoid, to the extent possible, requiring 

compliance filings at times when RTOs and ISOs are focused on the start of new 

markets.672

576. CAISO requests clarification from the Commission as to whether the six-month 

compliance deadline is intended to apply to those market enhancements that CAISO 

already has planned under its Market Redesign and Technology Upgrade. CAISO notes 

 671 NOPR, 122 FERC ¶ 61,167 at P 283. 

672 Ameren at 16. 
Docket Nos. RM07-19-000 and AD07-7-000 - 292 - 

that many of these upgrades, including allowing demand response to supply ancillary 

services and implementing enhanced shortage pricing, are on a separate timeline 

approved by the Commission.673

577. NYISO states that it supports the compliance deadlines in the NOPR, and calls on 

the Commission to reject any proposal calling for shorter compliance periods. NYISO 

notes that given the number of changes to RTO or ISO market software, billing practices 

and organizational functions that would be required by the Final Rule, along with the 

time required to consult with stakeholders, the proposed deadlines are the minimum 

necessary time for preparation of compliance filings.674

C. Commission Determination

578. As we proposed in the NOPR, we will require RTOs and ISOs to make a 

compliance filing within six months of the date that this Final Rule is published in the 

Federal Register. RTOs and ISOs should work with stakeholders and interested parties, 

where applicable, to comply with this rule and to develop their compliance filings. 

579. The six-month period appropriately recognizes that it is important for RTOs and 

ISOs to work with stakeholders and other interested parties to develop a compliance 

filing, and that (as NYISO contends) such processes take time. In response to Ameren 

and CAISO, we clarify that the compliance requirement is not meant to displace the 

timelines of any market improvements that RTOs or ISOs are currently undertaking. 

 673 CAISO at 2. 

674 NYISO at 22. 
Docket Nos. RM07-19-000 and AD07-7-000 - 293 - 

Each RTO and ISO should include in its compliance filing an update on the status of any 

relevant market design changes that are in the process of being implemented and address 

any remaining issues not addressed by the ongoing changes. It need not change the 

schedule for implementing these other market design changes as a result of this Final 

Rule. 

580. The compliance filing should explain the action the RTO or ISO has taken, or 

plans to take, to comply with the requirements in each of the four sections of this Final 

Rule. It should also describe, where applicable, the process used to develop the 

compliance filing and describe any major dissenting views. The Commission will 

evaluate each compliance filing to determine whether it satisfies the requirements in this 

rule, and issue additional orders as necessary. 

581. As described above, RTOs and ISOs, in cooperation with their customers and 

stakeholders, also are required to perform an assessment, through pilot projects or other 

mechanisms, of the technical feasibility and value to the market of smaller demand 

response resources providing ancillary services, including whether (and how) smaller 

resources can reliably and economically provide operating reserves and report their 

findings to the Commission. This assessment is due to the Commission within one year 

of the date that this Final Rule is published in the Federal Register. 

582. Finally, as described above, each RTO’s and ISO’s market monitoring unit is 

required to comment on the adequacy of market mitigation measures in its respective 

RTO’s or ISO’s shortage pricing proposal. This requirement will aid the Commission in 

evaluating the proposals once they are filed. 
Docket Nos. RM07-19-000 and AD07-7-000 - 294 - 

583. In response to commenters who argue that the six-month requirement for 

submission of a compliance filing is either too long or too short, we find that the sixmonth period is an adequate amount of time for an RTO or ISO to work with 

stakeholders and other interested parties to develop a compliance filing. We note that 

RTOs and ISOs may make their compliance filing at any time prior to the end of the sixmonth period. 

V. Information Collection Statement 

584. The Office of Management and Budget (OMB) regulations require approval of 

certain information collection requirements imposed by agency rules.675 Upon approval 

of a collection(s) of information, OMB will assign an OMB control number and an 

expiration date. Respondents subject to the filing requirements of this rule will not be 

penalized for failing to respond to these collections of information unless the collections 

of information display a valid OMB control number. This Final Rule amends the 

Commission’s regulations to improve the operation of organized wholesale electric 

power markets. The objective of this Final Rule is to improve market design and 

competition in organized markets. Through this rule the Commission hopes to provide 

remedies by: (1) ensuring that new criteria are established so that RTOs and ISOs are 

responsive to their customers and stakeholders; (2) improving market monitoring within 

RTOs and ISOs by requiring them to provide their Market Monitoring Units with access 

to market data and sufficient resources to perform their duties; (3) providing transparency 

 675 5 CFR 1320.11. 
Docket Nos. RM07-19-000 and AD07-7-000 - 295 - 

in the marketplace by requiring RTOs and ISOs to dedicate portions of their web sites so 

market participants can avail themselves of information concerning offers to buy or sell 

power on a long-term basis; and (4) requiring RTOs and ISOs to institute certain reforms 

in the demand response programs to remove several disincentives and barriers to demand 

response so as to provide for more efficient operation of markets and encourage new 

technologies. Filings by RTOs and ISOs would be made under Part 35 of the 

Commission’s regulations. The information provided for under Part 35 is identified as 

FERC-516. 

585. The Commission is submitting these reporting requirements to OMB for its review 

and approval under section 3507(d) of the Paperwork Reduction Act.676 The 

Commission solicited comments on the Commission’s need for this information, whether 

the information will have practical utility, the accuracy of provided burden estimates, 

ways to enhance the quality, utility, and clarity of the information to be collected, and any 

suggested methods for minimizing the respondent’s burden, including the use of 

automated information techniques. The Commission did not receive comments 

specifically addressing the burden estimates in the NOPR. Therefore we will use the 

same estimates here as in the NOPR. 

Burden Estimate: The Public Reporting burden for the requirements contained in the 

Final Rule is as follows: 

 676 44 U.S.C. 3507(d). 
Docket Nos. RM07-19-000 and AD07-7-000 - 296 - 

Data Collection Number of 

Respondents 

Number of 

Responses. 

Hours Per 

Response 

Total Annual 

Hours 

FERC-516 

Task 

Allow demand 

response to 

provide certain 

ancillary services 

6 1 433 

 

 2,598 

Remove certain 

deviation charges 

5 1 288 

 

 1,440 

Permit 

aggregation of 

Retail Customers 

6 1 102.5 615 

Allow pricing to 

ration demand 

during a shortage 

6 1 649 3,894

Long-term 

contract postings 

6 1 30 180 

MMUs 6 1 129 774 

Require RTO 

board 

responsiveness to 

customers 

6 1 180 1080 

Require RTO 

self-assessment 

6 1 650 3,900 

Totals 14,481 hours 

Total Annual Hours for Collection: (Reporting + recordkeeping, (if appropriate)) = 

Total hours for performing tasks 1 through 8 as identified above = 14,481 hours. 

Information Collection Costs: The average annualized cost677 is expected to be: 

Legal expertise = $473,526 (2,368 hours @$200 an hour) 

Technical Expertise = $712,038 (4,747 hours @$150 an hour) 

(RTO/ISO Senior Staff, Stakeholder participants) 

Administrative Support = $108,701 (2,718 hours @$40 an hour) 

 677 Differences in RTO/ISO staff hourly rates are to differentiate between 

administrative support staff and senior staff. 
Docket Nos. RM07-19-000 and AD07-7-000 - 297 - 

IT Support = $236,448 (2,489 hours @$95 an hour) 

Participatory Expenditures = $2,160,000 (96 participants @$1,000 per day on average 

4.5 days per activity for five of the eight activities identified above). 

Total = $3,690,713 

Title: FERC-516 “Electric Rate Schedule Filings.” 

Action: Proposed Collections. 

OMB Control No: 1902-0096 

Respondents: Business or other for profit, and/or not for profit institutions. 

Frequency of Responses: An initial filing to comply with the rule, and then on occasion 

as needed to revise or modify. 

Necessity of the Information: This Final Rule furthers the improvement of competitive 

wholesale electric markets and the provision of transmission services in the RTO and ISO 

regions. The Commission recognizes that significant differences exist among the 

regions, industry structures, and sources of electric generation, population demographics 

and even weather patterns. In fulfilling its responsibilities under sections 205 and 206 of 

the Federal Power Act, the Commission is required to address, and has the authority to 

remedy, undue discrimination and anticompetitive effects. 

586. Interested persons may obtain information on the reporting requirements by 

contacting: Federal Energy Regulatory Commission, 888 First Street, N.E., Washington, 

D.C. 20426 [Attention: Michael Miller, Office of the Executive Director, Phone: (202) 

502-8415, fax: (202) 273-0873, e-mail: <michael.miller@ferc.gov>]. Comments on the 

requirements of the proposed rule may also be sent to the Office of Information and 
Docket Nos. RM07-19-000 and AD07-7-000 - 298 - 

Regulatory Affairs, Office of Management and Budget, Washington, D.C. 20503 

[Attention: Desk Officer for the Federal Energy Regulatory Commission, fax (202) 395-

7285, email: <oira_submission@omb.eop.gov>]. 

VI. Environmental Analysis

587. The Commission is required to prepare an Environmental Assessment or an 

Environmental Impact Statement for any action that may have a significant adverse effect 

on the human environment.678 The Commission concludes that neither an Environmental 

Assessment nor an Environmental Impact statement is required for this Final Rule under 

section 380.4(a)(15) of the Commission’s regulations, which provides a categorical 

exemption for approval of actions under sections 205 and 206 of the FPA relating to the 

filing of schedules containing all rates and charges for the transmission or sale subject to 

the Commission’s jurisdiction, plus the classification, practices, contracts, and 

regulations that affect rates, charges, classifications, and services.679

VII. Regulatory Flexibility Act Certification

588. The Regulatory Flexibility Act of 1980 (RFA)680 generally requires a description 

and analysis of rules that will have significant economic impact on a substantial number 

of small entities. The RFA does not mandate any particular outcome in a rulemaking. It 

 678 Regulations Implementing the National Environmental Policy Act, Order No. 

486, FERC Stats. & Regs. ¶ 30,783 (1987). 

679 18 CFR 380.4(a) (15). 

680 5 U.S.C. 601-12. 
Docket Nos. RM07-19-000 and AD07-7-000 - 299 - 

only requires consideration of alternatives that are less burdensome to small entities and 

an agency explanation of why alternatives were rejected. 

589. In drafting a rule an agency is required to: (1) assess the effect that its regulation 

will have on small entities; (2) analyze effective alternatives that may minimize a 

regulation’s impact; and (3) make the analyses available for public comment.681 In its 

NOPR, the agency must either include an initial regulatory flexibility analysis (initial 

RFA)682 or certify that the proposed rule will not have a “significant impact on a 

substantial number of small entities.”683 

590. If in preparing the NOPR an agency determines that the proposal could have a 

significant impact on a substantial number of small entities, the agency shall ensure that 

small entities will have an opportunity to participate in the rulemaking procedure.684

591. In its Final Rule, the agency must either prepare a Final Regulatory Flexibility 

Analysis (Final RFA) or make the requisite certification. Based on the comments the 

agency receives on the NOPR, it can alter its original position as expressed in the NOPR, 

but it is not required to make any substantive changes to the proposed regulation. 

592. The statute provides for judicial review of an agency’s final certification or Final 

RFA.685 An agency must file a Final RFA demonstrating a “reasonable, good-faith 

 681 5 U.S.C. 601-604. 

682 5 U.S.C. 603(a). 

683 5 U.S.C. 605(b). 

684 5 U.S.C. 609(a). 
Docket Nos. RM07-19-000 and AD07-7-000 - 300 - 

effort” to carry out the RFA mandate.686 However, the RFA is a procedural, not a 

substantive, mandate. An agency is only required to demonstrate a reasonable, goodfaith effort to review the impact the proposed rule would place on small entities, any 

alternatives that would address the agency’s and small entities concerns and their impact, 

provide small entities the opportunity to comment on the proposals, and review and 

address comments. An agency is not required to adopt the least burdensome rule. 

Further, the RFA does not require the RFA to assess the impact of a rule on all small 

entities that may be affected by a rule, only on those entities that the agency directly 

regulates and that will be directly impacted by the rule.687

A. NOPR Proposal

593. In the NOPR, the Commission stated that most, if not all, of the transmission 

organizations to which this rule would apply do not fall within the definition of small 

entities.688 The Commission identified the characteristics of each of those organizations 

and all exceeded the standard size definition established in NAICS.689 It should be noted 

 685 5 U.S.C. 611. 

686 United Cellular Corp. v. FCC, 254 F.3d 78, 88 (D.C. Cir. 2001); Alenco

Communications, Inc. v. FCC, 201 F.3d 608, 625 (5th Cir. 2000). 

687 Mid-Tex Electric Coop., Inc. v. FERC, 773 F.2d 327 (D.C. Cir. 1985) (MidTex). 

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

689 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 

 (continued...) 
Docket Nos. RM07-19-000 and AD07-7-000 - 301 - 

that due to typographical error in the NOPR, footnote 292 omitted the word “million”

when identifying the size standard applicable to utilities. 

594. One of those requirements proposed in the NOPR was that “RTO and ISOs must 

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.”690 The Commission reasoned that such action would reduce 

obstacles for small retail loads to be able to participate in organized markets by allowing 

ARCs to assemble small demand responses that individually are too small to qualify for 

bidding into an RTO or ISO organized market and having ARCs assume many of the 

administrative tasks that retail customers may lack the resources or cannot afford. 

Simultaneously, as the Commission pointed out from comments received in response to 

its ANOPR, ARCs can reduce the RTO’s and ISO’s administrative burden of managing 

individual customers’ demand response participation.691 

 

Business Size Standards component of the North American Industry Classification 

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

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

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

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

(2004). 

690 NOPR, FERC Stats. & Regs. ¶32,628 at P 86. 

691 Id. P 83. 
Docket Nos. RM07-19-000 and AD07-7-000 - 302 - 

595. Thus, in the NOPR, based on comments to the ANOPR, the Commission sought to 

ameliorate administrative burdens on small entities, specifically small retail customers to 

be able to participate in organized market and access demand response programs. 

1. Comments

596. APPA and TAPS argue that the inclusion of ARCs, while assisting small retail 

customers, disproportionately shifts the burden to relevant electric retail regulatory 

authorities. APPA does not support the Commission’s proposal that RTOs presume that 

aggregation is allowed unless the relevant electric retail regulatory authority informs the 

RTO that it does not permit aggregation.692 APPA provides data on the number of power 

systems providing retail service in RTO regions and states that the vast majority of these 

are small utilities within the meaning of the RFA.693

597. TAPS, while recognizing the Commission’s efforts, also has concerns about the 

Commission’s proposal. TAPS believes the “proposal would place undue burdens on 

many individual nonregulated electric utilities to take affirmative regulatory actions to 

maintain their authority. . . . ”694 TAPS believes that if relevant electric retail regulatory 

authorities must assume the responsibility to notify RTOs then this places undue burden 

on municipal entities to become involved in lengthy legislative processes to make 

 692 APPA at 3. 

693 Id. at 3. 

694 TAPS at 13 
Docket Nos. RM07-19-000 and AD07-7-000 - 303 - 

determinations that may have already been made on whether ARC’s may aggregate the 

demand response of the municipals’ loads.695 

598. APPA believes the Commission is giving the RTOs and ISOs authority to trump 

state and local laws and regulations when it allows RTOs and ISOs to accept bids from an 

ARC whether or not the laws and regulations of the relevant electric retail regulatory 

authority explicitly permits it.696 APPA believes that the retail regulatory authority will 

be placed in the position of having to make an administrative finding of whether 

aggregation by ARCs of retail end users is to be permitted. By APPA’s count, only a 

small proportion of the 1,315 public power systems that provide retail electric service in 

states served by RTOs and ISOs have such laws or regulations. For the majority, this 

would result in a huge learning curve to become familiar with the process and 

consequently result in a “very substantial undertaking.”697 APPA estimates that 

approximately 1,307 of the power distribution systems located in states served by RTOs 

and ISOs are “small utilities” as the term is defined in the RFA. To require relevant 

electric retail regulatory authorities to consider an affirmative pronouncement on this 

issue is “cumulatively a very substantial FERC-imposed burden on them.”698

 695 Id. at 17. 

696 APPA at 43. 

697 Id. at 44. 

698 Id. at 45. 
Docket Nos. RM07-19-000 and AD07-7-000 - 304 - 

599. APPA believes that unless a system’s relevant electric retail regulatory authority 

affirmatively informs an RTO or ISO that it permits such aggregation by third-party 

ARCs, the RTO or ISO should be required to assume that such aggregation is not 

permitted. Should the Commission not accept APPA’s proposal, as an alternative APPA 

suggest that for relevant electric retail regulatory authorities governing public power 

systems located in RTO and ISO regions that exceed the RFA size requirement, they 

would have to consider the issue of third-party ARCs and aggregation of their retail 

customers. In the case of public power systems that do not meet the RFA size 

requirement, then the RTO or ISO would be responsible for making the assumption that 

aggregation by ARCs is not permitted.699

600. TAPS takes a similar position. It believes the NOPR can be interpreted to require 

municipal systems to take legislative or regulatory action specific to the third-party ARC 

issue and notify the RTO or ISO. For these municipal systems to respond particularly 

when they do not allow retail access will impose significant burdens on them. As an 

indication of the potential impact, TAPS identified the number of municipal systems 

served by their members including AMP-Ohio with 122 municipal electric systems in 

both Midwest ISO and PJM; Indiana Municipal Power Agency, which serves 51 

municipal electric systems in Midwest ISO; and Wisconsin Public Power Inc. which 

serves 50 municipal electric systems in Midwest ISO.700 TAPS reminds the Commission 

 699 Id. at 47. 

700 TAPS at 19. 
Docket Nos. RM07-19-000 and AD07-7-000 - 305 - 

that Congress, through passage of the RFA, requires agencies to assess the impact on 

entities whose total electric output does not exceed 4 million MWh. TAPS notes that the 

Commission’s certification in the NOPR recognized this responsibility, but failed to 

account for “the hundreds of small entities that it proposes to effectively put through this 

legislative or regulatory process.”701

601. TAPS believes the Commission can achieve its objective by rewording its 

requirement to have relevant electric retail regulatory authorities notify the RTO or ISO 

when they permit third-party ARCs. Unless there is a notification, the RTO or ISO is to 

assume that third-party aggregation is not permitted. By shifting the emphasis as to when 

the notification is to take place, hundreds of municipals would not be burdened by having 

to go through the legislative process. In addition, only systems with a total electric 

output exceeding 4 million MWh would have to go through the process. TAPS also 

proposes an additional alternative, namely that municipals with retail sales of more than 

500 million kWh as specified in PURPA would have to go through the process.702

2. Commission Determination

602. The Final Rule is applicable to all RTOs and ISOs. The Commission is requiring 

each RTO and ISO to make certain filings that reflect amendments to their tariffs to 

demonstrate they have either incorporated, or already have in place, processes that 

implement the requirements of this Final Rule. None of these entities, as identified in the 

 701 Id. at 20. 

702 Id.
Docket Nos. RM07-19-000 and AD07-7-000 - 306 - 

NOPR, meets the RFA definition of a small entity -- in particular, the last criterion of the 

definition “and which is not dominant in its field of operation.”703 

603. In Mid-Tex, the court accepted the Commission’s conclusion that, since virtually 

all of the public utilities that it regulates do not fall within the meaning of the term “small 

entities” as defined in the RFA, the Commission did not need to prepare a regulatory 

flexibility analysis in connection with its proposed rule governing the allocation of costs 

for construction work in progress (CWIP).704 The CWIP rules applied to all public 

utilities. This Final Rule applies only to RTOs and ISOs, which are a subset of “all 

public utilities” for which the regulatory flexibility analysis was not required. 

604. In a subsequent court decision, American Trucking Associations, Inc. v. EPA,

705

the U.S. Court of Appeals for the District of Columbia applied the decision in Mid-Tex to 

its determination. The Environmental Protection Agency (EPA) established a primary 

national ambient air quality standard for ozone and particulate matter. The basis of 

EPA’s certification was that the standard regulated small entities indirectly through state 

implementation plans. The court found that because the states, not EPA, had the direct 

 703 5 U.S.C. 601(3) and 601(6) and 15 U.S.C. 632(a)(1) (defining “small business 

concern”). 

704 Mid-Tex, 773 F.2d 327 at 342. 

705 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 Nos. RM07-19-000 and AD07-7-000 - 307 - 

authority to impose the burden on small entities, EPA’s regulation did not have a direct 

impact on small entities. 

605. Here APPA and TAPS contend that hundreds of small municipal systems would 

have to undertake legislative or regulatory actions in order to respond to the RTO. We 

disagree with their contention. No relevant electric retail regulatory authority is required 

to take any action under this rule. For these reasons, the Commission certifies that this 

Final Rule will not have a significant economic impact on a substantial number of small 

entities. 

VIII. Document Availability

606. In addition to publishing the full text of this document in the Federal Register, the 

Commission provides all interested persons an opportunity to view and/or print the 

contents of this document via the Internet through FERC's Home Page 

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

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

Washington DC 20426. 

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

eLibrary. The full text of this document is available on eLibrary in PDF and Microsoft 

Word format for viewing, printing, and/or downloading. To access this document in 

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

docket number field. 

608. User assistance is available for eLibrary and the Commission’s web site during 

normal business hours from FERC Online Support at 202-502-6652 (toll free at 1-866-
Docket Nos. RM07-19-000 and AD07-7-000 - 308 - 

208-3676) or email at ferconlinesupport@ferc.gov, or the Public Reference Room at 

(202) 502-8371, TTY (202) 502-8659. E-mail the Public Reference Room at 

public.referenceroom@ferc.gov. 

IX. Effective Date and Congressional Notification

609. These regulations are effective [insert date 60 days after publication in the 

FEDERAL REGISTER]. The Commission has determined, with the concurrence of the 

Administrator of the Office of Information and Regulatory Affairs of OMB, that this rule 

is not a “major rule” as defined in section 351 of the Small Business Regulatory 

Enforcement Fairness Act of 1996. The Commission will submit the Final Rule to both 

houses of Congress and the Government Accountability Office.

By the Commission. Commissioner Kelly concurring in part and dissenting in part 

 with a separate statement attached. 

( S E A L ) 

Nathaniel J. Davis, Sr., 

Deputy Secretary. 

 
Docket Nos. RM07-19-000 and AD07-7-000 - 309 - 

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. Amend § 35.28 as follows: 

(a) Amend paragraph (b) to add (b)(4), (b)(5), (b)(6), (b)(7), and (b)(8). 

(b) Add new paragraph (g). 

§ 35.28 Non-discriminatory open access transmission tariff.

 * * * * * 

 (b) Definitions * * * 

 (4) Demand response means a reduction in the consumption of electric energy 

by customers from their expected consumption in response to an increase in the price of 

electric energy or to incentive payments designed to induce lower consumption of electric 

energy. 

(5) Demand response resource means a resource capable of providing demand 

response. 

 (6) An operating reserve shortage means a period when the amount of available 

supply falls short of demand plus the operating reserve requirement. 

(7) Market Monitoring Unit means the person or entity responsible for carrying 

out the market monitoring functions that the Commission has ordered Commission-
Docket Nos. RM07-19-000 and AD07-7-000 - 310 - 

approved independent system operators and regional transmission organizations to 

perform. 

(8) Market Violation means a tariff violation, violation of a Commissionapproved order, rule or regulation, market manipulation, or inappropriate dispatch that 

creates substantial concerns regarding unnecessary market inefficiencies. 

 * * * * * 

(g) Tariffs and operations of Commission-approved independent system 

operators and regional transmission organizations. 

(1) Demand response and pricing. 

(i) Ancillary services provided by demand response resources. 

(A) Every Commission-approved independent system operator or regional 

transmission organization that operates organized markets based on competitive bidding 

for energy imbalance, spinning reserves, supplemental reserves, reactive power and 

voltage control, or regulation and frequency response ancillary services (or its functional 

equivalent in the Commission-approved independent system operator’s or regional 

transmission organization’s tariff) must accept bids from demand response resources in 

these markets for that product on a basis comparable to any other resources, if the 

demand response resource meets the necessary technical requirements under the tariff, 

and submits a bid under the Commission-approved independent system operator’s or 

regional transmission organization’s bidding rules at or below the market-clearing price, 

unless not permitted by the laws or regulations of the relevant electric retail regulatory 

authority. 
Docket Nos. RM07-19-000 and AD07-7-000 - 311 - 

(B) Each Commission-approved independent system operator or regional 

transmission organization must allow providers of a demand response resource to specify 

the following in their bids: 

(1) A maximum duration in hours that the demand response resource may be 

dispatched; 

(2) A maximum number of times that the demand response resource may be 

dispatched during a day; and 

(3) A maximum amount of electric energy reduction that the demand response 

resource may be required to provide either daily or weekly. 

(ii) Removal of deviation charges. A Commission-approved independent 

system operator or regional transmission organization with a tariff that contains a dayahead and a real-time market may not assess a charge to a purchaser of electric energy in 

its day-ahead market for purchasing less power in the real-time market during a real-time 

market period for which the Commission-approved independent system operator or 

regional transmission organization declares an operating reserve shortage or makes a 

generic request to reduce load to avoid an operating reserve shortage. 

(iii) Aggregation of retail customers. Each Commission-approved independent 

system operator and regional transmission organization must permit a qualified 

aggregator of retail customers to bid demand response on behalf of retail customers 

directly into the Commission-approved independent system operator’s or regional 

transmission organization’s organized markets, unless the laws and regulations of the 
Docket Nos. RM07-19-000 and AD07-7-000 - 312 - 

relevant electric retail regulatory authority expressly do not permit a retail customer to 

participate. 

(iv) Price formation during periods of operating reserve shortage. 

(A) Each Commission-approved independent system operator or regional 

transmission organization must modify its market rules to allow the market-clearing price 

during periods of operating reserve shortage to reach a level that rebalances supply and 

demand so as to maintain reliability while providing sufficient provisions for mitigating 

market power. 

(B) A Commission-approved independent system operator or regional 

transmission organization may phase in this modification of its market rules. 

(2) Long-term power contracting in organized markets. Each Commissionapproved independent system operator or regional transmission organization must 

provide a portion of its web site for market participants to post offers to buy or sell power 

on a long-term basis. 

(3) Market monitoring policies. 

(i) Each Commission-approved independent system operator or regional 

transmission organization must modify its tariff provisions governing its Market 

Monitoring Unit to reflect the directives provided in Order No. [insert order number], 

including the following: 

(A) Each Commission-approved independent system operator or regional 

transmission organization must include in its tariff a provision to provide its Market 

Monitoring Unit access to Commission-approved independent system operator and 
Docket Nos. RM07-19-000 and AD07-7-000 - 313 - 

regional transmission organization market data, resources and personnel to enable the 

Market Monitoring Unit to carry out its functions. 

(B) The tariff provision must provide the Market Monitoring Unit complete 

access to the Commission-approved independent system operator’s and regional 

transmission organization’s databases of market information. 

(C) The tariff provision must provide that any data created by the Market 

Monitoring Unit, including, but not limited to, reconfiguring of the Commissionapproved independent system operator’s and regional transmission organization’s data, 

will be kept within the exclusive control of the Market Monitoring Unit. 

(D) The Market Monitoring Unit must report to the Commission-approved 

independent system operator’s or regional transmission organization’s board of directors, 

with its management members removed, or to an independent committee of the 

Commission-approved independent system operator’s or regional transmission 

organization’s board of directors. A Commission-approved independent system operator 

or regional transmission organization that has both an internal Market Monitoring Unit 

and an external Market Monitoring Unit may permit the internal Market Monitoring Unit 

to report to management and the external Market Monitoring Unit to report to the 

Commission-approved independent system operator’s or regional transmission 

organization’s board of directors with its management members removed, or to an 

independent committee of the Commission-approved independent system operator or 

regional transmission organization board of directors. If the internal market monitor is 

responsible for carrying out any or all of the core Market Monitoring Unit functions 
Docket Nos. RM07-19-000 and AD07-7-000 - 314 - 

identified in paragraph (g)(3)(ii) of this section, the internal market monitor must report 

to the independent system operator’s or regional transmission organization’s board of 

directors.

(E) A Commission-approved independent system operator or regional 

transmission organization may not alter the reports generated by the Market Monitoring 

Unit, or dictate the conclusions reached by the Market Monitoring Unit. 

(F) Each Commission-approved independent system operator or regional 

transmission organization must consolidate the core Market Monitoring Unit provisions 

into one section of its tariff. Each independent system operator or regional transmission 

organization must include a mission statement in the introduction to the Market 

Monitoring Unit provisions that identifies the Market Monitoring Unit’s goals, including 

the protection of consumers and market participants by the identification and reporting of 

market design flaws and market power abuses. 

(ii) Core Functions of Market Monitoring Unit. The Market Monitoring Unit 

must perform the following core functions: 

(A) Evaluate existing and proposed market rules, tariff provisions and market 

design elements and recommend proposed rule and tariff changes to the Commissionapproved independent system operator or regional transmission organization, to the 

Commission’s Office of Energy Market Regulation staff and to other interested entities 

such as state commissions and market participants, provided that: 

(1) The Market Monitoring Unit is not to effectuate its proposed market design 

itself, and 
Docket Nos. RM07-19-000 and AD07-7-000 - 315 - 

(2) The Market Monitoring Unit must limit distribution of its identifications 

and recommendations to the independent system operator or regional transmission 

organization and to Commission staff in the event it believes broader dissemination could 

lead to exploitation, with an explanation of why further dissemination should be avoided 

at that time. 

(B) Review and report on the performance of the wholesale markets to the 

Commission-approved independent system operator or regional transmission 

organization, the Commission, and other interested entities such as state commissions and 

market participants, on at least a quarterly basis and submit a more comprehensive annual 

state of the market report. The Market Monitoring Unit may issue additional reports as 

necessary. 

(C) Identify and notify the Commission’s Office of Enforcement staff of 

instances in which a market participant’s or the Commission-approved independent 

system operator’s or regional transmission organization’s behavior may require 

investigation, including, but not limited to, suspected Market Violations. 

(iii) Tariff administration and mitigation

(A) A Commission-approved independent system operator or regional 

transmission organization may not permit its Market Monitoring Unit, whether internal or 

external, to participate in the administration of the Commission-approved independent 

system operator’s or regional transmission organization’s tariff or, except as provided in 

paragraph (g)(3)(iii)(D) of this section, to conduct prospective mitigation. 
Docket Nos. RM07-19-000 and AD07-7-000 - 316 - 

(B) A Commission-approved independent system operator or regional 

transmission organization may permit its Market Monitoring Unit to provide the inputs 

required for the Commission-approved independent system operator or regional 

transmission organization to conduct prospective mitigation, including, but not limited to, 

reference levels, identification of system constraints, and cost calculations. 

(C) A Commission-approved independent system operator or regional 

transmission organization may allow its Market Monitoring Unit to conduct retrospective 

mitigation. 

(D) A Commission-approved independent system operator or regional 

transmission organization with a hybrid Market Monitoring Unit structure may permit its 

internal market monitor to conduct prospective and/or retrospective mitigation, in which 

case it must assign to its external market monitor the responsibility and the tools to 

monitor the quality and appropriateness of the mitigation. 

(E) Each Commission-approved independent system operator or regional 

transmission organization must identify in its tariff the functions the Market Monitoring 

Unit will perform and the functions the Commission-approved independent system 

operator or regional transmission organization will perform. 

(iv) Protocols on Market Monitoring Unit referrals to the Commission of 

suspected violations.

(A) A Market Monitoring Unit is to make a non-public referral to the 

Commission in all instances where the Market Monitoring Unit has reason to believe that 

a Market Violation has occurred. While the Market Monitoring Unit need not be able to 
Docket Nos. RM07-19-000 and AD07-7-000 - 317 - 

prove that a Market Violation has occurred, the Market Monitoring Unit is to provide 

sufficient credible information to warrant further investigation by the Commission. Once 

the Market Monitoring Unit has obtained sufficient credible information to warrant 

referral to the Commission, the Market Monitoring Unit is to immediately refer the 

matter to the Commission and desist from independent action related to the alleged 

Market Violation. This does not preclude the Market Monitoring Unit from continuing to 

monitor for any repeated instances of the activity by the same or other entities, which 

would constitute new Market Violations. The Market Monitoring Unit is to respond to 

requests from the Commission for any additional information in connection with the 

alleged Market Violation it has referred. 

(B) All referrals to the Commission of alleged Market Violations are to be in 

writing, whether transmitted electronically, by fax, mail, or courier. The Market 

Monitoring Unit may alert the Commission orally in advance of the written referral. 

(C) The referral is to be addressed to the Commission’s Director of the Office 

of Enforcement, with a copy also directed to both the Director of the Office of Energy 

Market Regulation and the General Counsel. 

(D) The referral is to include, but need not be limited to, the following 

information. 

(1) The name[s] of and, if possible, the contact information for, the entity[ies] 

that allegedly took the action[s] that constituted the alleged Market Violation[s]; 

(2) The date[s] or time period during which the alleged Market Violation[s] 

occurred and whether the alleged wrongful conduct is ongoing; 
Docket Nos. RM07-19-000 and AD07-7-000 - 318 - 

(3) The specific rule or regulation, and/or tariff provision, that was allegedly 

violated, or the nature of any inappropriate dispatch that may have occurred; 

(4) The specific act[s] or conduct that allegedly constituted the Market 

Violation; 

(5) The consequences to the market resulting from the acts or conduct, 

including, if known, an estimate of economic impact on the market; 

(6) If the Market Monitoring Unit believes that the act[s] or conduct 

constituted a violation of the anti-manipulation rule of Part 1c, a description of the 

alleged manipulative effect on market prices, market conditions, or market rules; 

(7) Any other information the Market Monitoring Unit believes is relevant and 

may be helpful to the Commission. 

(E) Following a referral to the Commission, the Market Monitoring Unit is to 

continue to notify and inform the Commission of any information that the Market 

Monitoring Unit learns of that may be related to the referral, but the Market Monitoring 

Unit is not to undertake any investigative steps regarding the referral except at the 

express direction of the Commission or Commission Staff. 

(v) Protocols on Market Monitoring Unit Referrals to the Commission of 

Perceived Market Design Flaws and Recommended Tariff Changes.

(A) A Market Monitoring Unit is to make a referral to the Commission in all 

instances where the Market Monitoring Unit has reason to believe market design flaws 

exist that it believes could effectively be remedied by rule or tariff changes. The Market 

Monitoring Unit must limit distribution of its identifications and recommendations to the 
Docket Nos. RM07-19-000 and AD07-7-000 - 319 - 

independent system operator or regional transmission organization and to the 

Commission in the event it believes broader dissemination could lead to exploitation, 

with an explanation of why further dissemination should be avoided at that time. 

(B) All referrals to the Commission relating to perceived market design flaws 

and recommended tariff changes are to be in writing, whether transmitted electronically, 

by fax, mail, or courier. The Market Monitoring Unit may alert the Commission orally in 

advance of the written referral. 

(C) The referral should be addressed to the Commission’s Director of the 

Office of Energy Market Regulation, with copies directed to both the Director of the 

Office of Enforcement and the General Counsel. 

(D) The referral is to include, but need not be limited to, the following 

information. 

(1) A detailed narrative describing the perceived market design flaw[s]; 

(2) The consequences of the perceived market design flaw[s], including, if 

known, an estimate of economic impact on the market; 

(3) The rule or tariff change(s) that the Market Monitoring Unit believes could 

remedy the perceived market design flaw; 

(4) Any other information the Market Monitoring Unit believes is relevant and 

may be helpful to the Commission. 

(E) Following a referral to the Commission, the Market Monitoring Unit is to 

continue to notify and inform the Commission of any additional information regarding 

the perceived market design flaw, its effects on the market, any additional or modified 
Docket Nos. RM07-19-000 and AD07-7-000 - 320 - 

observations concerning the rule or tariff changes that could remedy the perceived design 

flaw, any recommendations made by the Market Monitoring Unit to the regional 

transmission organization or independent system operator, stakeholders, market 

participants or state commissions regarding the perceived design flaw, and any actions 

taken by the regional transmission organization or independent system operator regarding 

the perceived design flaw. 

(vi) Market Monitoring Unit ethics standards. Each Commission-approved 

independent system operator or regional transmission organization must include in its 

tariff ethical standards for its Market Monitoring Unit and the employees of its Market 

Monitoring Unit. At a minimum, the ethics standards must include the following 

requirements: 

(A) The Market Monitoring Unit and its employees must have no material 

affiliation with any market participant or affiliate. 

(B) The Market Monitoring Unit and its employees must not serve as an 

officer, employee, or partner of a market participant. 

(C) The Market Monitoring Unit and its employees must have no material 

financial interest in any market participant or affiliate with potential exceptions for 

mutual funds and non-directed investments. 

(D) The Market Monitoring Unit and its employees must not engage in any 

market transactions other than the performance of their duties under the tariff. 

(E) The Market Monitoring Unit and its employees must not be compensated, 

other than by the Commission-approved independent system operator or regional 
Docket Nos. RM07-19-000 and AD07-7-000 - 321 - 

transmission organization that retains or employs it, for any expert witness testimony or 

other commercial services, either to the Commission-approved independent system 

operator or regional transmission organization or to any other party, in connection with 

any legal or regulatory proceeding or commercial transaction relating to the Commissionapproved independent system operator or regional transmission organization or to the 

Commission-approved independent system operator’s or regional transmission 

organization’s markets. 

(F) The Market Monitoring Unit and its employees may not accept anything of 

value from a market participant in excess of a de minimis amount. 

(G) The Market Monitoring Unit and its employees must advise a supervisor in 

the event they seek employment with a market participant, and must disqualify 

themselves from participating in any matter that would have an effect on the financial 

interest of the market participant. 

(4) Offer and bid data. (i) Unless a Commission-approved independent system 

operator or regional transmission organization obtains Commission approval for a 

different period, each Commission-approved independent system operator and regional 

transmission organization must release its offer and bid data within three months. 

(ii) A Commission-approved independent system operator or regional 

transmission organization must mask the identity of market participants when releasing 

offer and bid data. The Commission-approved independent system operators and 

regional transmission organization may propose a time period for eventual unmasking. 
Docket Nos. RM07-19-000 and AD07-7-000 - 322 - 

(5) Responsiveness of Commission-approved independent system operators 

and regional transmission organizations. Each Commission-approved independent 

system operator or regional transmission organization must adopt business practices and 

procedures that achieve Commission-approved independent system operator and regional 

transmission organization board of directors’ responsiveness to customers and other 

stakeholders and satisfy the following criteria: 

(i) Inclusiveness. The business practices and procedures must ensure that any 

customer or other stakeholder affected by the operation of the Commission-approved 

independent system operator or regional transmission organization, or its representative, 

is permitted to communicate the customer’s or other stakeholder’s views to the 

independent system operator’s or regional transmission organization’s board of directors; 

(ii) Fairness in balancing diverse interests. The business practices and 

procedures must ensure that the interests of customers or other stakeholders are equitably 

considered, and that deliberation and consideration of Commission-approved independent 

system operator’s and regional transmission organization’s issues are not dominated by 

any single stakeholder category; 

(iii) Representation of minority positions. The business practices and 

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

on a particular issue, minority positions are communicated to the Commission-approved 

independent system operator’s and regional transmission organization’s board of 

directors at the same time as majority positions; and 
Docket Nos. RM07-19-000 and AD07-7-000 - 323 - 

(iv) Ongoing responsiveness. The business practices and procedures must 

provide for stakeholder input into the Commission-approved independent system 

operator’s or regional transmission organization’s decisions as well as mechanisms to 

provide feedback to stakeholders to ensure that information exchange and communication 

continue over time. 

(6) Compliance filings. All Commission-approved independent system 

operators and regional transmission organizations must make a compliance filing with the 

Commission as described in Order No. [insert order number] under the following 

schedule: 

(i) The compliance filing addressing the accepting of bids from demand 

response resources in markets for ancillary services on a basis comparable to other 

resources, removal of deviation charges, aggregation of retail customers, shortage pricing 

during periods of operating reserve shortage, long-term power contracting in organized 

markets, Market Monitoring Units, Commission-approved independent system operators’ 

and regional transmission organizations’ board of directors’ responsiveness, and 

reporting on the study of the need for further reforms to remove barriers to comparable 

treatment of demand response resources must be submitted on or before [insert date that 

is six months of publication in the FEDERAL REGISTER]. 

 (ii) A public utility that is approved as a regional transmission organization 

under § 35.34, or that is not approved but begins to operate regional markets for electric 

energy or ancillary services after [insert effective date of Final Rule], must comply with 
Docket Nos. RM07-19-000 and AD07-7-000 - 324 - 

Order No. [insert order number] and the provisions of paragraphs (g)(1) through (g)(5) 

of this section before beginning operations. 
Docket Nos. RM07-19-000 and AD07-7-000 - 325 - 

NOTE: The following appendix will not be published in the Code of Federal 

Regulations.

APPENDIX 

Abbreviated Names of Commenters 

Alcoa – Alcoa, Inc. 

Ameren – Ameren Services Company 

American Forest – American Forest & Paper Association 

AMPA – Arkansas Municipal Power Association 

APPA – American Public Power Association 

ATC – American Transmission Company, LLC 

Beacon Power – Beacon Power Corporation 

Blue Ridge – Blue Ridge Power Agency 

BlueStar Energy – BlueStar Energy Services, Inc. 

Mr. Borlick – Robert L. Borlick, Borlick & Associates 

BP Energy – BP Energy Company 

CAISO – California Independent System Operator Corporation 

California DWR – California Department of Water Resources State Water Project 

California Munis – California Municipal Utilities Association 

California PUC – Public Utilities Commission of the State of California 

Cogeneration Parties - Energy Producers and Users Coalition (EPUC) and the 

Cogeneration Association of California (CAC). EPUC is an ad hoc group 

representing the end-use and customer generation interests of the following: Aera 

Energy LLC; BP America, Inc. (including Atlantic Richfield Company); Chevron 

U.S.A., Inc.; ConocoPhillips Company; ExxonMobil Power and Gas Services, 

Inc.; Shell Oil Products US; THUMS Long Beach Company; Occidental Elks 

Hills, Inc.; and Valero Refining Company-California. CAC is an ad hoc

association representing the power generation, power marketing and cogeneration 

operation interests of the following: Coalinga Cogeneration Company, Mid-Set 

Cogeneration Company, Kern River Cogeneration Company, Sycamore 

Cogeneration Company, Sargent Canyon Cogeneration Company, Salinas River 

Cogeneration Company, Midway Sunset Cogeneration Company and Watson 

Cogeneration Company. 

Comverge – Comverge, Inc. 

Connecticut and Massachusetts Municipals – Connecticut Municipal Electric Energy 

Cooperative and Massachusetts Municipal Wholesale Electric Company 
Docket Nos. RM07-19-000 and AD07-7-000 - 326 - 

Constellation – Constellation Energy Commodities Group, Inc., Constellation 

NewEnergy, Inc., and Constellation Power Source Generation, Inc. 

DC Energy – DC Energy, LLC

Detroit Edison – Detroit Edison Company 

Dominion Resources – Dominion Resources Services 

DRAM – Demand Response and Advanced Metering Coalition 

Duke Energy – Duke Energy Corporation 

EEI – Edison Electric Institute 

EnergyConnect – EnergyConnect, Inc. 

Energy Curtailment – Energy Curtailment Specialists, Inc. 

EnerNOC – EnerNOC, Inc. 

E.ON U.S – E.ON U.S. LLC 

EPSA – Electric Power Supply Association 

Exelon – Exelon Corporation 

FTC – Federal Trade Commission 

FirstEnergy - FirstEnergy Service Company, on behalf of FirstEnergy Solutions Corp. 

and the transmission- and distribution-owning utility subsidiaries of FirstEnergy 

Corp.: American Transmission Systems, Incorporated; The Cleveland Electric 

Illuminating Company; Jersey Central Power and Light Company; Metropolitan 

Edison Company; Ohio Edison Company; Pennsylvania Electric Company; 

Pennsylvania Power Company; and The Toledo Edison Company 

IID – Imperial Irrigation District 

IMEA – Illinois Municipal Electric Agency 

Indianapolis P&L – Indianapolis Power and Light Company 

Industrial Coalitions - The Coalition of Midwest Transmission Customers, Connecticut 

Industrial Energy Consumers, Industrial Energy Consumers of Pennsylvania, 

NEPOOL Industrial Customer Coalition, Industrial Energy Users-Ohio, West 

Virginia Energy Users Group, PJM Industrial Customer Coalition, American Iron 

and Steel Institute, and Portland Cement Association 

Industrial Consumers – Electricity Consumers Resource Council, American Chemistry 

Council, American Iron and Steel Institute, Association of Businesses Advocating 

Tariff Equity, Council of Industrial Boiler Owners, and Wisconsin Industrial 

Energy Group 

Integrys Energy – Integrys Energy Services, Inc. 

ISO New England – ISO New England Inc. 

ISO/RTO Council – ISO/RTO Council, which is comprised of the Alberta Electric 

System Operator; California Independent System Operator, Inc.; New Brunswick 

System Operator; Electric Reliability Council of Texas; Independent Electricity 
Docket Nos. RM07-19-000 and AD07-7-000 - 327 - 

System Operator of Ontario; ISO New England Inc.; Midwest Independent 

Transmission System Operator, Inc.; New York Independent System Operator, 

Inc.; PJM Interconnection, L.L.C.; and Southwest Power Pool, Inc. 

ITC – International Transmission Company; Michigan Electric Transmission Company, 

LLC; and ITC Midwest LLC 

Joint Commenters - Citadel Energy Products LLC, Citadel Energy Strategies LLC, 

Citadel Energy Investments Ltd.; and DC Energy LLC

Kansas CC – Kansas Corporation Commission 

LPPC – Large Public Power Council 

MADRI States – the State members of the Mid-Atlantic Distributed Resources Initiative 

Maine PUC – Maine Public Utilities Commission 

Midwest Energy – Midwest Energy, Inc. 

Midwest ISO – Midwest Independent Transmission System Operator, Inc. 

Midwest ISO TOs – Midwest ISO Transmission Owners: Ameren Services Company, 

as agent for Union Electric Company d/b/a AmerenUE, Central Illinois Public 

Service Company d/b/a AmerenCIPS, Central Illinois Light Co. d/b/a 

AmerenCILCO, and Illinois Power Company d/b/a AmerenIP; City of Columbia 

Water and Light Department (Columbia, Missouri); City Water, Light & Power 

(Springfield, Illinois); Duke Energy Shared Services for Duke Energy Ohio, Inc., 

Duke Energy Indiana, Inc., and Duke Energy Kentucky, Inc.; Great River Energy; 

Hoosier Energy Rural Electric Cooperative, Inc.; Indiana Municipal Power 

Agency; Indianapolis Power & Light Company; Manitoba Hydro; Michigan 

Public Power Agency; Minnesota Power (and its subsidiary Superior Water, 

L&P); Montana-Dakota Utilities Co.; Northern Indiana Public Service Company; 

Northern States Power Company, a Minnesota corporation, and Northern States 

Power Company, a Wisconsin corporation, subsidiaries of Xcel Energy Inc.; 

Northwestern Wisconsin Electric Company; Otter Tail Power Company; Southern 

Illinois Power Cooperative; Southern Indiana Gas & Electric Company (d/b/a 

Vectren Energy Delivery of Indiana); Southern Minnesota Municipal Power 

Agency; Wabash Valley Power Association, Inc.; and Wolverine Power Supply 

Cooperative, Inc. 

NARUC – National Association of Regulatory Commissioners

National Grid – National Grid USA and its affiliates 

NCPA – Northern California Power Agency 

NEPGA – New England Power Generators Association, Inc. 

NEPOOL Participants – New England Power Pool Participants Committee 

New England Power Generators – New England Power Generators Association, Inc. 

New York PSC – New York State Public Service Commission 

NIPSCO – Northern Indiana Public Service Company
Docket Nos. RM07-19-000 and AD07-7-000 - 328 - 

New Jersey BPU – New Jersey Board of Public Utilities 

North Carolina Electric Membership – North Carolina Electric Membership 

Corporation 

Northeast Utilities – Northeast Utilities 

NRECA – National Rural Electric Cooperative Association 

NSTAR – NSTAR Electric Company 

NYISO – New York Independent System Operator, Inc. 

NY TOs – Central Hudson Gas & Electric Corporation, Consolidated Edison Company 

of New York, Inc., Long Island Power Authority, New York Power Authority, 

New York State Electric & Gas Corporation, Orange and Rockland Utilities, Inc., 

and Rochester Gas and Electric Corporation 

Ohio PUC – Public Utilities Commission of Ohio 

Old Dominion – Old Dominion Electric Cooperative 

OMS – Organization of MISO States, whose participating members are: Illinois 

Commerce Commission, Indiana Utility Regulatory Commission, Iowa Utilities 

Board, Kentucky Public Service Commission, Michigan Public Service 

Commission, Minnesota Public Utilities Commission, Montana Public Service 

Commission, Nebraska Power Review Board, Public Utilities Commission of 

Ohio, South Dakota Public Utilities Commission, Wisconsin Public Service 

Commission. Participating associate members are: Indiana Office of Utility 

Consumer Counselor, Iowa Office of Consumer Advocate and the Minnesota 

Office of Energy Security 

OPSI – Organization of PJM States, Inc., whose state commission members include: 

Delaware Public Service Commission, District of Columbia Public Service 

Commission, Illinois Commerce Commission, Indiana Utility Regulatory 

Commission, Kentucky Public Service Commission, Maryland Public Service 

Commission, Michigan Public Service Commission, New Jersey Board of Public 

Utilities, North Carolina Utilities Commission, Public Utilities Commission of 

Ohio, Pennsylvania Public Utility Commission, Tennessee Regulatory Authority, 

Virginia State Corporation Commission, and Public Service Commission of West 

Virginia 

Orion Energy – Orion Energy Systems, Inc. 

Pennsylvania PUC – Pennsylvania Public Utility Commission 

PG&E – Pacific Gas and Electric Company 

PJM – PJM Interconnection, LLC 

PJM Power Providers – PJM Power Providers Group 

Potomac Economics – Potomac Economics, Ltd. 

PPL Parties –PPL Brunner Island, LLC; PPL Edgewood Energy, LLC; PPL Electric 

Utilities Corporation; PPL EnergyPlus, LLC; PPL Great Works, LLC; PPL 
Docket Nos. RM07-19-000 and AD07-7-000 - 329 - 

Holtwood, LLC; PPL Maine, LLC; PPL Martins Creek, LLC; PPL Montana, LLC; 

PPL Montour, LLC; PPL Shoreham Energy, LLC; PPL Susquehanna, LLC; PPL 

University Park, LLC; PPL Wallingford Energy LLC; and Lower Mount Bethel 

Energy, LLC 

Public Interest Organizations –Citizen Power; Conservation Law Foundation; 

Environment Northeast; Environmental Law & Policy Center; Fresh Energy; Izaak 

Walton League; Natural Resources Defense Council; Northwest Energy Coalition; 

Office of the Ohio Consumers’ Counsel; Pace Energy Project; PennFuture; Project 

for Sustainable FERC Energy Policy; Southern Alliance for Clean Energy; The 

Stella Group, Ltd.; Union of Concerned Scientists; and Western Grid Group 

Reliant – Reliant Energy, Inc. 

Retail Energy – Retail Energy Supply Association 

SMUD - Sacramento Municipal Utility District 

SoCal Edison-SDG&E – Southern California Edison Company and San Diego Gas & 

Electric Company 

Sorgo – Sorgo Fuels, Inc. 

SPP – Southwest Power Pool, Inc. 

Steel Manufacturers – Steel Manufacturers Association 

Steel Producers – Nucor and Steel Dynamics 

TANC – Transmission Agency of Northern California 

TAPS – Transmission Access Policy Study Group 

Wal-Mart – Wal-Mart Stores, Inc. 

Xcel – Xcel Energy Services, Inc., on behalf of Northern States Power Company, a 

Minnesota corporation; Northern States Power Company, a Wisconsin 

corporation; Southwestern Public Service Company; and Public Service Company 

of Colorado 

Abbreviated Names of Reply Commenters 

Allied Public Interest Groups - Clean Energy First, Conservation Law Foundation, 

Environment Northeast, Environmental Law & Policy Center, Fresh Energy, 

Natural Resources Defense Council, Northwest Energy Coalition, Office of the 

Ohio Consumers' Counsel, Pace Energy and Climate Center, Penn Future, Project 

for Sustainable FERC Energy Policy, Renewable Northwest Project, and Union of 

Concerned Scientists. 

CAISO and the Cities - CAISO and the cities of Anaheim, Azusa, Banning, Colton, and 

Riverside, California 
UNITED STATES OF AMERICA 

FEDERAL ENERGY REGULATORY COMMISSION 

Wholesale Competition in Regions with Docket Nos. RM07-19-000 

 Organized Electric Markets AD07-7-000 

(Issued October 17, 2008) 

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

 I write separately for two reasons. First, I want to emphasize the 

importance of competition to the operation of organized wholesale electric 

markets and the fact that many of the findings here will help foster that 

competition. Second, I write to express my misgivings about the potential impacts 

of several of the directives included in the Final Rule. 

 I believe that many of the Final Rule’s findings will promote competition, 

thereby helping the Commission to fulfill our statutory mandate to ensure 

adequate and reliable service at just and reasonable rates. In particular, I support 

the Final Rule’s requirements that regional transmission organizations (RTOs) and 

independent system operators (ISOs): (1) accept bids for certain ancillary services 

from demand response resources that meet technical requirements and submit a 

bid at or below the market-clearing price; (2) permit qualified aggregators of retail 

customers to bid demand response on behalf of retail customers; and (3) eliminate 

deviation charges during system emergencies to a purchaser of electric energy for 

taking less energy in the real-time market than it purchased in the day-ahead 

market. I also agree with requiring RTOs/ISOs to include a tariff provision that 

commits to providing market monitoring units (or MMUs) with the data, 

resources, and personnel necessary to carry out the MMUs’ functions. 

 I continue to be troubled by the Final Rule’s directive to each RTO or ISO 

with an organized energy market to make a compliance filing to propose any 

necessary reforms to allow for scarcity pricing in times of emergency by 

modifying market power mitigation rules. The Final Rule states that existing 

RTO/ISO rules “may not produce prices that accurately reflect the value of energy 

and, by failing to do so, may harm reliability, inhibit demand response, deter entry 

of demand response and generation resources, and thwart innovation.” I recognize 

that the majority has good intentions in requiring RTOs/ISOs to make this filing. 

However, I believe that, prior to allowing energy supply offer caps and demand 

bid caps to rise or be eliminated, the necessary generation and demand response 

infrastructure must be in place to give consumers the ability to respond to higher 

prices. As Commission staff noted in the 2006 FERC Staff Demand Response 
Docket Nos. RM07-19-000 and AD07-7-000 - 2 - 

Assessment, advanced metering currently has low market penetration of less than 

six percent in the United States.1

 Without providing consumers with the ability to 

respond to rising prices, I view the decision to allow energy supply offer caps and 

demand bid caps to rise or be eliminated as irresponsible. 

 Additionally, I disagree with the Final Rule’s decision to promote 

responsiveness of RTOs/ISOs by allowing them to adopt hybrid boards with 

stakeholder members. Having an independent board is the cornerstone of 

RTO/ISO policy. Providing for stakeholder representatives on an RTO/ISO board 

jeopardizes such an independent governing structure. I agree with Duke Energy’s 

statement that “hybrid boards are contrary to the premise of independent RTO 

governance, and that the board advisory committee is a much more effective 

means of helping RTO boards to understand member issues and concerns.”2

 I also 

fear that a board with independent and non-independent members will suffer from 

a divisive atmosphere with suspicion as to whether non-independent board 

members are acting in the best interests of the RTO/ISO and its customers or in 

the best interest of the particular market participant represented by that nonindependent board member. I also share Pennsylvania PUC’s concern that it will 

be difficult to protect competitively sensitive information with non-independent 

members serving on the RTO/ISO’s board.3

 I believe that a board advisory 

committee is a better way to address RTO/ISO responsiveness to stakeholders 

while maintaining the independence of RTO/ISO boards. 

 Finally, as I noted previously in my separate statement regarding the notice 

of proposed rulemaking (NOPR),4

 I am concerned about the issue of MMUs being 

removed from tariff administration and mitigation. I note that a large number and 

variety of commenters were also concerned about the NOPR proposal, including 

American Forest, California PUC, Indianapolis P&L, ISO New England, 

 1

 Assessment of Demand Response and Advanced Metering: Staff Report, 

Docket No. AD06-2-000, at 26 (2006) (2006 FERC Staff Demand Response 

Assessment). 

2

 Duke Energy Corporation Apr. 21, 2008 Comments, Docket No. RM07-

19, at 2-3. 

3 See Pennsylvania PUC Apr. 21, 2008 Comments, Docket No. RM07-19, 

at 18. 

4

 Wholesale Competition in Regions with Organized Electric Markets, 

Notice of Proposed Rulemaking, 73 FR 12,576 (Mar. 7, 2008), FERC Stats. & 

Regs. ¶ 32,628 (2008) (Comm’r Kelly concurring in part and dissenting in part). 
Docket Nos. RM07-19-000 and AD07-7-000 - 3 - 

Industrial Coalitions, Maine PUC, NARUC, NEPOOL Participants, New York 

PSC, North Carolina Electric Membership, Ohio PUC, Old Dominion, OMS, 

Potomac Economics, and Xcel. ISO New England stated that it “disagrees with 

the proposition that an MMU’s performance of mitigation functions compromises 

the MMU’s independence or distracts an MMU from its core functions,”5

 referring 

to the arguments against MMUs’ involvement in mitigation as “unconvincing.”6

 

Maine PUC stated that “[t]he Commission has not demonstrated that there is a 

lack of independence or a conflict of interest in having those who are experts in 

the areas of market mitigation performing day-to-day mitigation.”7

 Industrial 

Coalitions called the Commission’s proposal, “objectionable because it would 

place responsibility for mitigation in the hands of the RTO/ISO staff that designed, 

and have a vested interest in the success of, market rules.”8

 

 I do not mean to imply that the Final Rule totally ignores these concerns. 

Indeed, the Final Rule does make changes to the NOPR proposal by drawing a 

distinction between RTOs/ISOs that have a single MMU and those that have 

hybrid MMUs, with both an “external” and “internal” market monitor. Under 

these changes, a RTO/ISO may allow its MMU - whether it is a single MMU or a 

hybrid MMU - to perform retrospective mitigation. However, only a RTO/ISO 

with both an internal and external MMU may allow its internal MMU to continue 

to perform prospective mitigation.9

 In those instances, the internal MMU may 

perform the prospective mitigation, but only if the RTO/ISO moves the 

responsibility and the tools to monitor the quality and appropriateness of the 

mitigation conducted by the internal MMU to its external MMU. Finally, both 

single MMUs and hybrid MMUs may provide the RTO/ISO with the inputs 

needed for the RTO/ISO to conduct prospective mitigation, including “reference 

levels, identification of system constraints, and cost calculations.” 

 5

 ISO New England Apr. 21, 2008 Comments, Docket No. RM07-19, at 19. 

6 Id.

7

 Maine PUC Apr. 21, 2008 Comments, Docket No. RM07-19, at 7. 

8

 Industrial Coalitions Apr. 21, 2008 Comments, Docket No. RM07-19, at 

22. 

9

 The Final Rule considers prospective mitigation to include mitigation that 

can affect market outcomes on a forward-going basis, such as altering the prices of 

offers or altering the physical parameters of offers at or before the time they are 

considered in a market solution. 
Docket Nos. RM07-19-000 and AD07-7-000 - 4 - 

 After this long, drawn-out process, I question what problem we are actually 

trying to solve with this proposal. MMUs are professionals who have been 

performing mitigation in a competent, professional, and efficient manner for many 

years. I disagree with the misgivings expressed in the Final Rule that “unfettered 

conduct of mitigation by MMUs makes them subordinate to the RTOs and ISOs 

and raises conflict of interest concerns.” I do not think the record supports that 

assertion. I am also concerned that the dictates of the Final Rule may put some 

RTOs/ISOs to unnecessary expense. While the Final Rule has evolved in a 

positive way on this issue, I believe it continues to be an answer in search of a 

problem. 

 

 Accordingly, for the reasons stated above, I concur in part and dissent in 

part on this Final Rule. 

 ______________________________ 

 Suedeen G. Kelly