122 FERC ¶ 61,167 

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 February 22, 2008) 

AGENCY: Federal Energy Regulatory Commission. 

ACTION: Notice of Proposed Rulemaking. 

SUMMARY: The Federal Energy Regulatory Commission (Commission) is proposing 

to amend 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 a period 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 stakeholders and 

customers, and ultimately to the consumers who benefit from and pay for electricity 

services. The Commission proposes to require that each RTO and ISO make certain 

filings that propose amendments to its tariff, in order to comply with the proposed 

requirements in each area, or that demonstrate that its existing tariff and market design 

already satisfy the requirements. The Commission invites all interested persons to submit 

comments in response to the regulations proposed herein. 

DATES: Comments are due [insert date that is 45 days after publication in the 
Docket Nos. RM07-19-000 and AD07-7-000 - 2 - 

FEDERAL REGISTER].

ADDRESSES: You may submit comments, identified by docket number by any of the 

following methods: 

• Agency Web Site: http://ferc.gov. Documents created electronically using word 

processing software should be filed in native applications or print-to-PDF format 

and not in a scanned format. 

• Mail/Hand Delivery: Commenters unable to file comments electronically must 

mail or hand deliver an original and 14 copies of their comments to: Federal 

Energy Regulatory Commission, Secretary of the Commission, 888 First Street, 

N.E., Washington, D.C. 20426. 

Instructions: For detailed instructions on submitting comments and additional 

information on the rulemaking process, see the Comment Procedures Section of this 

document. 

FOR FURTHER INFORMATION CONTACT: 

David Kathan (Technical Information) 

Office of Energy Market Regulation 

Federal Energy Regulatory Commission 

888 First Street, N.E. 

Washington, D.C. 20426 

David.Kathan@ferc.gov

(202) 502-6404 

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: 
122 FERC ¶ 61,167 

UNITED STATES OF AMERICA 

FEDERAL ENERGY REGULATORY COMMISSION 

Wholesale Competition in Regions with Organized 

Electric Markets 

Docket Nos. RM07-19-000 

AD07-7-000 

NOTICE OF PROPOSED RULEMAKING 

(Issued February 22, 2008) 

TABLE OF CONTENTS

 Paragraph Numbers

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

II. Background................................................................................................................. 12.

III. Proposals to Expand the Scope of the Proceeding .................................................... 16.

IV. Discussion ................................................................................................................. 26.

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

Organized Markets....................................................................................................... 26.

1. Background......................................................................................................... 27.

a. Importance of Demand Response to Competition in RTO/ISO Areas .......... 28.

b. Prior Commission Actions To Address Demand Response........................... 32.

2. The Need for Commission Action ..................................................................... 37.

3. Proposed Reforms............................................................................................... 46.

a. Ancillary Services Provided by Demand Response Resources ..................... 47.

i. Preliminary Proposals in the ANOPR ........................................................ 47.

ii. Comments on the ANOPR Proposals and Questions................................ 50.

iii. Commission Proposal............................................................................... 56.

b. Deviation Charge............................................................................................ 65.

i. Preliminary Proposals in the ANOPR ........................................................ 65.

ii. Comments on the ANOPR Proposals and Questions................................ 67.

iii. Commission Proposal............................................................................... 72.

c. Aggregation of Retail Customers................................................................... 80.

i. Preliminary Proposals in the ANOPR ....................................................... 80.

ii. Comments on the ANOPR Proposals and Questions................................ 82.

iii. Commission Proposal............................................................................... 86.

d. Potential Future Demand Response Reforms ................................................ 94.
Docket Nos. RM07-19-000 and AD07-7-000 ii 

e. Market Rules Governing Price Formation During Periods of Operating 

Reserve Shortage................................................................................................. 97.

i. Preliminary Proposals in the ANOPR ........................................................ 97.

ii. Comments on the ANOPR Proposals and Questions................................ 99.

iii. Commission Proposal............................................................................. 107.

B. Long-Term Power Contracting in Organized Markets ........................................ 129.

1. Background....................................................................................................... 130.

2. The Need for Commission Action.................................................................... 134.

3. Preliminary Proposals in the ANOPR .............................................................. 138.

4. Comments on the ANOPR Proposals and Questions....................................... 142.

5. Proposed Reforms............................................................................................. 155.

C. Market-Monitoring Policies ................................................................................. 162.

1. Background....................................................................................................... 163.

2. Prior Commission Actions Regarding Market Monitoring ............................. 165.

3. The Need for Commission Action.................................................................... 169.

4. Proposed Reforms............................................................................................. 171.

a. Independence and Function.......................................................................... 172.

i. Structure and Tools................................................................................... 173.

ii. Oversight ................................................................................................. 183.

iii. Functions ................................................................................................ 191.

iv. Mitigation and Operations ...................................................................... 200.

v. Ethics ....................................................................................................... 211.

vi. Tariff Provisions ..................................................................................... 215.

b. Information Sharing ..................................................................................... 219.

i. Enhanced Information Dissemination ...................................................... 220.

ii. Tailored Requests for Information .......................................................... 231.

iii. Commission Referrals ............................................................................ 238.

c. Pro Forma Tariff........................................................................................... 241.

i. Preliminary Proposals in the ANOPR ...................................................... 241.

ii. Comments on the ANOPR Proposals and Questions.............................. 242.

iii. Commission Proposal............................................................................. 243.

D. Responsiveness of RTOs and ISOs to Stakeholders and Customers................... 245.

1. Background....................................................................................................... 247.

2. Preliminary Proposals in the ANOPR .............................................................. 249.

3. Comments on the ANOPR Proposals and Questions....................................... 254.

a. Comments on the Hybrid Board Approach.................................................. 255.

b. Comments on the Board Advisory Committee Approach ........................... 264.

c. Comments on the Need to Increase Management Responsiveness.............. 268.

d. Comments on Regional Differences ............................................................ 270.

4. The Need for Commission Action.................................................................... 272.

5. Proposed Reform .............................................................................................. 275.
Docket Nos. RM07-19-000 and AD07-7-000 iii 

V. Applicability of the Proposed Rule and Compliance Procedures ............................ 282.

VI. Information Collection Statement ........................................................................... 286.

VII. Environmental Analysis......................................................................................... 290.

VIII. Regulatory Flexibility Act Certification............................................................... 291.

IX. Comment Procedures .............................................................................................. 292.

X. Document Availability ............................................................................................. 296.

APPENDIX A: Commenter Acronyms 
122 FERC ¶ 61,167 

UNITED STATES OF AMERICA 

FEDERAL ENERGY REGULATORY COMMISSION 

Wholesale Competition in Regions with Organized 

Electric Markets 

Docket Nos. RM07-19-000 

AD07-7-000 

NOTICE OF PROPOSED RULEMAKING 

(Issued February 22, 2008) 

I. Introduction

1. The Federal Energy Regulatory Commission (Commission) is proposing reforms 

to improve the operation of organized wholesale electric power markets.1

 Ensuring the 

competitiveness of organized wholesale markets is integral to the Commission fulfilling 

its statutory mandate to ensure adequate and reliable non-discriminatory service at just 

and reasonable rates. Effective competition protects consumers by providing greater 

supply options, encouraging new entry and innovation, and encouraging demand 

response and energy efficiency. In the past several years, the Commission has received 

both formal and informal comments from market participants, consumer and industry 

organizations, state regulators, and others recommending improvements to competitive 

wholesale markets. 

2. In response to these comments, the Commission held three public conferences in 

2007 in order to gather more information on competition at the wholesale level and other 

 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. 
Docket Nos. RM07-19-000 and AD07-7-000 - 2 - 

related issues. At the first conference on competition issues, held on February 27, 2007, 

most speakers addressed issues affecting the RTO and ISO regions, including the levels 

of wholesale prices, the need for long-term power contracts, the effectiveness of market 

monitoring, and the lack of adequate demand response.2

 On April 5, 2007, the 

Commission also held a technical conference on market monitoring policies and heard 

from interested commenters on issues such as the development of the concept and 

functions of market monitoring and the market monitoring units’ (MMU) role with 

respect to the Commission, ISOs and RTOs, and various stakeholders.3

 The Commission 

then held a second competition conference on May 8, 2007, to examine in more detail 

several specific concerns and challenges identified in the first conference. This second 

conference focused on regions with organized markets administered by RTOs and ISOs 

and dealt with: (1) demand response, including the role of demand response during a 

period of operating reserve shortage; (2) fostering long-term power contracting; and (3) 

the responsiveness of RTOs and ISOs to customers and other stakeholders.4

3. Based on the record compiled at these three conferences, the Commission issued 

an Advance Notice of Proposed Rulemaking (ANOPR)5

 on June 22, 2007 to identify and 

 2

 See Second Supplemental Notice of Conference, Conference on Competition in 

Wholesale Power Markets, Docket No. AD07-7-000 (Feb. 26, 2007). 

3

 See Notice of Agenda for the Conference, Review of Market Monitoring 

Policies, Docket No. AD07-8-000 (Mar. 30, 2007). 

4

 See Supplemental Notice of Conference, Conference on Competition in 

Wholesale Power Markets, Docket No. AD07-7-000 (Apr. 19, 2007). 

5

 Wholesale Competition in Regions with Organized Electric Markets, Advance 
Docket Nos. RM07-19-000 and AD07-7-000 - 3 - 

implement improvements to specific aspects of organized wholesale markets. In the 

ANOPR, the Commission identified four issues in organized market regions that were not 

being adequately addressed or 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 a period 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. 

4. The Commission received several thousand pages of comments from over a 

hundred commenters in response to the ANOPR (a list of commenters and their 

abbreviated names the Commission will use for them in this document appears in 

Appendix A).6

 After review of the comments, and pursuant to our responsibility under 

sections 205 and 206 of the Federal Power Act (FPA)7

 to ensure that rates, charges, 

classifications, and service of public utilities (and any rule, regulation, practice, or 

contract affecting any of these) are just and reasonable and not unduly discriminatory, the 

 

Notice of Proposed Rulemaking, 72 Fed. Reg. 36,276 (July 2, 2007), FERC Stats. & 

Regs. ¶ 32,617 (2007). 

6

 We do not summarize in this NOPR every comment received in response to the 

ANOPR. The Commission has reviewed and considered each comment submitted, 

however, and appreciates the careful consideration the commenters have given to this 

proceeding. 

7

 16 U.S.C. § 824d - 824e (2000). 
Docket Nos. RM07-19-000 and AD07-7-000 - 4 - 

Commission is making several proposals in this NOPR designed to ensure just and 

reasonable rates and to remedy undue discrimination and preference and to improve 

wholesale competition in regions with organized markets. These proposals reflect the 

record compiled by the Commission in its conferences and in comments to the ANOPR. 

These proposals, along with background information and a summary of comments 

received, will be described in detail in the sections below. 

5. In proposing the reforms in the four areas described below, the Commission 

recognizes that there are differences of opinion on the appropriate scope of this 

rulemaking, as well as on the four specific issues described in the ANOPR. We are 

therefore guided by the record in this proceeding and the need to undertake timely and 

concrete reforms where the record supports them. From the commencement of our first 

technical conference in this proceeding, our goal has been to identify any specific reforms 

that can be made to optimize the efficiency of organized markets for the benefit of 

customers, and ultimately the consumers who benefit from and pay for electricity 

services. As we explain further below, however, this proceeding does not represent the 

final effort to improve the efficiency of competitive markets. Rather, we will continue to 

evaluate other specific reforms that may be necessary. 

6. In the area of demand response and the use of market prices to elicit demand 

response, the Commission proposes several requirements for ISOs and RTOs. These 

proposals include requirements to: (1) accept bids from demand response resources in 

their markets for certain ancillary services, comparable to any other resources; (2) 

eliminate, during a system emergency, a charge to a buyer in the energy market for taking 
Docket Nos. RM07-19-000 and AD07-7-000 - 5 - 

less electric energy in the real-time market than purchased in the day-ahead market; (3) 

permit an aggregator of retail customers (ARC) 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. 

7. In the section on long-term power contracting, the Commission proposes that ISOs 

and RTOs be required 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 proposal is designed to 

promote greater use of long-term contracts through improving transparency among 

market participants. 

8. In the area of improving market monitoring, the Commission proposes that each 

RTO and ISO provide its MMU with access to market data, resources and personnel 

sufficient to carry out its duties, and that the MMU (or the external MMU in a hybrid 

structure) report directly to the RTO or ISO board. In addition, the Commission proposes 

to require that the MMU’s functions include: (1) identifying ineffective market rules and 

recommending proposed rules and tariff changes; (2) reviewing and reporting on the 

performance of the wholesale markets to the RTO or ISO, the Commission, and other 

interested entities; and (3) notifying appropriate Commission staff of instances in which a 

market participant’s behavior requires investigation. The Commission also proposes 
Docket Nos. RM07-19-000 and AD07-7-000 - 6 - 

expanding the list of recipients to receive MMU recommendations regarding rule and 

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

The Commission further proposes to remove the MMU from tariff administration, require 

each RTO and ISO to include ethics standards for MMU employees in its tariff, and 

consolidate all its MMU provisions in one section of its tariff. The Commission also 

proposes expanding the dissemination of MMU market information to a broader 

constituency, with reports made on a more frequent basis, and reducing the time period 

before energy market bid and offer data are released to the public. 

9. Finally, the Commission proposes to establish new criteria intended to ensure that 

an RTO or ISO is responsive to its customers and stakeholders, and ultimately to the 

consumers who benefit from and pay for electricity services. These principles will 

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

of minority positions; and (4) ongoing responsiveness. 

10. In each of these four areas, the Commission will require RTOs and ISOs to consult 

with their stakeholders and make a compliance filing that details why the entity’s existing 

practices comply with the final rule in this proceeding, or the entity’s plans to attain 

compliance. 

11. Finally, as indicated above, these reforms do not represent our final effort to 

improve the functioning of competitive organized markets for the benefit of consumers. 

For example, although we are proposing specific reforms to eliminate barriers to demand 

response, we propose to require each RTO or ISO to study whether further reforms are 

necessary to eliminate barriers to demand response in organized markets. Any reforms 
Docket Nos. RM07-19-000 and AD07-7-000 - 7 - 

must ensure that demand response resources are treated on a comparable basis as other 

resources. We also are ordering a staff technical conference on proposals by American 

Forest and Portland Cement Association, et al. to modify the design of organized 

markets. Finally, we direct, as explained further below, 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. The 

Commission therefore will continue to evaluate reforms in this area, but will not allow 

the prospect of other reforms to delay the benefits to consumers from those proposed 

herein. 

II. Background

12. As the Commission noted in the ANOPR, national policy has been, and continues 

to be, to foster competition in wholesale electric power markets.8

 This policy was 

embraced in the recent Energy Policy Act of 2005 (EPAct 2005),9

 and is reflected in 

Commission policy and practice. The Commission, in fulfilling its responsibility to 

“guard the consumer from exploitation by non-competitive electric power companies,”10

relies on both its own regulations and competition to ensure consumer protection. In 

doing so, the Commission is aware of the need to vary the mix of regulation and 

competition based on the circumstances of the time, taking into account advances of 

 8

 ANOPR, FERC Stats. & Regs. ¶ 32,617 at P 4. 

9

 Pub. L. No. 109-58, 119 Stat. 594 (2005). 

10 Nat’l Ass’n for the Advancement of Colored People v. FPC, 520 F.2d 432, 438 

(D.C. Cir. 1975), aff’d, 425 U.S. 662 (1976). 
Docket Nos. RM07-19-000 and AD07-7-000 - 8 - 

technology, changes in economies of scale, and new state and federal laws that affect the 

energy industry. 

13. 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. The Commission acknowledges that significant differences exist 

between regions, including differences in industry structure, mix of ownership, sources 

for 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. The Commission recognizes 

and respects these differences across various regions. At the same time, wholesale 

competition can serve customers well in all regions. The focus of this proceeding is on 

further improving the operation of wholesale competitive markets in organized market 

regions.11 

14. Some perceived challenges in the organized wholesale markets may be closely 

related to state retail issues, and the distinction between wholesale and retail competition 

 11 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-NE), California Independent Service Operator Corp. (CAISO), and Southwest 

Power Pool, Inc. (SPP). 
Docket Nos. RM07-19-000 and AD07-7-000 - 9 - 

challenges is often blurred. For example, wholesale customers typically have more 

advanced meters than retail customers; organized market rates vary with time of day 

whereas retail rates typically do not; and retail choice programs, which tend to be in areas 

served by organized wholesale markets, may rely on RTOs or ISOs to provide or arrange 

for the provision of some functions previously carried out by vertically integrated 

utilities. This has created challenges for wholesale market design. Although the 

Commission acknowledges that issues with retail markets are often intertwined with 

wholesale market issues, the Commission will not address retail market issues in this 

proceeding. This rulemaking is designed to focus on wholesale markets; issues related to 

retail markets will vary by state and are more appropriately considered in separate 

proceedings before the affected state(s) or the Commission where the specific interaction 

between the retail and wholesale market can be explored. 

15. Comments received on the ANOPR and made during technical conferences 

highlight several potential problems with wholesale competition both inside and outside 

the organized market regions that are within the scope of this proceeding. In the 

ANOPR, the Commission noted that it was not addressing potential reforms outside the 

organized market regions, explaining that many of the important concerns discussed 

during the first technical conference (e.g., nondiscriminatory access to transmission, 

nondiscriminatory rules for power procurement) were already being addressed in other 

proceedings. Similarly, the Commission has chosen to limit this proceeding to four 

discrete areas involving wholesale competition within organized markets. As explained 

further below, however, these are not the final reforms the Commission may pursue with 
Docket Nos. RM07-19-000 and AD07-7-000 - 10 - 

respect to organized markets; rather, we will continue to evaluate specific proposals that 

may serve to strengthen organized markets. 

III. Proposals to Expand the Scope of the Proceeding

16. Several parties propose to expand the scope of this proceeding beyond the four 

areas covered in the ANOPR. We received a request from APPA, in its comments on the 

ANOPR, and a request from AARP, et al., a group consisting of 41 entities, for a largescale investigation of the workings of organized markets with respect to their ability to 

produce just and reasonable rates. APPA and AARP, et al. state that the current market 

system allows incumbent sellers (those power suppliers with older power plants) to make 

excess profits while disadvantaging certain power suppliers with new generation. APPA 

and AARP, et al. argue that this has resulted in increased cost to consumers without the 

corresponding benefit of new generation being built. APPA and AARP, et al. claim that 

the Commission has a responsibility under sections 205 and 206 of the FPA to investigate 

the workings of organized markets based on their allegations of unjust and unreasonable 

rates. 

17. The Commission acknowledges the concerns of APPA and AARP, et al.; however, 

we decline to initiate the broad investigation APPA and AARP, et al. have requested as 

part of this proceeding. As noted above, by listening to the concerns of market 

participants, and evaluating the record of this proceeding, we have identified four specific 

areas in which reforms can improve wholesale electricity market operations. Through the 

competition conferences and the ANOPR process, we have developed a solid record in 

favor of making those reforms, and a strong sense of what the Commission can do to be 
Docket Nos. RM07-19-000 and AD07-7-000 - 11 - 

helpful in these four areas. It is important that the Commission move forward with 

regard to the specific reforms under consideration in this proposed rulemaking to foster 

improvements in the near term to the competitive operation of existing organized markets 

administered by RTOs and ISOs. Further, we also note that the approach we are taking in 

this NOPR is consistent with the ISO/RTO Council’s proposal.12

18. In contrast to the specific reforms proposed herein, APPA and AARP, et al. 

request a broad, generic inquiry into alleged (but not specified) market design flaws. 

Their request not only fails to offer any specific solutions, but also fails to appreciate the 

differences in market design that exist in each region. Over the past five years, the 

Commission has undertaken significant market design reforms in most regions. We have 

not adopted a standard market design, but rather have undertaken different reforms, at 

different times in each region to reflect the differing characteristics of each market. The 

Commission has devoted considerable resources over the years to improving the market 

designs in each organized market to ensure that they produce just and reasonable rates. 

We summarize some of these efforts below. 

19. For example, in response to the California energy crisis of 2000-2001, the 

Commission worked with CAISO and its stakeholders to develop a Market Redesign and 

Technology Upgrade program designed to improve the efficiency and proper working of 

 12 ISO/RTO Council urges the Commission to focus on determining the 

appropriate means of addressing issues that are ripe for this NOPR and which ones might 

be better considered in existing forums. It states that existing stakeholder processes 

provide an appropriate forum for targeted consideration of various issues, including the 

ones raised by APPA and AARP, et al. ISO/RTO Council at 1, 3. 
Docket Nos. RM07-19-000 and AD07-7-000 - 12 - 

the market through improved modeling and new forward markets,13 which the 

Commission subsequently approved in part. In 2004, the Commission approved the 

Midwest ISO’s open access transmission and energy markets tariff, which provides for 

terms and conditions necessary to implement a market-based congestion management 

program and energy spot markets. 14 This includes a day-ahead energy market and a realtime energy market, locational marginal pricing, and a market for financial transmission 

rights. 

20. The Commission has also acted on proposals developed by regional entities to 

ensure that adequate price signals exist in the market for both short-term and long-term 

electric power transactions, by addressing pricing issues during reserve shortages and by 

approving forward capacity markets. The Commission has approved a demand curve for 

capacity markets in the region operated by NYISO. The Commission approved PJM’s 

Reliability Pricing Model to provide an auction process for forward capacity contracting. 

The Commission also approved a settlement agreement for ISO-NE to create a 

transitional forward capacity market to meet the needs of its stakeholders.15 These 

 13 Cal. Indep. Sys. Operator Corp., 116 FERC ¶ 61,274 (2006), order on reh’g, 119 

FERC ¶ 61,076 (2007). 

14 Midwest Indep. Transmission Sys. Operator, Inc., 108 FERC ¶ 61,163, order on 

reh’g, 109 FERC ¶ 61,157 (2004), order on reh’g 111 FERC ¶ 61,043, reh’g denied, 112 

FERC ¶ 61,086 (2005), aff’d sub nom. Wisconsin Public Power, Inc. v. FERC, 493 F.3d 

239 (D.C. Cir. 2007). 

15 Devon Power, LLC, 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). 
Docket Nos. RM07-19-000 and AD07-7-000 - 13 - 

actions were designed to minimize the disruption during periods of operating reserve 

shortage and encourage new investment in generation, while accepting variation between 

regions and allowing for regional choice. 

21. The Commission has also issued region-specific orders providing for cost 

allocation for new transmission investment, removing uncertainty over the cost 

responsibility for the development of new transmission. In Opinion No. 494,16 the 

Commission approved PJM’s policy for determining recovery of transmission costs for 

existing and new facilities, providing for region-wide cost sharing for certain new extra 

high-voltage transmission facilities. The Commission also approved the Midwest ISO’s 

transitional pricing scheme, which incorporates cost sharing for new transmission 

facilities.17 

22. In addition to these region-specific actions, the Commission has addressed 

incentives for the building of new generation and transmission in all regions with 

organized markets. In Order No. 679,18 the Commission allowed parties building 

transmission to apply for recovery of prudently incurred costs for construction work in 

 16 PJM Interconnection, L.L.C., 119 FERC ¶ 61,063 (2007) (Opinion No. 494), 

reh’g pending. 

17 Midwest Indep. Transmission Sys. Operator, Inc., 114 FERC ¶ 61,106, order on 

reh’g and technical conference, 117 FERC ¶ 61,241 (2006), order on reh’g, 118 FERC ¶ 

61,208 (2007), appeal pending sub nom. Public Service Comm’n of Wisconsin v. FERC, 

No. 06-1408 (D.C. Cir., filed Dec. 13, 2006); Midwest Indep. Transmission Sys.

Operator, Inc., 118 FERC ¶ 61,209, order on reh’g, 120 FERC ¶ 61,080 (2007). 

18 Promoting Transmission Investment through Pricing Reform, Order No. 679, 

FERC Stats. & Regs. ¶ 31,222, order on reh’g, Order No. 679-A, FERC Stats. & Regs. ¶ 

31,236 (2006), order on reh’g, 119 FERC ¶ 61,062 (2007). 
Docket Nos. RM07-19-000 and AD07-7-000 - 14 - 

progress, pre-operations, and abandoned facilities, and it provided for application for an 

incentive rate of return on equity for new transmission investment. As a further means of 

reducing uncertainty and spurring investment, the Commission finalized rules for 

interconnection for large, small and wind generators. These rules remove barriers to 

interconnection by streamlining the process of, and improving incentives for, building 

new generation. The Commission has also acted to improve certainty in the cost of 

transmission for electric customers by creating rules for long-term transmission rights in 

Order Nos. 681 and 681-A.19

23. In Order No. 890, the Commission reformed the open access transmission tariff 

(OATT) to ensure that it continues to provide nondiscriminatory access to transmission 

service. Among other things, Order No. 890 requires an open and transparent regional 

transmission planning process.20 The Commission is now focusing on the compliance 

phase of OATT reform to ensure that it is implemented properly.21 The Commission also 

has been pursuing a cooperative dialogue with the National Association of Regulatory 

Utility Commissioners (NARUC) to identify and analyze models for competitive power 

 19 Long-Term Firm Transmission Rights in Organized Electricity Markets, Order

No. 681, FERC Stats. & Regs. ¶ 31,226, order on reh'g, Order No. 681-A, 117 FERC ¶ 

61,201 (2006).

20 This addresses, in part, concerns raised by some commenters regarding posting 

of future transmission constraints and congestion costs. 

21 ANOPR, FERC Stats. & Regs. ¶ 32,617 at P 33 (citing Preventing Undue 

Discrimination and Preference in Transmission Service, Order No. 890, 72 Fed. Reg. 

12,266 (Mar. 15, 2007), FERC Stats. & Regs. ¶ 31,241, order on reh’g, Order No. 890-A, 

FERC Stats. & Regs. ¶ 31,261 (2007)). 
Docket Nos. RM07-19-000 and AD07-7-000 - 15 - 

procurement. This effort is designed to enhance the ability of load-serving entities 

(LSEs) to acquire reliable power supplies at competitive prices. As noted in the ANOPR, 

the Commission has also acted to investigate demand response in organized markets, 

through a Commission report and a recent technical conference. This conference was 

designed to examine demand response resources in markets, grid operations and 

expansion, and best practices for the measurement and evaluation of demand response 

resources.

22 The Commission also held a technical conference on December 11, 2007 to 

explore issues surrounding the management of interconnection queues.23

24. In recognition of our continuing respect for regional differences in market design, 

we believe that, if there are specific concerns about the market designs in a particular 

region, they should be considered, in the first instance, at the regional level. We 

therefore direct each RTO or ISO to provide a forum for affected consumers to voice 

specific concerns (and to propose regional solutions) to the issues raised generically by 

APPA and AARP, et al. Although most existing stakeholder processes already allow for 

the submission of such proposals, we encourage RTOs and ISOs to give priority to any 

significant concerns that may be raised on these issues, including concerns as to the value 

to the market of significant changes to the market rules. For example, PJM recently has 

conducted a series of forums on long-term contracts to gather information and facilitate 

 22 Supplemental Notice, Demand Response in Wholesale Markets, Docket No. 

AD07-11-000 (April 6, 2007). 

23 Notice of Technical Conference, Interconnection Queuing Practices, Docket No. 

AD08-2-000 (November 2, 2007). 
Docket Nos. RM07-19-000 and AD07-7-000 - 16 - 

the exchange of ideas on this important issue. We encourage similar efforts on the 

concerns raised by APPA and AARP, et al. Any proposed solutions should be vetted 

through the stakeholder process and ultimately considered by the boards of the RTOs or 

ISOs. Ultimately, such matters may be brought to the Commission after consideration by 

the region. We encourage each region to commence the consideration of any such issues 

in the near future and not await the issuance of a final rule in this proceeding. 

25. However, those entities that have such concerns have a responsibility to propose 

solutions to address those concerns. For example, American Forest submitted comments 

that contained a mechanism, the Financial Performance Obligation (FPO), to address 

concerns that they raised regarding the structure of organized markets. Portland Cement 

Association, et al., also included a proposed solution in its comments to address their 

concerns regarding the organized markets. We are encouraged by entities that actually 

propose solutions rather than merely identify concerns without proposing any meaningful 

ways to address those concerns. While we do not adopt these proposals in this 

proceeding, we believe that they warrant additional consideration. Therefore, as 

explained below, we direct Staff to convene a technical conference regarding the 

American Forest and Portland Cement Association, et al., proposals so that the 

Commission and the industry can learn more about the proposals and the merit of 

adopting such changes where appropriate. 
Docket Nos. RM07-19-000 and AD07-7-000 - 17 - 

IV. Discussion

A. Demand Response and Pricing During Periods of Operating Reserve

Shortages in Organized Markets

26. This section of the NOPR proposes several reforms to further eliminate barriers to 

demand response in organized energy markets. These reforms must ensure that demand 

response is treated comparably to other resources. The Commission proposes to require 

RTOs and ISOs to: (1) accept bids from demand response resources in their markets for 

certain ancillary services, comparable to other resources; (2) eliminate, during a system 

emergency, certain charges to buyers in the energy market for voluntarily reducing 

demand; and (3) permit ARCs to bid demand response on behalf of retail customers 

directly into the RTO’s or ISO’s organized markets.24 We also propose that RTOs and 

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

shortage. These proposals, if adopted, would require market rules to ensure that demand 

response can participate directly and is treated comparably to supply resources in the 

organized electric energy and ancillary services markets. We also propose to require that 

each RTO and ISO study further reforms to address any remaining barriers to ensure that 

demand response is treated comparably to other resources and to report to the 

Commission within six months of the date of the final rule in this proceeding. In 

addition, we propose that each RTO or ISO must adopt reasonable standards necessary 

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

 24 We will use the phrase “aggregation of retail customers” to refer to parties that 

aggregate demand response bids (which are mostly from retail loads), or ARCs. 
Docket Nos. RM07-19-000 and AD07-7-000 - 18 - 

verify, and ensure compliance with any such standards.25 As discussed further below, we 

intend to direct staff to convene a technical conference to explore issues that the RTOs 

and ISOs should include as part of these studies. The specific reforms being proposed 

here are therefore the next step in removing barriers to demand response, but not the final 

step. 

1. Background

27. The Commission has expressed the view on numerous occasions that the wholesale 

electric power market works best when demand can respond to the wholesale price.26 

Based on the view that the value to customers of electric power varies,27 the 

Commission’s policy is to eliminate barriers to the participation of demand response in 

the organized power markets, in part because demand response helps to hold down 

wholesale power prices; increases awareness of energy usage; provides for more efficient 

operation of markets; mitigates market power; enhances reliability; and encourages new 

technologies that support the use of renewable energy resources, distributed generation, 

 25 We understand that some RTOs and ISOs may already be developing 

measurement and verification requirements, as well as appropriate mechanisms to ensure 

compliance. It is not our intention that these programs be delayed based on our proposals 

here. 

26 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). 

27 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 - 19 - 

and advanced metering. The reforms we propose today would further facilitate demand 

response by removing several barriers to demand response. This will benefit customers 

of electric energy because increased demand response will improve price signals and 

provide for greater flexibility. We provide background on the benefits of demand 

response and prior Commission actions addressing demand response below. 

a. Importance of Demand Response to Competition in 

RTO/ISO Areas

28. A well-functioning competitive wholesale electric market should reflect current 

supply and demand conditions. Enabling demand-side responses, 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. 

29. Demand response helps to reduce prices in competitive wholesale markets in at 

least three ways. First, demand response has both a direct effect and an indirect effect on 

wholesale demand. The direct effect occurs when demand response is bid directly into 

the wholesale market: lower demand means a lower wholesale price. Demand response 

at retail, if not bid directly into the wholesale market by a retail customer, affects the 

wholesale market indirectly because it reduces the need for power by the retail 

customers’ LSE and in turn reduces that LSE’s need to purchase power from the 

wholesale market.28

 28 See Federal Energy Regulatory Commission, Assessment of Demand Response 

and Advanced Metering: Staff Report, Docket No. AD06-2-000, at 11 (August 8, 2006) 

(2006 FERC Staff Demand Response Assessment). 
Docket Nos. RM07-19-000 and AD07-7-000 - 20 - 

30. Second, demand response tends to flatten an area’s load profile. The combination 

of reductions in peak demand and a shift of at least a portion of this peak demand to nonpeak periods due to demand response would tend to make peak and off-peak demand less 

divergent—a flatter load profile. A flatter load profile would reduce the need to use the 

more costly resources during periods of high demand, which tends to shift the distribution 

of resource types toward lower-cost base load generation and away from higher-cost 

peaking generation. This effect tends to lower the overall average cost to produce 

energy.29

31. Third, demand response can help reduce generator market power. As more 

demand response generally is available during peak periods, power suppliers need to 

account more for the price responsiveness of load when they consider submitting higherprice bids. The more demand response is able to reduce the peak price, the more 

downward pressure it places on generator bidding strategies by increasing the risk to a 

supplier that it will not be dispatched if it bids too high.30

b. Prior Commission Actions To Address Demand Response

32. The Commission has issued numerous orders over the last several years on various 

aspects of electric demand response in organized markets. A goal of most of these orders 

 29 Id.

30 Id. at 12 
Docket Nos. RM07-19-000 and AD07-7-000 - 21 - 

was to remove unnecessary obstacles to demand response participating in the wholesale 

power markets of RTOs and ISOs.31

33. These orders approved various types of demand response programs, including 

programs to allow demand response to be used as a capacity resource32 and as a resource 

during system emergencies,33 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.34 The Commission also has approved special 

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

 31 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). 

32 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). 

33 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). 

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

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

101 FERC ¶ 61,344 (2002), order on reh'g, 103 FERC ¶ 61,304, order on reh'g, 105 

FERC ¶ 61,211 (2003); PJM Interconnection, L.L.C., 99 FERC ¶ 61,227 (2002). 
Docket Nos. RM07-19-000 and AD07-7-000 - 22 - 

and regulation service.35 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. 

34. The Commission has approved programs that allow smaller retail customers—that 

cannot individually meet the RTO or ISO minimum bid size threshold—to combine 

individual demand response into a larger block for bidding into the organized markets, if 

permitted by state law, without having to go through their LSE.36 A third-party ARC, 

often called a curtailment service provider, typically provides this aggregation service. 

The aggregate demand response may be bid directly into the energy and ancillary 

services markets. 

35. In addition, the Commission has explicitly addressed demand response in its 

recent Final Rules on OATT Reform (Order No. 890) and reliability standards (Order No. 

693).37 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. Specifically, the Commission agreed with Alcoa’s 

request that load resources (i.e., demand response) should be permitted to self-supply and 

 35 See, e.g., PJM Interconnection, L.L.C., 114 FERC ¶ 61,201 (2006). 

36 Supra note 34. 

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

693, 72 Fed. Reg 16,416 (April 4, 2007), FERC Stats. & Regs. ¶ 31,242, order on reh’g, 

Order No. 693-A, 120 FERC ¶ 61,053 (2007). 
Docket Nos. RM07-19-000 and AD07-7-000 - 23 - 

sell ancillary services to third parties.38 In doing so, the Commission also made clear that 

a transmission provider may use non-generation resources in meeting its OATT 

obligation to provide ancillary services, so long as those resources are capable of 

providing the service.39 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.40

36. The Commission has also worked closely with state regulators to examine demand 

response issues. The NARUC-FERC Collaborative Dialogue on Demand Response 

began in November 2006 to explore state-federal coordination of efforts to promote and 

integrate demand response into retail and wholesale markets. The Commission has 

conducted several technical conferences on demand response over the last several years, 

most recently on April 23, 2007.41 In addition, as mentioned, in response to a 

 38 Order No. 890, FERC Stats. & Regs. ¶ 31,241 at P 887-88. 

39 E.g., Order No. 890, FERC Stats. & Regs. ¶ 31,241 at OATT Schedule 5 

(Operating Reserve – Spinning Reserve Service). Order No. 890 does not require 

transmission providers, however, to purchase ancillary services from non-generation 

resources or generation resources. 

40 Order No. 693 directed the Electricity Reliability Organization to develop new 

versions of its BAL-002, BAL-005, and EOP-002 reliability standards to allow demand 

side resources to provide contingency reserves. Order No. 693, FERC Stats. & Regs. ¶ 

31,242 at P 330-35, 404-06, 573. 

41 For example, the Commission conducted a technical conference on January 25, 

2006 to help prepare for a survey and a staff report on demand response in Docket No. 

AD06-2-000. See supra note 28. The April 23, 2007 conference was convened in 

Docket No. AD07-11-000. 
Docket Nos. RM07-19-000 and AD07-7-000 - 24 - 

requirement of EPAct 200542 to assess demand response capability nationally, in August 

2006 the Commission published a staff report on demand response and advanced 

metering.43 In September 2007, the Commission published its second annual staff report 

on demand response and advanced metering.44

2. The Need for Commission Action 

37. 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. The 2006 FERC Staff Demand 

Response Assessment estimated the total installed demand response capability from 

existing programs nationally to be 37,500 MWs, or about five percent of current peak 

demand.45 Several reports indicate that the potential demand response capability 

available in the United States may be much greater.46 

38. The Commission’s policy is to eliminate barriers to the participation of demand 

response in the organized power markets by ensuring comparable treatment of resources. 

This position is consistent with EPAct 2005, which states that demand response shall be 

 42 Pub. L. No. 109-58, § 1252(e)(3), 119 Stat. 594, 966 (2005). 

43 See 2006 FERC Staff Demand Response Assessment. 

44 See Federal Energy Regulatory Commission, 2007 Assessment of Demand 

Response and Advanced Metering: Staff Report, (September 2007) (2007 FERC Staff 

Demand Response Assessment). 

45 2006 FERC Staff Demand Response Assessment at 7. 

46 See, e.g., Ahmad Faruqui et al., The Brattle Group, The Power of Five Percent: 

How Dynamic Pricing Can Save $35 Billion in Electricity Costs (May 16, 2007), 

available at http://www.brattle.com/_documents/UploadLibrary/Upload574.pdf. 
Docket Nos. RM07-19-000 and AD07-7-000 - 25 - 

encouraged and unnecessary barriers to demand response participation in energy, 

capacity, and ancillary service markets shall be eliminated.47 The Commission can take 

additional steps to further encourage demand response to improve the operation of the 

organized energy and ancillary services markets by removing several unnecessary 

barriers to demand response participation.48 

39. The Commission can further eliminate barriers to the participation of demand 

response in certain ancillary services markets. Some forms of demand response are well 

suited to provide the ancillary services of spinning reserves, supplemental reserves, 

energy imbalance, and regulation and frequency response.49 Because demand is always 

connected and demand response, in principle, can always be available, some forms of 

 47 Section 1252(f) of the EPAct 2005 states that, “[i]t is the policy of the United 

States that time-based pricing and other forms of demand response whereby electricity 

customers are provided with electricity price signals and the ability to benefit by 

responding to them, shall be encouraged, the deployment of such technology and devices 

that enable electricity customers to participate in such pricing and demand response 

systems shall be facilitated, and unnecessary barriers to demand response participation in 

energy, capacity, and ancillary service markets shall be eliminated.” 

48 We note that while the Commission can remove some obstacles to demand 

participation in organized markets, more effective demand response also requires the 

action of state commissions. An effective way for demand to respond to price is at the 

retail level, through some form of time-based retail rates (e.g., rates that vary by hour, 

such as real-time pricing, or by blocks of time, such as time-of-use rates or critical peak 

pricing). Demand response is more effective when retail rates are tied to current 

wholesale market-clearing prices. Effective demand response can be achieved by linking 

the wholesale and retail markets. 

49 See 2006 FERC Staff Demand Response Assessment at 51. For an explanation 

of each of these ancillary services, see the pro forma OATT, Schedules 3 through 6, 

contained in Order No. 890. 
Docket Nos. RM07-19-000 and AD07-7-000 - 26 - 

demand response resources may be able to provide a rapid, near real-time response.50 

Nevertheless, not all RTOs and ISOs allow demand response to participate in ancillary 

services markets. ISO-NE, NYISO, and CAISO allow demand response resources to 

provide supplemental (non-spinning) reserves. As of mid-2007, only PJM allows 

demand response resources to provide synchronized reserves (PJM’s term for spinning 

reserves) and regulation service.51 

40. In Order No. 890, the Commission modified the definitions of certain ancillary 

services in the pro forma open access transmission tariff to clarify that demand response 

is eligible to supply these ancillary services on a comparable basis to generation 

resources. Order No. 890 concluded, however, that procurement and pricing of ancillary 

services—including issues related to competitive procurement—were beyond the scope 

of that rulemaking. Though RTOs and ISOs procure ancillary services through 

competitive market means, they are not currently required to accept bids from qualified 

demand response providers to provide ancillary services even if those providers are 

technically capable of doing so. This hinders the integration of qualified demand 

response resources into these RTO and ISO ancillary services markets. 

41. One reason for the lack of participation of demand response in some ancillary 

service markets may be that market rules for bidding and participating in ancillary 

 50 For example, electric-arc steel furnaces have the capability to adjust their 

consumption rapidly, and air conditioner cycling programs can respond within several 

minutes of execution. 

51 We note, however, that no resource has yet qualified to provide this service to 

PJM. 
Docket Nos. RM07-19-000 and AD07-7-000 - 27 - 

services markets were developed with generation in mind and may not accommodate 

demand response resources. For example, many demand response resources can respond 

quickly and at a low cost if called upon for a short duration, which may make them well 

suited for providing operating reserves. If market rules require, however, that a single 

bid be made into a joint energy-plus-reserves market (also known as a “co-optimized” 

market), those seeking to offer operating reserves risk being dispatched to provide energy 

or other ancillary services for which they are not well suited. As a result, a potential 

operating reserve provider that does not wish to be called upon frequently or for a 

prolonged period in the energy market may simply decide not to participate in a cooptimized market, and consequently not be a source for providing demand response 

resources as operating reserves. Market rules that do not allow a demand response 

provider to limit the frequency and duration of interruption may thereby create a 

disincentive for a demand response resource to bid into the operating reserves market.52 

42. Further, demand response providers need market rules that allow bids to be flexible 

and that reflect bidders’ willingness to offer various levels of service depending on the 

market prices. While the design of today’s organized markets does allow some flexible 

and some price-sensitive bidding into day-ahead and real-time energy markets, the 

Commission is nevertheless concerned that some market features may inhibit LSEs and 

other demand response providers from bidding load reductions into energy markets. For 

example, in most organized markets, if an LSE’s actual purchase from the real-time 

 52 See 2006 FERC Staff Demand Response Assessment at 123. 
Docket Nos. RM07-19-000 and AD07-7-000 - 28 - 

market differs from the purchase it scheduled in the day-ahead market, it may be assessed 

an uplift charge (separate from any imbalance charge). This uplift charge recovers 

certain costs of extra generation when day-ahead purchases exceed real-time purchases. 

However, these costs may be minimal during an emergency when there is no extra 

generation. Further, this uplift charge may unnecessarily discourage an LSE from urging 

retail customers to conserve energy during a system emergency. RTO and ISO tariffs 

also do not impose these types of charges on generators that generate more power during 

system emergencies than scheduled. Eliminating this uplift charge for demand response 

sought by RTOs or ISOs from buyers in an emergency removes a disincentive for this 

demand response and promotes comparable treatment of demand and supply resources. 

43. Organized energy market rules also may restrict the type of bid that a LSE or ARC 

may submit.53 There is usually a minimum bid size threshold in an RTO or ISO market. 

Also, it is hard for some demand response providers to participate if, for example, they 

are not able to start and stop frequently or if cycling output up and down produces 

excessive stress on their equipment. Aggregation programs can improve the participation 

of small retail loads that lack standing as an LSE or individually cannot meet a 

requirement that a demand response bid be of minimum size. These programs allow a 

larger number of customers to access demand response programs, which increases the 

potential market and reliability benefits realized from demand response in wholesale 

 53 In some cases, this may be intended to treat a demand response resource bid the 

same as a generation bid, but more often, bidding features available to generation, such as 

a guaranteed minimum price, are not available to demand response resources. 
Docket Nos. RM07-19-000 and AD07-7-000 - 29 - 

markets. The 2006 FERC Staff Demand Response Assessment and comments that we 

have received indicate, however, that more needs to be done to facilitate the direct 

participation of ARCs in energy markets. 

44. Another factor that may limit participation in demand response programs is the use 

of bid caps and price caps in wholesale market design. Bid caps and price caps in RTO 

and ISO markets are designed to limit the opportunity to exercise market power in these 

markets, but they also may prevent the markets from expressing prices that are 

legitimately high due to a shortage. These caps may not permit buyers in RTO and ISO 

wholesale energy markets to see prices high enough to signal that there is a period of 

operating reserve shortage and that reliability is at risk. Moreover, when power is in 

short supply and price is high, retail prices remain fixed, and retail customers do not 

adjust their demand to react to wholesale price signals. Consequently, both generation 

and demand response can be in short supply at once, and the market-clearing price may 

not reflect the actual cost of providing more power or the value to customers of not being 

interrupted. Further, as discussed in the long-term contracting section below, capping the 

exposure of LSEs to higher prices may reduce their incentive to explore various hedging 

activities, such as participating in interruptible demand response programs, entering into 

long-term contracts or similar power supply procurement options, and building new 

generating units. 

45. Certain demand response programs may themselves act to dampen prices during a 

period of operating reserve shortage. The term “emergency demand response program” 

is used here to refer to a demand response program where participants agree to reduce 
Docket Nos. RM07-19-000 and AD07-7-000 - 30 - 

demand if called on by the RTO or ISO during a system emergency. They may be paid a 

fixed price rather than the market-clearing price when called on. As a result, the marketclearing price may decrease because demand is reduced when an emergency demand 

response resource is used, even though that resource is the highest-valued resource used 

at the time. The reduced price is contrary to the signal that should be sent in an 

emergency. Only NYISO has integrated its emergency demand response programs into 

the market-clearing process.54

3. Proposed Reforms

46. In order to further eliminate barriers to demand response in organized markets, the 

Commission proposes reforms to obligate RTOs and ISOs to: (1) accept bids from 

demand response resources in its markets for certain ancillary services, comparable to 

any other resources; (2) eliminate, during a system emergency, a charge to a buyer in the 

energy market for taking less electric energy in the real-time market than purchased in the 

day-ahead market; (3) permit an ARC to bid a demand response on behalf of retail 

customers directly into the RTO’s or ISO’s organized energy markets, unless the laws or 

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

customer to participate; and (4) modify their market rules to allow the market-clearing 

price to accurately reflect the value of energy during periods of operating reserve 

shortage. The Commission also proposes to require RTOs and ISOs to study whether 

further reforms are necessary to eliminate barriers to demand response in organized 

 54 The Commission approved this change in 2003. New York Indep. Sys.

Operator, Inc., 102 FERC ¶ 61,313 (2003). 
Docket Nos. RM07-19-000 and AD07-7-000 - 31 - 

markets. We believe that these proposals ensure comparable treatment of demand 

response resources. We discuss these proposals in greater detail below. 

a. Ancillary Services Provided by Demand Response

Resources

i. Preliminary Proposals in the ANOPR

47. In the ANOPR, the Commission sought comment on obligating RTOs and ISOs to 

purchase demand response resources in their markets for certain ancillary services, 

similar to any other resources, if the resources meet the necessary technical requirements 

and submit a bid under the generally-applicable bidding rules at or below the marketclearing price. The Commission contemplated granting an exception where the seller 

would not be permitted to do so by state retail laws or regulations. The Commission 

proposed to require modifications to RTO and ISO tariffs that would apply this 

requirement for energy imbalance, spinning reserves, and supplemental reserves, as 

defined in the pro forma OATT, or their functional equivalents in an RTO or ISO tariff. 

To be eligible to supply these ancillary services, the Commission stated that demand 

response resources must be capable of reducing demand within seconds or minutes and 

must meet the RTO’s or ISO’s reasonable size, telemetry, metering, and bidding 

requirements. 

48. The Commission also sought comment on requiring modifications to RTO and 

ISO tariffs to provide that demand response resources must be allowed to provide 

spinning and supplemental reserves without also being required to sell into the energy 

market. 
Docket Nos. RM07-19-000 and AD07-7-000 - 32 - 

49. The Commission requested comment on, among other things, whether each RTO 

or ISO should propose its own minimum requirements (for example, as to minimum size 

bids, measurement, and telemetry) or whether the Commission should specify the 

appropriate minimum requirements in a Commission rule. 

ii. Comments on the ANOPR Proposals and Questions

50. Most of the commenters that address the Commission’s proposal in the ANOPR 

support having an RTO or ISO accept bids from demand response resources for certain 

ancillary services on a comparable basis. For example, BlueStar Energy states that the 

Commission’s proposal “will lead to greater economic efficiency, and reduce costs and 

risks for retail customers.”55 Industrial Coalitions states that the Commission’s current 

proposal is the next logical step, after Order No. 890, in promoting the integration of 

demand response resources into all RTO- and ISO-coordinated markets and services.56 

51. Other commenters raise concerns with the ability of smaller entities to fully 

participate as resource providers for ancillary services. APPA argues that it may be 

difficult to reconcile the technical requirements for end users, necessitated by the 

instantaneous nature of certain ancillary services, with the desire of many larger loads for 

reliability, flexibility, and convenience, thus making it unlikely that many demand 

response resources will want to provide ancillary services.57 The California PUC argues 

that requiring demand response resources to satisfy all requirements for service provision 

 55 BlueStar Energy at 2. 

56 Industrial Coalitions at 13-14. 

57 APPA at 48. 
Docket Nos. RM07-19-000 and AD07-7-000 - 33 - 

comparable to those applied to supply resources could construct considerable barriers to 

participation of small demand response resources.58 

52. NYISO and National Grid support the participation of demand response to the 

extent practical in the ancillary services market. They request, however, that the 

Commission clarify that it would not require the RTO or ISO to “purchase” certain 

ancillary services from demand response resources but to accept bids from them.59

53. Multiple commenters supported the Commission’s proposal to allow demand 

response resources to provide reserves without being required to sell into the energy 

market. Alcoa, for example, states that demand-responsive load supplying ancillary 

services does not create market power concerns because such services are not the primary 

business of demand response resources.60 Strategic Energy states that the proposal would 

allow customers to offer operating reserves without disrupting the company business via 

prolonged shutdowns to satisfy an energy schedule.61 

54. Conversely, several commenters oppose the Commission’s proposal. ISO-NE 

does not support the proposal because its core market design does not allow separate bids 

to be placed in the energy and reserve markets for any resources.62 NYISO concurs, 

claiming that the proposal would not be efficient in New York because NYISO’s market 

 58 California PUC at 7. 

59 NYISO at 28; National Grid at 5. 

60 Alcoa at 18-19. 

61 Strategic Energy at 4. 

62 ISO-NE at 19. 
Docket Nos. RM07-19-000 and AD07-7-000 - 34 - 

design co-optimizes energy and ancillary services through an integrated dispatch process 

and generators in New York must make themselves available to supply energy in order to 

be eligible to supply ancillary services.63 Thus, any change to NYISO’s market design 

could lead to inefficient scheduling outcomes. NYISO does state, however, that its 

existing bidding procedures are flexible enough to permit demand response resources to 

structure their bids in a way that virtually eliminates the possibility that they may be 

selected to provide energy involuntarily. NYISO asserts that it could develop new 

bidding rules that would allow demand response resources to specify that they: (1) could 

not be called on for more than an hour or a certain maximum number of times per day; or 

(2) would be subject to energy management limits. NYISO asserts that such rules would 

allow demand side resources to convey their limitations on frequency and duration of 

activation without undermining the co-optimized market design. 

55. A majority of commenters assert that the Commission should allow RTOs and 

ISOs to develop their own minimum requirements for demand response participation in 

ancillary services markets. EEI states that the Commission recognized that the various 

organized markets and state regulatory programs are different and had different physical 

and state requirements.64 Dominion Resources, Pepco, PGC, PG&E, and SPP agree. EEI 

further argues that given all the regional differences in control systems and market 

software, having a standardized set of requirements may result in unnecessary expense 

 63 NYISO at 32. 

64 EEI at 12. 
Docket Nos. RM07-19-000 and AD07-7-000 - 35 - 

and delay in implementation in certain regions by requiring incompatible infrastructure. 

PGC claims that a “one-size fits all” minimum requirements rule would be inappropriate, 

and states that allowing each RTO or ISO region to establish its own requirements would 

permit each system the flexibility to modify requirements as they gain additional 

experience with demand response resources.65 Pepco argues for RTO/ISO-established 

technical requirements because the types of generation resources available, transmission 

constraints, and load pattern characteristics for each region would all be taken into 

account, and would be appropriate for that region.66

iii. Commission Proposal

56. The Commission proposes 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 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. 

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 

 65 PGC at 10-11. 

66 Pepco at 7. 
Docket Nos. RM07-19-000 and AD07-7-000 - 36 - 

of their functional equivalents in an RTO or ISO tariff. We propose that demand 

response resources that are capable of reducing demand within the response time 

requirement for the ancillary service and that meet reasonable requirements adopted by 

the RTO or ISO as to size, telemetry, metering, and bidding be eligible to supply energy 

imbalance, spinning reserves, supplemental reserves, reactive and voltage control, and 

regulation and frequency response. In the compliance filing to be submitted within six 

months of the final rule, the RTO or ISO must 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. Such standards would be subject 

to Commission approval. 

57. We believe that this policy would increase the competitiveness of ancillary services 

markets, help reduce the price of ancillary services, and improve the reliability of the 

grid. Experience in the PJM, CAISO, and ERCOT markets has demonstrated that certain 

demand response resources can provide some ancillary services reliably. Moreover, this 

proposal would require that, for ancillary services acquired in a competitive process, 

RTOs and ISOs make any necessary changes to their tariffs and market rules to allow for 

direct demand response resource participation in the ancillary services markets. 

58. We clarify, in response to NYISO’s and National Grid’s requests, that this proposal 

would not require an RTO or ISO to purchase certain ancillary services from demand 

response resources, but rather to accept bids from them for ancillary services acquired in 

a competitive bidding process, and if they meet minimum technical requirements and 

clear the market, on a basis comparable to other resources. The purpose of the proposal 
Docket Nos. RM07-19-000 and AD07-7-000 - 37 - 

is to ensure that all RTOs and ISOs treat demand response resources comparably with 

other resources in the market rules for energy imbalance, spinning reserves, supplemental 

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

proposal does not require the adoption of a competitive bidding process where one was 

previously not utilized. 

59. The California PUC’s argument that ancillary services market rules for 

comparable and nondiscriminatory access for demand response resources may be a 

barrier to participation of small demand response resources has merit. Experiments and 

pilot programs suggest that resources below minimum size thresholds in RTO and ISO 

markets have the potential to respond quickly and reliably.67 Adjusting minimum size 

thresholds and telemetry requirements to accommodate smaller demand response 

resources may result in a significant increase in potential sources of operating reserves. 

Without extensive experience with the ability of smaller demand response resources to 

provide ancillary services, however, it is premature to mandate specific conditions under 

which RTOs and ISOs must accommodate smaller resources into the spinning reserves, 

supplemental reserves, energy imbalance markets, reactive and voltage control, and 

regulation and frequency response. Instead, we propose to direct the RTOs and ISOs to 

perform an assessment of the technical feasibility and value to the market of smaller 

loads providing some ancillary services one year from the effective date of the final rule, 

 67 See 2006 FERC Staff Demand Response Assessment at 114. 
Docket Nos. RM07-19-000 and AD07-7-000 - 38 - 

including whether (and how) smaller resources can reliably and economically provide 

operating reserves through pilot projects or other mechanisms.68 

60. In the ANOPR, the Commission made a preliminary proposal to remove a 

disincentive for demand response to offer operating reserves. The proposal was to 

modify RTO and ISO tariffs to provide that demand resources must be allowed to provide 

spinning and supplemental reserves without also being required to sell into the energy 

market, explaining that customers may be more likely to offer demand response as 

operating reserves if they do not need to worry about disruptions to their businesses by 

participating in the energy markets. We are sympathetic, however, to concerns raised in 

ISO-NE’s and NYISO’s comments that the ANOPR proposal could undo their recent 

success in resolving design problems of disjointed markets by combining and cooptimizing their energy and ancillary services markets. The Commission is mindful of 

these concerns and does not intend to negatively affect the market efficiencies created by 

co-optimized market designs. 

61. NYISO suggests, however, that the development of new bidding rules could limit 

the exposure of demand response resources selling into the energy market—rules that 

would not require changes to its co-optimized markets. Resource bids in RTO and ISO 

markets typically allow bidders to specify various parameters of their bid (e.g., price, 

quantity, startup and no-load costs, and minimum downtime between starts). NYISO 

suggests new parameters that would allow demand response bidders to specify additional 

 68 For example, ISO-NE is assessing whether small demand response resources 

can provide operating reserves in its Demand Response Reserves Pilot. 
Docket Nos. RM07-19-000 and AD07-7-000 - 39 - 

constraints on the dispatch of their resources. In its comments, NYISO offers that a 

demand response bidder could specify the maximum duration in hours that a bid can be 

dispatched, maximum number of times that a bid can be dispatched during a day, and a 

maximum amount of energy that a resource can produce either daily or weekly, and that 

those parameters could be incorporated into the bidding rules. We believe that NYISO’s 

suggestion has merit. 

62. We propose here 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 cooptimized RTO markets. These limits are comparable to the limits generators may 

specify on price, quantity, startup and no-load costs, and minimum downtime between 

starts—limits that may not be available to demand response resources. The proposal is 

for RTOs and ISOs to incorporate new parameters into their 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 a maximum amount of electric 

energy that the demand response resource may be required to provide either daily or 

weekly. We expect that this requirement would encourage demand response in the 

spinning reserves, supplemental reserves, and regulation and frequency response markets 

by reducing the risk that demand response resources would be called on too frequently or 

for too long a period. We ask for comment on whether these new parameters should be 

available for all bids, not just demand response resources. These new bidding parameters 
Docket Nos. RM07-19-000 and AD07-7-000 - 40 - 

could benefit energy-limited resources or runtime-limited resources, e.g., hydropower 

and units with environmental restrictions. The new bidding parameters could also benefit 

resources that cannot start and stop quickly. The proposal should not require 

fundamental changes to existing market designs,69 or affect the efficiencies of cooptimized markets. 

63. 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 will assess whether each 

filing satisfies the proposed requirement and will issue additional orders as necessary. 

64. We request comment on this proposed requirement for RTOs and ISOs to allow 

demand response resources to specify 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, and on whether other bidding parameters should be 

considered. We note that any parameters must accommodate the characteristics of 

demand response resources but must not have the effect of creating an undue preference 

for demand response resources vis-à-vis other resources. Further, we intend that the 

bidding parameters would be implemented at all RTOs and ISOs. Finally, we agree with 

commenters that it would not be appropriate for the Commission to develop in a 

rulemaking a standardized set of minimum requirements for minimum size bids, 

 69 Bidding rules at RTOs and ISOs such as Midwest ISO and PJM already 

incorporate aspects of these proposed new bidding parameters. 
Docket Nos. RM07-19-000 and AD07-7-000 - 41 - 

measurement, telemetry, and other factors. Instead, we will allow each RTO or ISO to 

develop its own minimum requirements, including bidding parameters. We propose to 

require the RTOs and ISOs confer with each other and to provide a technical and factual 

basis for any necessary regional variations. 

b. Deviation Charge

i. Preliminary Proposals in the ANOPR

65. In the ANOPR, the Commission stated that it was considering a proposal to modify 

RTO and ISO tariffs to eliminate, during a system emergency, a charge to a buyer in the 

energy market for taking less electric energy in the real-time market than purchased in the 

day-ahead market.70 

66. The Commission requested comment on whether an RTO or ISO should assess a 

deviation charge for a day-ahead to real-time load reduction in the absence of a system 

emergency. The Commission noted that eliminating the deviation charge might have 

unintended consequences and asked whether it would result in an unfair reallocation of 

these costs to others; whether it was important to retain the deviation charge to 

discourage poor scheduling practices; or whether eliminating the deviation charge would 

introduce opportunities for gaming behavior. 

ii. Comments on the ANOPR Proposals and Questions

67. The vast majority of commenters support the preliminary proposal in the ANOPR 

to modify RTO and ISO tariffs to eliminate a deviation charge during a system 

 70 The Commission noted that it would refer to the charge that it proposed to 

eliminate during an emergency as a “deviation charge.” 
Docket Nos. RM07-19-000 and AD07-7-000 - 42 - 

emergency.

71 For instance, APPA asserts that it does not make much sense to penalize 

entities that help the RTO alleviate a system emergency.72 SMUD states that eliminating 

penalties for load reductions during a system emergency is a sensible approach to 

promoting further development of demand response as a resource eligible to be bid into 

organized markets.73

68. Several supporters prefer allowing RTOs and ISOs the flexibility to establish rules 

for settling deviations. For example, SoCal Edison-SDG&E believe each RTO or ISO is 

different, and that allowing each region to determine specific deviation charges based on 

individual circumstances may make more sense than adopting uniform standards. In their 

opinion, such an approach would help mitigate any unintended consequences, such as 

gaming.74

69. Other commenters who disagree with the Commission’s preliminary proposal are 

concerned about the uplift costs resulting from the elimination of deviation charges. DC 

Energy argues that eliminating the deviation charge penalty for demand response 

participants would negatively impact the market and result in unfair cost reallocation.75 It 

 71 A number of commenters appear to misunderstand the proposal. Several did not 

distinguish a voluntary reduction in power purchase between day-ahead and real time (the 

intent here) from a demand response bidder that fails to deliver its accepted demand 

response. 

72 APPA at 53. 

73 SMUD at 4. 

74 SoCal Edison-SDG&E at 2-3. 

75 DC Energy at 4. 
Docket Nos. RM07-19-000 and AD07-7-000 - 43 - 

maintains that such elimination would create two classes of market participants and have 

a deleterious affect on the market by inefficiently and unfairly reallocating costs to 

others. 

70. Two commenters raise concerns about the applicability of the proposal to virtual 

bidding.76 APPA and the Connecticut and Massachusetts Municipals worry that virtual 

bidders may engage in market manipulation. Connecticut and Massachusetts Municipals 

argue that virtual bidders’ virtual load in the day-ahead market may create the appearance 

of a shortage even without corresponding real-time load. Therefore, the Commission 

should tailor any deviation exemption to apply to physical loads only.77 APPA agrees.78

71. Suppliers predominantly support the Commission’s additional ANOPR proposal to 

eliminate deviation charges absent system emergencies. These commenters argue that 

any load reduction, during either a system emergency or non-emergency, would benefit 

all loads in RTOs and ISOs through greater market efficiency. Other commenters, 

including the RTOs and ISOs, however, oppose this proposal. Arguments against 

eliminating deviation charges for non-emergency periods include concerns about 

 76 Virtual bidding, sometimes called “convergence bidding,” involves sales or 

purchases in the RTO or ISO day-ahead market that do 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 power in the real-time spot market. By making 

virtual energy sales or purchases in the day-ahead market and settling these positions in 

the real-time market, any market participant can arbitrage price differences between the 

two markets. 

77 Connecticut and Massachusetts Municipals at 40. 

78 APPA at 53. 
Docket Nos. RM07-19-000 and AD07-7-000 - 44 - 

potential gaming and inaccurate scheduling. APPA states that in order to ensure accurate 

schedules and cost accountability, deviation charges should remain in place absent a 

system emergency.79 EEI argues that the elimination of this charge during nonemergencies “sends the wrong price signal to market participants, provides a disincentive 

to minimize deviations, and leads to increased costs to the market.”80 PJM states that 

little reliability value is associated with load reductions during non-emergencies, and 

therefore waiving the deviation charges is not justified, particularly when costs would 

have to be collected through a socialized uplift charge.81

iii. Commission Proposal

72. The Commission proposes to require that all RTO and ISO tariffs be modified to 

eliminate a charge, which we refer to as a deviation charge,82 to a buyer83 in the energy 

market for taking less electric energy 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. 

 79 Id. at 54. 

80 EEI at 17-19. 

81 PJM at 7-8. 

82 Deviation charges recover certain costs including importantly 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 the extra generators 

committed after the close of the day-ahead market that are not recovered from sales of 

energy at real-time LMPs. 

83 Examples of buyers in RTO and ISO energy markets include a load serving 

entity that purchases electricity to meet the load requirements of its retail customers or a 

retail customer that purchases electricity directly from the wholesale market. 
Docket Nos. RM07-19-000 and AD07-7-000 - 45 - 

73. 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 to eliminate the deviation charge during a system emergency. 

This filing would be submitted within six months of the date the final rule is published in 

the Federal Register. The Commission will assess whether each filing satisfies the 

proposed requirement and will issue additional orders as necessary. 

74. Commenters supporting this proposal make sound arguments for it. We agree that 

removal of this deviation charge during a system emergency would remove a disincentive 

for greater demand response in the real-time market. A buyer may be deterred from 

reducing load during periods when supplies are tight and the real-time price is high if that 

buyer is subject to a charge for reducing its real-time consumption from its day-ahead 

purchases. If that buyer takes the appropriate action to reduce load and is accordingly 

penalized by a deviation charge, this unintended disincentive may lead the buyer to 

maintain a high load or discourage an LSE from calling on the demand response 

capabilities of its retail customers. Removal of this disincentive is important during a 

system emergency when load reduction is needed (and valued) most. 

75. RTO and ISO tariffs already contain provisions associated with the dispatch of 

generators during real time, and specify payments and deviation charges for uninstructed 

deviations. During system emergencies, all available generation resources are instructed 

to increase output if possible. Because these units are instructed to increase output, RTO 

and ISO tariffs do not impose deviation charges on generators that generate more power 
Docket Nos. RM07-19-000 and AD07-7-000 - 46 - 

during system emergencies than scheduled. Elimination of deviation charges for demand 

response by buyers ensures comparability between demand and supply resources. 

76. As noted above, although a majority of commenters express support for this 

proposal, a significant number appear to misunderstand it. For example, some 

commenters appear to believe that the Commission proposed to remove any penalty for a 

day-ahead bidder of demand response who fails to reduce demand in real time, and 

oppose this idea as discriminating in favor of a demand response provider. Accordingly, 

we provide two clarifications. First, this proposal applies to demand response that is in 

addition to the demand response of participants in RTO/ISO wholesale demand response 

programs. If demand response program participants reduce demand as directed, RTOs 

and ISOs already do not levy a deviation charge. We are not proposing to remove any 

penalty for a day-ahead bidder of demand response who fails to follow directions to 

reduce demand in real time. This proposal focuses on demand response from LSEs and 

other buyers that consume less total energy in real time during system emergencies than 

they had scheduled in the day-ahead market.84 Second, deviation charges would be 

eliminated only when the RTO or ISO announces an emergency situation after the close 

of the day-ahead market. The RTO or ISO could inform buyers either by instituting 

formal procedures that direct LSEs and electric utilities to activate retail demand response 

programs during a system emergency or by requesting voluntary load reductions, which 

 84 Note that under our proposal, if a demand response program participant reduces 

demand at greater levels than instructed during a system emergency, it will not be 

subjected to a deviation charge for the higher than instructed demand response. 
Docket Nos. RM07-19-000 and AD07-7-000 - 47 - 

may occur prior to or at the same time that a system emergency is declared. This is 

intended to ensure that buyers are not penalized when they voluntarily reduce load to 

improve system reliability at the request of a system operator. 

77. In response to concerns that eliminating the deviation charge during a system 

emergency would result in an unfair allocation of the uplift costs or the creation of an 

unfair subsidy to demand response, we recognize that a deviation charge covers real costs 

to generators and others. These costs include those associated with the extra generation 

committed after the close of the day-ahead market that are not recovered from sales of 

energy in real time. Since demand response during system emergencies can be 

instrumental in maintaining system reliability and reducing overall energy prices, the 

Commission proposes that these costs be allocated to all loads of the RTO or ISO. 

78. The Commission’s proposal to eliminate deviation charges during a system 

emergency applies to physical load reductions. With regard to virtual purchases, we 

believe that, during an emergency, these day-ahead purchases may not cause unneeded 

generation to be committed to the market because an emergency by its nature is a time 

when the system is short of generation. As a result, we believe that virtual purchasers 

may not cause significant additional costs during an emergency. Indeed, virtual 

purchases may enhance reliability by increasing the amount of generation resources 

available in real time during a system emergency. Assessing a deviation charge on 

virtual purchasers during an emergency may be unfair and may discourage helpful virtual 

bidding. Some commenters contend that virtual purchases add to system costs but do not 

address whether they add to costs during an emergency situation when the system is short 
Docket Nos. RM07-19-000 and AD07-7-000 - 48 - 

of generation. The Commission seeks comment on whether to require RTO and ISO 

tariffs to be modified to eliminate deviation charges for virtual purchasers during system 

emergencies. 

79. We do not propose to modify RTO and ISO tariffs to eliminate deviation charges 

absent a system emergency, in light of the comments we received regarding this ANOPR 

proposal. We are concerned about the resulting possibility of market manipulation and 

inefficiencies if deviation charges are removed, as raised by several commenters. Given 

the reliability value associated with demand response during system emergencies, 

socialization of related uplift costs is supportable. 

c. Aggregation of Retail Customers

i. Preliminary Proposals in the ANOPR

80. In the ANOPR the Commission sought comment on requiring 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. Under the 

preliminary proposal, the amended market rules could not exclude a demand response bid 

from a third-party ARC that is not an LSE, unless state laws or regulations do not permit 

this. RTOs and ISOs would have the same rules for ARC participation as for LSEs, 

except as needed to comply with state laws and regulations, unless the RTO or ISO 

satisfactorily explained the reason for any such difference. As part of the preliminary 

proposal, the Commission suggested directing RTOs and ISOs to coordinate to identify 

common issues, best practices, and market rules that are consistent between regions, 

particularly in the areas of market procedures, bidding protocols, communication 
Docket Nos. RM07-19-000 and AD07-7-000 - 49 - 

protocols, and measurement and verification, and having them report to the Commission 

on their coordination efforts. 

81. The Commission also requested comments on whether ARCs allow for 

inappropriate compensation when a retail customer is paid for wholesale demand 

response and also saves in its retail bill from the same demand response. The 

Commission noted that some argue that the payments to customers for demand response 

are a form of double payment that provides an unjustified subsidy. 

ii. Comments on the ANOPR Proposals and Questions

82. A large number of commenters address at great length the proposal to require an 

RTO to accept a demand response bid into its energy market from an ARC, if permitted 

by state law. A majority – including such diverse entities as EPSA, CAISO, and 

Industrial Consumers – appears to support the basic proposal although many raise 

implementation concerns. Comments in opposition to the proposal also vary widely and 

represent a diversity of interests, from SoCal Edison-SDG&E to the Massachusetts 

Attorney General. They offer a variety of reasons not to require market rule changes, 

with most concluding that this topic is a subject better suited for detailed stakeholder 

negotiations than a generic rulemaking. State regulators generally like the state law 

exemption, but several worry that the program could have unintended consequences and 

is inappropriate for non-retail access states. Public power, cooperatives, and other retail 

service providers not regulated by state commissions ask for clarification that an RTO or 
Docket Nos. RM07-19-000 and AD07-7-000 - 50 - 

ISO may not accept a bid from an ARC that aggregates their customers if their own retail 

regulations would not permit this.85 

83. Commenters identified multiple benefits associated with ARCs. ARCs provide 

valuable services to retail customers by handling various tasks such as developing 

demand response action plans, handling event notifications from system operators, and 

managing payment.86 ARCs can reduce the RTOs’ and ISOs’ administrative burden of 

managing individual customers’ demand response participation.87 ARCs with risk and 

portfolio management expertise can manage a portfolio of diverse demand response 

resources to achieve greater value and reliability with the aggregated demand response 

resource.88

84. RTOs and ISOs indicate that standardization of several technical issues may be 

beneficial. For example, PJM notes that a few areas that can be standardized, including 

(1) the method for determining baseline consumption, (2) the tools for establishing the 

uniform baseline and measuring the demand response, (3) the interface tools that allow 

demand response providers to use a common portal and protocol for offering demand 

response into the organized markets, and (4) the telemetry and metering requirements.89 

 85 APPA at 56; NRECA at 13; EEI at 19; AEP at 4-5; California Municipals at 8-

9. 

86 See Public Interest Organizations at 10. 

87 See EnerNOC at 6. 

88 See, e.g., Energy Curtailment at 10-15; EnerNOC at 6; Public Interest 

Organizations at 9-10. 

89 PJM at 9-10. 
Docket Nos. RM07-19-000 and AD07-7-000 - 51 - 

Several commenters, however, express concern that any rules for aggregation must be 

tailored to the specific design of the particular market and regional circumstances. They 

argue that these rules should not be developed in a generic Commission rulemaking 

process. Instead, the Commission should allow these rules to be developed by the RTO 

or ISO through a regional stakeholder process.90 

85. In response to ANOPR questions about how much to compensate a demand 

response aggregator for reducing its consumption of electric energy, voluminous 

comments were received ranging from strong arguments for paying the full market price 

to strong arguments for avoiding “double compensation.” Many commenters oppose 

having a Commission regulation setting a price to compensate for allegedly incorrect 

retail prices. Several point out that if retail customers faced real-time market prices, a 

retail aggregation program or any issue of compensation would not be needed. The 

commenters that want to see a transition to retail customers paying “efficient” market 

prices do not want permanent Commission regulations that compensate for “inefficient” 

retail prices. 

iii. Commission Proposal

86. The Commission proposes 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. 

 90 E.g., NY TO at 8; LPPC at 5-6; Kansas CC at 2-4; SoCal Edison-SDG&E at 3; 

Old Dominion at 9; Massachusetts AG at 2-3; Northeast Utilities at 8. 
Docket Nos. RM07-19-000 and AD07-7-000 - 52 - 

87. This proposal would reduce a barrier to demand response by permitting an ARC to 

act as an intermediary for many small retail loads that cannot individually participate in 

the organized market. We agree with commenters that aggregating small retail customers 

into larger pools of resources allows more customers to access demand response 

programs, which increases the potential market and reliability benefits realized from 

demand response in wholesale markets.91 Experience with existing aggregation programs 

in PJM, NYISO, and ISO-NE has shown that these programs increased demand 

responsiveness in these regions. 

88. In response to comments on the ANOPR’s preliminary proposal, we offer these 

clarifications of our proposal here. 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 

bidder only has the opportunity to be among the bids that clear the market; it does not 

guarantee that the bid will clear the market and be selected. In response to comments 

from public power entities, cooperatives, and other such entities with retail customers that 

are sometimes not subject to state public utility regulation, we clarify that, for the 

purposes of the ARC part of this rule, the term “relevant electric retail regulatory 

authority ” means the entity that establishes the retail electric prices and any retail 

competition policies for those customers, such as the city council for a municipal utility 

or the governing board of a cooperative utility.92 An ARC can bid demand response 

 91 See, e.g., PJM at 8; EnerNOC at 5-7; Alcoa at 22; Public Interest Organizations 

at 6-10. 

92 We do not intend to require an RTO or ISO to accept a demand response bid 
Docket Nos. RM07-19-000 and AD07-7-000 - 53 - 

either on behalf of only one retail customer or multiple retail customers. 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, and an individual customer may serve as an ARC on behalf of itself and others. 

Finally, RTOs or ISOs may specify certain requirements, such as registration with the 

RTO or ISO and creditworthiness and other requirements, which qualify a resource 

provider to make a bid and requests comments on whether there is any reason not to 

subject ARC to the same requirements as any other bidder in the energy market. 

89. As mentioned, we received voluminous comments on the issue of compensation to 

a demand response aggregator, with comments on this issue differing widely. A standard 

compensation approach may not be feasible given the differences in market designs 

across the regions, and we are persuaded that a rule that fixes a single pricing method in 

regulations may not be appropriate. However, the appropriate valuation of demand 

response in organized markets is addressed further below in our proposal for pricing 

during a period of operating reserve shortage. 

90. We agree with commenters who argue that each region’s market design is 

different and that it is important for the ARC provisions to consider these regional 

differences. For this reason, we do not propose to require detailed generic market rule 

 

from an ARC that has aggregated the demand responses of retail customers if this is not 

permitted by laws or regulations of those regulatory entities covered by the term “state 

regulatory authority” for those retail customers or if the retail customers are served at 

retail by a “nonregulated electric utility,” as these two terms are defined in sections 3(9) 

and 3(17) of the Public Utility Regulatory Policies Act of 1978, 16 U.S.C. §§ 2602(9), 

(17) (2000). 
Docket Nos. RM07-19-000 and AD07-7-000 - 54 - 

amendments for ARCs. We propose instead 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 in accordance with the following criteria: 

• 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, 

 Its aggregate demand response must be as verifiable as eligible LSE or 

large industrial customer demand response that are bid directly into the 

market. 

 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. 

 Demand response bids from an ARC must not be treated differently from 

the demand response bids of an LSE or a large industrial customer. 

• The RTO or ISO may require the ARC to be an RTO member if membership is a 

requirement for other bidders. 

• Single aggregated bids consisting of individual demand response from a single 

area, reasonably defined, may be required by RTOs and ISOs. 

• An RTO or ISO may place appropriate restrictions on demand response 

participation by any customer to avoid counting the same demand response 

resource more than once. 
Docket Nos. RM07-19-000 and AD07-7-000 - 55 - 

• The market rules do not have to allow bids from an ARC where 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. 

91. We request comment about whether these criteria are appropriate and whether 

there are additional appropriate criteria for allowing an ARC to bid demand response. 

92. 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 to permit an ARC to bid a demand response on behalf of retail 

customers.93 This filing would be submitted within six months of the date the final rule is 

published in the Federal Register. The Commission will assess whether each filing 

satisfies the proposed requirement and will issue additional orders as necessary. 

93. We note, however, that cooperation and coordination among the RTOs and ISOs 

in developing standard terms for demand response programs would be beneficial. 

Accordingly, we encourage RTOs and ISOs to coordinate their efforts through the 

ISO/RTO Council to identify common issues, best practices, and market rules that are 

consistent between regions (particularly in the areas of market procedures, bidding 

protocols, communication protocols, and measurement and verification) or act to develop 

 93 In particular, this proposal would not necessarily require any change to an 

existing aggregation program that already functions well if the existing program satisfies 

the proposed criteria. See NEPOOL Participants at 12; TAPS at 19-21; Silicon Valley 

Power at 7-8. 
Docket Nos. RM07-19-000 and AD07-7-000 - 56 - 

common business practices and measurement and verification protocols through the 

North American Energy Standards Board (NAESB). 

d. Potential Future Demand Response Reforms

94. The need for, and the focus on, demand response will continue to increase. 

Although the Commission is proposing specific reforms to eliminate barriers to demand 

response here, we believe that other reforms may be necessary in the future. However, 

we do not wish to delay the adoption of these specific reforms while the Commission and 

industry continue to study and consider other advances in this area. Rather, we believe 

that the reforms proposed here should proceed while the Commission and stakeholders 

study what additional efforts are needed and develop a record to support further reforms. 

95. In order to achieve this goal, we intend to direct staff to hold a technical 

conference shortly after receiving the comments on this NOPR to consider the following 

issues for demand response participation in the wholesale markets: (1) if 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. The proposed 

technical conference will provide a forum for RTOs/ISOs, demand response providers, 

and other stakeholders to express their views regarding these issues. It will also serve as 

guidance to the RTOs/ISOs of the areas that they should include as part of the study we 

propose to order as well as other issues identified in the course of the study. We propose 
Docket Nos. RM07-19-000 and AD07-7-000 - 57 - 

to require each RTO or 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, and to submit its findings and any proposed solutions along with a 

timeline for implementation to address barriers to the Commission within six months of 

the Final Rule (RTO and ISO studies). To ensure that minority views are adequately 

represented, we propose to require that the RTO or ISO identify any significant minority 

views in its filing. We also will require the Independent Market Monitor for each RTO 

or ISO to provide its views on this issue to the Commission. 

96. These RTO and ISO studies will have significant value. They have the potential 

to provide independent critical analysis and a basis for additional reform. In this regard, 

we note that section 529 of the Energy Independence and Security Act of 2007 (EISA) 

requires the Commission to complete a national assessment of demand response both to 

estimate the potential for demand response and to determine how to overcome the 

barriers to achieving that potential.94 We believe that the RTO and ISO studies we are 

proposing to require will help us in preparing the assessment and ultimately in 

developing a national action plan on demand response as required by EISA. These 

studies will also provide a sound platform and record for the Commission to consider 

whether there should be additional reforms to remove barriers to demand response in 

organized markets that ensure comparable and fair treatment of demand response 

 94 The Energy Independence and Security Act of 2007, Pub L. No. 110-140, 121 

Stat. 1492 (2007). 
Docket Nos. RM07-19-000 and AD07-7-000 - 58 - 

resources as required by the EISA.95 We seek 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. 

e. Market Rules Governing Price Formation During Periods 

of Operating Reserve Shortage

i. Preliminary Proposals in the ANOPR

97. In the ANOPR, the Commission sought comment on modifying market rules that 

limit the market-clearing price during an emergency, that is, when the amount of 

available supply falls short of demand plus the operating reserve requirement.96 When 

this happens, reliability is threatened and market rules that limit the market price may 

have the unintended effect of discouraging demand response. Limiting the price also 

discourages existing generators needed mostly for emergencies from continuing 

operation and discourages entry of new generation. The ANOPR presented for comment 

four possible approaches to addressing this problem. 

98. First, the Commission proposed requiring RTOs and ISOs to increase the energy 

supply offer caps and demand bid caps above the current levels during an emergency. 

This could also result in a market-clearing price higher than the existing caps. Second, 

the Commission proposed requiring RTOs and ISOs to allow only demand bid caps to be 

 95 42 U.S.C. § 8241 et seq. (2000), amended by EISA, Pub L. No. 110-140, § 529, 

121 Stat. 1492 (2007). 

96 We note that in this section of the NOPR, we refer to this emergency period as a 

period of operating reserve shortage. 
Docket Nos. RM07-19-000 and AD07-7-000 - 59 - 

raised above the current level, while keeping generation offer caps in place. Such high 

demand bids would be allowed to set the market price if they clear the market. As a third 

possible approach, the Commission proposed requiring a demand curve for operating 

reserves in each RTO or ISO market. Finally, as a fourth approach, the Commission 

proposed requiring RTOs and ISOs to modify their market rules to set the marketclearing price for all supply and demand response resources dispatched during an 

emergency at the payment made to participants in an emergency demand response 

program.97

ii. Comments on the ANOPR Proposals and Questions

99. Many commenters advocate an RTO-by-RTO approach instead of a rulemaking 

for addressing this issue.98 They call for the Commission to identify the general features 

of a solution, allowing each RTO and ISO and its regional stakeholders to develop the 

details. Others request that the Commission act only in coordination with state regulators 

because the ability of ultimate consumers to reduce demand in an emergency depends on 

retail metering, pricing, and other programs. 

 97 Based on comments on the ANOPR’s preliminary proposals, we note that there 

may be some confusion regarding the second and fourth approaches. We clarify that a 

demand bid is different from a demand response bid. The first is an offer by a potential 

purchaser to buy a certain amount of energy at a given market price, and the second is an 

offer by a purchaser to reduce its normal purchase by a given amount in return for 

compensation. 

98 E.g., Ameren at 31; CAISO at 19-20; EEI at 11; National Grid at 10; NEPOOL 

Participants at 15-17; NYISO at 34-35; PJM MMU at 6-7; PG&E at 9. 
Docket Nos. RM07-19-000 and AD07-7-000 - 60 - 

100. Many other commenters spoke for or against all four approaches collectively. 

Those opposed to allowing buyers to see a higher price during an emergency argue that 

the proposals are based on an incorrect assumption that higher prices would reduce 

demand. They contend that most of the buyers in an RTO’s or ISO’s market are LSEs 

with an obligation to buy regardless of the price; thus, the ultimate consumers (at retail) 

will not see the higher price or reduce demand.99 Some opposing commenters argue that 

the proposals in varying degrees would create new opportunities for generators to 

exercise market power.100 Further, they oppose some of the proposals because they 

would result in an administratively determined price instead of a true market price.101 

101. Those in support of allowing buyers to see a higher price during an emergency 

argue that prices should be determined by an unencumbered market where buyers and 

sellers are allowed to make bids and offers with no restriction.102 

102. In general, among those who favored one or more of the ANOPR’s four 

approaches, the first (raise all caps during an emergency) and third (have a demand curve 

for operating reserves) approaches received the strongest support. The second (raise only 

demand bid caps during an emergency) and fourth (allow the payments for emergency 

 99 See, e.g., APPA at 59; Industrial Coalitions at 10-12; LPPC at 7-8; OPSI at 38; 

PJM MMU at 7; Public Interest Organizations at 11; TAPS at 21. 

100 See, e.g., Ameren at 29; Connecticut and Massachusetts Municipals at 41-42; 

EEI at 25; Industrial Consumers at 22; PJM Power Providers at 2-6; PPL Parties at 5-9. 

101 See, e.g., EEI at 29; Reliant at 5; PJM Power Providers at 31. 

102 See, e.g., AEP at 5; The Alliance at 9; Constellation at 5-6; EPSA at 33; Reliant 

at 5-7; Strategic Energy at 9. 
Docket Nos. RM07-19-000 and AD07-7-000 - 61 - 

demand response to set the market-clearing price during an emergency) approaches had 

the weakest support. 

103. In comments on the first approach—lifting energy bid caps and price caps above 

the current levels only during an emergency—supporters say that this course of action 

allows buyers and sellers to set a true market price for electricity during an emergency, 

reduces demand by the appropriate amount, and allows investors in new generation to 

assess the value to buyers of new generating resources. This approach also has strong 

opposition, with particular concerns about the potential for generators to exercise market 

power and the inability of customers to respond to high prices. 

104. The few commenters supporting the second approach—raising bid caps above the 

current level only for demand bids—say that it decreases generators’ ability to 

manipulate the market compared to the first option. They also make the general point 

that it is important to let buyers express their true value for power. Those objecting to 

this proposal raised many of the same concerns that were raised regarding the first 

approach. For instance, they allege that even raising bid caps only for demand bids 

would allow generators to physically withhold some portion of their output from the 

market to obtain higher prices for the remaining output. Commenters also argued that the 

proposal was based on the false assumption that buyers that do not enter a bid to purchase 

at a high price will not be served. These commenters maintain that utilities shed load 

only as a last resort during an emergency, and emergency curtailment programs dictate 

the allocation of power during a shortage in a way that has nothing to do with the price 

bid into the energy market. 
Docket Nos. RM07-19-000 and AD07-7-000 - 62 - 

105. Support for the third approach of establishing a demand curve for operating 

reserves rests heavily on its track record, namely that the Commission has approved these 

programs before and many regions have experience with them.103 Arguments against this 

specific proposal are largely objections to administratively determined demand curves 

where prices may be set at levels that do not reflect competitive market conditions. 

106. In commenting on the fourth approach—setting the market-clearing price at the 

payment made to participants in an emergency demand response program—a few 

commenters state that this approach is preferable to allowing no higher price during an 

emergency at all and could be supported as a transitional step in the process of removing 

all bid and offer caps. Opposition to this approach is based on the market price being 

administratively determined and a variety of other reasons, for example, that it is 

inappropriate to set an energy price based on a reliability payment. 

iii. Commission Proposal

107. We have carefully considered the comments on this issue and continue to believe 

that existing market rules appear to be unjust, unreasonable and unduly discriminatory or 

preferential during times of scarcity. In particular, they may not accurately reflect the 

true value of energy and, by failing to do so, may harm reliability, inhibit demand 

response, deter new entry of demand response and generation resources and thwart 

innovation. However, we are cognizant of the fact that this is a difficult issue and that 

 103 Duke Energy at 11; EPSA at 35; PJM MMU at 6-7; National Grid at 10-11; 

NEPOOL Participants at 16; New England Power Generators at 6-7; NYISO at 35; NY 

TO at 10. 
Docket Nos. RM07-19-000 and AD07-7-000 - 63 - 

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. We first explain the 

potential need for reform and then we describe our proposal to address this issue. 

108. In a competitive market, demand and supply respond to price. If the price of 

energy is artificially capped during times of scarcity, this will constitute a barrier to 

effectively attracting new generation and demand resources into organized markets. 

When the system faces a shortage of operating reserves, additional resources are needed 

for operating reserves that help to maintain grid reliability. At such times, market prices 

can elicit demand response from certain customers who are equipped to respond and, 

thus, help balance the system. When bid and offer caps are in place, however, it is not 

always possible to elicit the optimal level of demand or generator response. 

109. Some commenters argue that certain barriers to demand response remain and that 

the Commission should not undertake any reform until such barriers are removed. The 

Commission is taking several important, concrete steps in this rulemaking to eliminate 

remaining barriers to demand response that are indicated by the existing record to ensure 

comparable and fair treatment of demand response resources. We recognize, however, 

that some barriers may remain. That is why we are requiring each RTO or ISO, as 

explained above, to undertake a further study of this issue and report back to the 

Commission. However, even if some barriers remain (certain of which may be subject to 

state jurisdiction, not our jurisdiction), price remains an important factor in encouraging 

demand response. Without prices that reflect the true value of energy, we cannot expect 

the full integration of demand response into organized markets. We therefore do not 
Docket Nos. RM07-19-000 and AD07-7-000 - 64 - 

believe that reforms in this area should be delayed until every barrier to demand 

response, whether retail or wholesale, technological or regulatory, is identified and 

addressed. We have, however, included as a primary criterion for approving price reform 

during periods of operating reserve shortage an adequate record demonstrating that 

provisions exist for mitigating market power and deterring gaming behavior. These 

could include, but are not limited to, use of demand resources to discipline bidding 

behavior to competitive levels during periods of operating reserve shortages. 

110. We recognize that not all customers are at present equipped to respond to scarcity 

pricing. Nevertheless, putting rules in place that allow the fraction of the load currently 

able to respond can have a very positive effect on the market and help reduce prices for 

all. 104 Further, with the modifications that this proposal anticipates, more buyers would 

find it worthwhile to invest in technologies that allow them to respond to prices. This 

group could include not only large manufacturers and others buying directly from the 

RTO or ISO market, but also ARCs, and LSEs which can implement retail demand 

response programs designed to reduce load during reserve shortages. 

111. The Commission's proposed reforms are also intended to increase reliability. Our 

proposal is limited to periods of true scarcity (i.e., when there is a shortage of operating 

reserves). We have a duty to implement rules that ensure adequate supplies. If the price 

of energy during these periods is artificially constrained, demand cannot respond 

 104 See 2006 FERC Staff Demand Response Assessment at 7. As reported in the 

2006 FERC Staff Demand Response Assessment, as little as five percent of load 

responding to price may discipline market prices. 
Docket Nos. RM07-19-000 and AD07-7-000 - 65 - 

efficiently and therefore the likelihood of involuntary curtailments is increased. Thus, 

demand resources may be a low cost resource that can be used to meet operating reserves 

requirements at the lowest total cost of maintaining reliability. Furthermore, by 

artificially capping prices, the price signals necessary to attract new entry by both 

generation and demand resources are muted and long-term resource adequacy is harmed. 

112. This is not merely a theoretical problem. In regions such as PJM and New 

England, the Commission has found in prior orders that existing energy and capacity 

markets did not encourage sufficient new entry and that these regions therefore faced 

serious reliability problems.105 The Commission adopted forward capacity markets in 

those regions to avoid the threats to reliability and the real costs to our economy of 

inadequate generation and demand resources. The reforms we propose here can help to 

avoid these problems in other regions. Moreover, as we explain below, in regions that 

already have such capacity markets, the reforms proposed here can reduce the level of 

revenues that must be recovered in such capacity markets. 

113. Some commenters appear to misunderstand our proposal and suggest that we are 

proposing to lift the caps on generation in every organized market. This is not correct. 

Only one of our proposals would lift price caps on generators bidding energy into 

organized markets. The other three would not do so, but rather would seek to better 

reflect the value of energy during times of scarcity through other means. 

 105 Devon Power, LLC, 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); PJM Interconnection, LLC, 117 FERC ¶ 61,331 (2006). 
Docket Nos. RM07-19-000 and AD07-7-000 - 66 - 

114. In regions that have already adopted forward capacity markets, the lifting of such 

price caps on energy would primarily shift revenues from capacity markets to energy 

markets. In New England and PJM, the revenues collected by generators in the energy 

market are deducted from the revenues that need to be recovered in the capacity markets. 

Moreover, by shifting the price signals from capacity markets to energy markets, the 

Commission is encouraging greater demand response, as demand response may face 

fewer barriers to participating in energy markets than forward capacity markets. 

115. Finally, and most importantly, we are not proposing to change the rules in each 

region without regard to the specific circumstances facing that region. As we explain 

below, each region will be permitted to demonstrate that its current rules do not need to 

be reformed because they already adequately reflect the value of energy during periods of 

scarcity. 

116. Other commenters raise market power concerns. We agree that we have a duty to 

guard the consumer against exploitation by sellers with market power and we will fulfill 

that duty. As we explain below, we are proposing that market power issues be 

adequately addressed before any reforms in this area are adopted. 

117. We now explain our proposal for reform in this area. We propose to require each 

organized market to make a compliance filing, within six months of a final rule in this 

proceeding, proposing any necessary reforms to ensure that the market price for energy 

accurately reflects the value of such energy during periods of scarcity (i.e., an operating 

reserve shortage). Because there are regional differences in market design, we will not 

mandate any one type of reform in this area. Rather, each region may propose one of the 
Docket Nos. RM07-19-000 and AD07-7-000 - 67 - 

four approaches described in the ANOPR (and summarized further below) or it may 

propose a different approach. Alternatively, a region may demonstrate that its existing 

market rules already reflect the value of energy during periods of scarcity and therefore 

do not need to be reformed. 

118. In recognition of the concerns of many commenters, we also propose to adopt 

further requirements to ensure that any reforms in this area are supported by adequate 

factual support and show how they are designed to protect consumers against the exercise 

of market power. 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. Specifically, the RTO or ISO should 

provide historical evidence in its region regarding the interaction of supply and demand 

during periods of scarcity and the resulting effects on the market price for energy. To the 

extent this evidence indicates that the region’s market rules are inadequate during these 

periods, the RTO or ISO must then explain and support why its proposed reforms are 

tailored to address those inadequacies. 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. 

119. As a general matter, we will consider the factual record compiled by the RTO or 

ISO to determine whether its proposal, or its demonstration as to its existing market rules, 

would: 

• Improve reliability by reducing demand and increasing generation during 

periods of operating reserve shortage; 
Docket Nos. RM07-19-000 and AD07-7-000 - 68 - 

• 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. 

120. We request 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. 

121. Second, the Commission will require any RTO proposing reform in this area to 

address the adequacy of any mitigation measures that would be in place during periods of 

operating reserve shortage. We recognize that many commenters have raised market 

power concerns and we take those concerns seriously. However, we note that enhanced 

demand responsiveness and increased entry by generators can help to mitigate seller 

market power by lowering market prices.106 Moreover, we note that generator bid and 

 106 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 - 69 - 

offer caps are not increased in three of the four options proposed.107 These caps provide 

further protection against the exercise of seller market power. Further, the Commission 

notes that other market power mitigation measures remain in place during times when 

operating reserves are insufficient. For example, conduct and impact tests are applied in 

ISO-NE, NYISO, and Midwest ISO. A pivotal supplier test is used in PJM. PJM and 

CAISO mitigate bids by generators chosen out of merit order. Moreover, the 

Commission intends 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. 

122. In addition, to ensure that we have an adequate record on the issue of market 

power mitigation, we propose to solicit the views of the Independent Market Monitor for 

each RTO or ISO region on any proposed reforms in this area. 

123. We now briefly summarize the four approaches discussed in the ANOPR and 

referred to above. As noted, however, these are not the only approaches that may be 

considered. Under the first approach, RTOs and ISOs would increase the energy supply 

offer caps and demand bid caps above the current levels only during an emergency. For 

example, if operating reserves drop below levels required in mandatory reliability 

 107 In the first approach, bid and offer caps would increase for both sellers and 

buyers. In the second approach, bid and offer caps for buyers would be increased, but bid 

and offer caps for sellers would remain in place. In the third approach, based on a 

demand curve for operating reserves, bid and offer caps would remain in place for both 

sellers and buyers. In the fourth approach (which proposes that payments to participants 

in an emergency demand response program could set the market-clearing price), bid and 

offer caps would again remain in place for both sellers and buyers. 
Docket Nos. RM07-19-000 and AD07-7-000 - 70 - 

standards, then bid caps would be allowed to rise above existing caps. As we described 

above, increasing energy supply offer and demand bid caps would allow the market to 

clear at a price above the current (or non-emergency) cap.108 Customers and LSEs could 

then decide whether to purchase energy at the higher price, and those who place a higher 

value on energy could continue to buy it while those who do not value it as highly could 

reduce their demand. Thus, this proposal would allow supply and demand to operate 

more efficiently to allocate limited supply to those who value it the most. 

124. Under the second approach, RTOs and ISOs would increase bid caps above the 

current level only for demand bids (i.e., the buyers’ offers to purchase a certain amount of 

energy at a given price) while keeping generation bid caps in place. That is, a buyer 

would be allowed to inform the RTO or ISO about how much energy it would purchase at 

various prices above the current bid caps. These demand bids would be allowed to set 

the market price if they clear the market. As with the other approaches, the higher market 

price under this approach would create an incentive for all buyers to lower their demands 

during an emergency. Demand that is price-sensitive would be reduced until available 

supply can meet the demand plus the need for operating reserves. This proposal does not 

change any rules that govern how demand response resources operate in the market.109

 108 Under this proposal, the price and bid caps would be removed in the real-time 

market during an operating reserve shortage, but not necessarily in the day-ahead market. 

Thus, the price and bid caps would be removed normally for only a fraction of the spot 

market. In a severe shortage when the system operator is aware that the day-ahead 

market will produce insufficient generation for day-ahead energy and operating reserves, 

the price and bid caps would also be removed for the day-ahead market. 

109 We clarify that this approach refers to demand, not demand response. That is, 
Docket Nos. RM07-19-000 and AD07-7-000 - 71 - 

125. The third approach is for an RTO or ISO to establish a demand curve for operating 

reserves. The RTO or ISO would establish market rules that set real-time prices at 

specific pre-determined values (typically above the market-wide offer and bid caps) 

during an operating reserve shortage. The price level would increase with the severity of 

the shortage. This approach will ensure that market prices reflect tight conditions on the 

grid without altering any of the market power mitigation restrictions on either supply 

offers or demand bids. The Commission has already approved this option in the NYISO 

and ISO-NE markets.110 These existing programs for pricing during reserve shortages 

have been implemented and activated during periods of operating reserve shortage in 

these regions. Moreover, the exposure to higher prices would increase the incentive for 

load to engage in hedging activities, and higher prices during shortages should attract 

new generation. As long as the prices that are implemented during reserve shortages are 

based on costs relevant to the market (such as the cost of new peak generation entry), and 

the particular characteristics of RTO and ISO regions, demand curves for operating 

reserves should induce sufficient supply and demand responses. A properly designed 

 

this proposal allows a buyer to submit a bid to purchase energy at a price that exceeds the 

current bid cap. This proposal in no way affects demand response resources that 

participate in a program where they are paid some amount of money to reduce their 

consumption. 

110 The Commission approved market rules for NYISO and ISO-NE that include a 

demand curve for operating reserves that sets the real-time market price when operating 

reserves are low. New York Indep. Sys. Operator, Inc., 106 FERC ¶ 61,111 (2004); New 

England Power Pool and ISO New England Inc., 115 FERC ¶ 61,175 (2006). See David 

B. Patton & Pallas LeeVanSchaik, 2006 Assessment of the Electricity Markets in New 

England (June 2007); David B. Patton & Pallas LeeVanSchaik, 2006 State of the Market 

Report New York ISO (July 2007). 
Docket Nos. RM07-19-000 and AD07-7-000 - 72 - 

demand curve for operating reserves should also alleviate concerns about 

administratively determined prices. As noted above, the demand curve is a reflection of 

the costs of entering the energy market and indicates the prices suppliers would expect to 

be paid to provide that energy to the market. Thus, while the demand curve is 

administratively determined, it is based on market conditions. 

126. Under the fourth approach, an RTO or ISO would amend its market rules to set the 

market-clearing price for all supply and demand response resources dispatched equal to 

the payment made to participants in an emergency demand response program.111 Since 

the emergency demand response programs are only called during an emergency when 

demand needs to be reduced quickly, they should be the marginal resource and set the 

market-clearing price. Without such a rule, demand response payments are made to those 

demand response resources that respond to the RTO’s or ISO’s call to reduce load, yet 

prices are still set by the generation resource with the highest running costs (or at the 

price cap). This proposal would set the market-clearing price by the actual marginal 

reliability resource, the demand response resource. For example, if participants in 

emergency demand response programs were paid $500/MWh to reduce their 

consumption when directed, then the $500/MWh payment would set the market-clearing 

price in the zones where the program was active. 

127. This rulemaking approach to demand response is directed at all RTOs and ISOs to 

ensure that all meet certain basic demand response goals. However, we do not intend to 

 111 RTOs and ISOs would have to amend their market rules on unit commitment 

and settlement to adjust wholesale energy prices outside the normal clearing process. 
Docket Nos. RM07-19-000 and AD07-7-000 - 73 - 

alter current RTO and ISO shortage pricing programs if the compliance filings satisfy us 

that the current programs meet the intent of this requirement. Some RTOs and ISOs have 

already dedicated considerable resources to develop various shortage-pricing programs. 

These programs have been developed through established stakeholder processes in the 

RTOs and ISOs and have been approved by the Commission and determined to be just 

and reasonable. Thus, the requirement proposed here may be satisfied by a filing 

demonstrating that the RTO or ISO already has a Commission-approved approach for 

pricing during periods of operating reserve shortage that meets the requirements 

previously discussed ( i.e., in P 117, 118 and 120). 

128. Each RTO or ISO may also consider a “phase-in” of its specific emergency 

pricing method, over a period of years (e.g., three years). This phase-in period can 

gradually introduce customers to price increases during an emergency and allow them to 

develop ways to reduce demand during an emergency to avoid high prices. We note that 

the phase-in may be linked to key factors such as the deployment of the advanced 

metering needed to implement their proposed method, provided the phase-in period is not 

protracted. However, the full deployment of advanced metering is not a requirement for 

the implementation of emergency pricing as price and demand responsiveness can be 

achieved without such a prerequisite. 

B. Long-Term Power Contracting in Organized Markets

129. In the ANOPR, the Commission offered for comment three proposals intended to 

facilitate long-term contracting in organized markets, along with questions about whether 

to modify Electric Quarterly Reports (EQR) data requirements to facilitate long-term 
Docket Nos. RM07-19-000 and AD07-7-000 - 74 - 

contracting. Following review of the comments, the Commission proposes to require that 

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

to buy or sell electric energy on a long-term basis. The Commission will consider 

reasonable additional steps in response to comments on this NOPR, and continues to 

encourage ISOs and RTOs to work within their authorities with stakeholders to facilitate 

long-term power contracting. 

1. Background

130. Long-term power contracts are an important element in 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 also improve price stability, mitigate the 

risk of the abuse of market power, and provide a platform for investment in new 

generation and transmission. 

131. As the Commission noted in the ANOPR, an organized market region naturally 

should facilitate long-term contracting by eliminating pancaked rates for long distance 

power sales, eliminating loop flow problems within its footprint, and ensuring reliable 

transmission operation over a large area. 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. 

132. While most of the comments submitted in response to the ANOPR and testimony 
Docket Nos. RM07-19-000 and AD07-7-000 - 75 - 

from parties at the Commission’s technical conference on May 8, 2007 agree as to the 

importance of long-term contracts, opinions vary as to the extent of a problem with longterm contracts in the market and its causes. Many customers argue that issues of market 

design and over-reliance on the spot market have driven up prices, making long-term 

contracting difficult. On the other hand, many power sellers believe that markets are 

operating well, but parties are unable to reach long-term contracts due to differing price 

expectations and differing assessments of long-term risk. 

133. 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.112 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 improved the interconnection process and provide for 

interconnection with network integration service to facilitate long-term reliance on new 

generation.113 The Commission has also reformed capacity markets in several regions to 

 112 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). 

113 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 
Docket Nos. RM07-19-000 and AD07-7-000 - 76 - 

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.114 

2. The Need for Commission Action

134. As noted above, long-term power contracts are an important element of a working 

market. They enable buyers and sellers to manage risks, they promote stability in 

pricing, and they provide a solid foundation for the financing of new generation. Despite 

this importance, both buyers and sellers perceive that it is increasingly difficult to enter 

into long-term contracts, and that fewer long-term contracts are being signed as a result. 

135. The Commission believes that further transparency in long-term electric energy 

markets would facilitate efforts by both sellers and buyers to incorporate long-term 

contracts as an essential part of their energy portfolios. This is especially true for new 

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. During the panel on 

long-term contracting at the second Commission competition conference, a representative 

 

(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. 

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). 

114 Devon Power, LLC, 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); PJM Interconnection, L.L.C., 117 FERC ¶ 61,331 (2006). 
Docket Nos. RM07-19-000 and AD07-7-000 - 77 - 

from PJM stated that he had spoken to what he termed “smaller players” who indicated 

that they were willing to contract for power but were unaware of who the available 

counterparties were.115 These “smaller players” said that they would be interested in a 

bulletin board on the PJM web site that would facilitate networking.116

136. While the market has the most important role to play in disseminating information, 

an RTO or ISO can play an important role in promoting greater transparency and 

liquidity in long-term power markets, and thus help reduce possible over-reliance on its 

spot markets. The information systems it operates are well suited for making such 

information available to the parties in its region.117 As discussed below, several 

commenters support having RTOs and ISOs provide a section of their web sites for a 

long-term contract bulletin board, which they believe would be a useful tool in assisting 

parties in finding interested counterparties and facilitating long-term contracts. 

137. In light of these comments and our own observation, the Commission will take 

action in this area. We do so because of the importance of long-term contracts to a 

working market and because we believe greater transparency in the market will facilitate 

such long-term contracts. We therefore propose 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. 

 115 Transcript of Conference at 187, Conference on Competition in Wholesale 

Power Markets, Docket No. AD07-7-000 (May 8, 2007).

116 Id.

117 See id. at 117. 
Docket Nos. RM07-19-000 and AD07-7-000 - 78 - 

3. Preliminary Proposals in the ANOPR

138. Given the importance of long-term contracts, in the ANOPR the Commission 

requested comment on any concrete steps it could take to facilitate voluntary long-term 

power contracting in organized market regions.118 Specifically, the Commission solicited 

comment on whether it should encourage greater market transparency by requiring RTOs 

and ISOs to post information that could facilitate long-term contracts, such as aggregate 

information on long-term contract prices and quantities, and if so, how the information 

could be reported so that it protects the confidentiality of individual contracts. The 

Commission also asked whether disseminating other information, such as estimates of 

transmission constraints and long-term congestion costs, would be helpful to long-term 

contracting. 

139. The Commission also solicited comment on whether it should require or encourage 

efforts to develop new standardized forward products and whether standardized products 

would facilitate long-term contracting. The Commission inquired about what role it 

should play, whether the Commission should encourage RTOs or ISOs to play an active 

role in this area (or whether that would place them in a position of undertaking 

commercial functions), and whether this was a role better played by NAESB or other 

industry groups. 

 118 The Commission noted, however, that it was mindful of the limits of its 

jurisdiction in seeking comment on this issue, as the Commission cannot compel buyers 

and sellers to enter into long-term contracts. The Commission also noted that the 

purchasing practices of LSEs are often dictated by state policies, not those of this 

Commission. 
Docket Nos. RM07-19-000 and AD07-7-000 - 79 - 

140. Third, the Commission asked whether it should require ISOs and RTOs to dedicate 

a portion of their web sites for market participants to post offers to buy or sell power 

long-term. The Commission asked whether this proposal would prove helpful, or 

whether it was a service that would be better provided by the market. 

141. Finally, the Commission requested comments on whether it should consider any 

modification of the data requirements of the EQR—for example, to report the start date, 

term, and end date of long-term power contracts—to provide information that would 

make transparent the average prices of long-term power contracts of various terms and 

vintages. 

4. Comments on the ANOPR Proposals and Questions

142. Commenters filed extensive comments agreeing with the Commission on the 

importance of long-term contracts in a functioning market. They differ, however, on the 

nature and extent of the problems with long-term contracting, what measures would best 

address the problems, and whether the Commission should attempt to deal with the 

various problems by requiring RTO or ISO actions. 

143. Most commenters recommend against most of the actions proposed by the 

Commission in the ANOPR, which address the problems through regulations applicable 

to RTOs or ISOs. Some of these commenters argue that market participants and the 

private sector should address concerns over long-term contracting opportunities, while 

others argue that the Commission can improve long-term contracting opportunities by 

addressing larger structural issues, identified below. 
Docket Nos. RM07-19-000 and AD07-7-000 - 80 - 

144. The preliminary proposal to require RTOs and ISOs to reserve a section of their 

web sites for parties to post offers to buy or sell power under long-term contracts has the 

most support, although most commenters do not necessarily support making this a 

regulatory requirement. A minority of commenters support this proposal—some 

strongly, including several RTOs and ISOs, state regulators, wholesale sellers, many 

small wholesale buyers, and Joint Consumer Advocates. Commenters indicate that such 

a web site would be useful for many market participants, particularly new market 

participants, and would help facilitate long-term contracting. Midwest ISO and PJM 

indicate that they have already begun working on posting such discussion boards on their 

web sites, and other RTOs and ISOs such as SPP indicate support for providing space on 

their web sites to post such offers. 

145. Commenters opposed to this proposal indicate that the market already adequately 

performs this function, and that the RTOs and ISOs should be able to determine on their 

own whether to have a web site section for bulletin board postings. EEI and Duke 

Energy note that PJM once had a bulletin board for similar purposes that fell into disuse, 

likely due to a lack of interest from market participants. Many commenters, such as 

EPSA, argue that RTOs and ISOs should be allowed to determine, in consultation with 

stakeholders, what to post on their web sites. Some commenters state that legal issues 

may arise from having RTOs or ISOs post information, including concerns over 

confidentiality and potential liability for the posting of incorrect information, and that 

these issues should be addressed before any action is taken. The New England 
Docket Nos. RM07-19-000 and AD07-7-000 - 81 - 

Conference said that it supports a regional, voluntary solution, where regional working 

groups would be created to discuss measures to increase information sharing. 

146. Commenters offer little support for the ANOPR proposal to require RTOs and 

ISOs to develop new standardized forward products. Those few commenters supporting 

the proposal believe that new products would assist customers in developing long-term 

contracts. Some commenters, such as the New York PSC and NRG, offer qualified 

support for the concept of improved forward products, but state that the Commission 

should encourage RTO or ISO participation in developing such products rather than 

require their development by the RTOs and ISOs themselves. 

147. A large majority of commenters oppose this proposed requirement. They say that 

the market already supplies standardized products, and that it is better equipped to do so 

than RTOs or ISOs. EEI notes that it already has a process for developing standardized 

products that involves working with market participants to adjust to changes in the 

market. Many commenters also note that long-term contracts vary considerably from 

transaction to transaction, making standardized products difficult to develop unless they 

are quite general and so less useful than they are for short-term transactions. Finally, 

some commenters note that this proposed requirement would be an undue burden to ISOs 

and RTOs. 

148. Most commenters argue strongly against adopting the ANOPR’s preliminary 

proposal to require ISOs and RTOs to post information on long-term contract prices and 

quantities. They argue that this proposed requirement is unnecessary, is possibly 

counterproductive, and would create additional expense for the ISO or RTO. A few, such 
Docket Nos. RM07-19-000 and AD07-7-000 - 82 - 

as BlueStar and DC Energy, support the proposal, arguing that it would increase 

transparency in the market, which would lead to greater liquidity and increased long-term 

contracting. Some ISOs and RTOs also indicate that they would be willing to post 

information if directed to do so, but that confidentiality concerns would need to be 

addressed. Many commenters think that the requirement would not be useful because of 

the wide variation in long-term contract provisions and the time lag between contracting 

and posting of the information.119 Others, such as the OMS, argue that the data collection 

requirement would unduly burden RTOs and ISOs. The burden would be unnecessary, 

according to PG&E, PSEG, Allegheny, Ameren and others, because the market and trade 

press already provide sufficient data. Finally, many commenters point to a concern over 

the confidentiality of data and the possibility that posted data could be used to game the 

market. 

149. Only a few commenters address the Commission’s request for comments on 

whether we should consider modifications to the information collected on long-term 

contracts in the EQR. These commenters are generally opposed to having the 

Commission modify the EQR data reporting requirements. Although SUEZ Energy 

supports increased reporting requirements, arguing that it would create increased 

transparency for providers of retail service, most commenters believe that the information 

in the EQR is already sufficient and that any new information requirements could have 

negative effects on confidentiality or markets. For instance, Old Dominion notes that 

 119 See Pepco at 13; New England Power Generators at 8; Dynegy at 3. 
Docket Nos. RM07-19-000 and AD07-7-000 - 83 - 

modifying EQR data could reveal competitive information and result in reduced forward 

liquidity for physical transactions. 

150. The Commission also requested comments on additional steps that it could take to 

promote long-term contracting opportunities. Many commenters point to the importance 

of contract certainty, long-term stability of market rules and regulatory policies, and 

proper market design in supporting long-term contracting, although comments vary on 

how best to provide for these elements. For instance, Old Dominion argues that the 

Commission should reaffirm its commitment to incremental changes to market design to 

prevent instability. PSEG notes that the Commission should resist changing tariffs and 

should not revise contracts under FPA section 206, where either the buyer or seller has 

miscalculated risks. 

151. A majority of commenters indicate that structural impediments to long-term 

contracting prevent market participants from fully utilizing long-term contracts as part of 

their energy portfolios. Impediments cited include differences between buyers and sellers 

in assessing the appropriate long-term price and assessing long-term risks, over-reliance 

on spot markets, market design, and regulatory uncertainty. Many commenters, such as 

FirstEnergy, point to buyers’ and sellers’ inability to agree on a long-term price as the 

real problem with long-term contracts. Some commenters suggest that the Commission 

should review over-reliance on the spot markets, which, they assert, affects forward 

prices and creates a disincentive for parties to engage in long-term deals. 

152. Commenters also propose a variety of more fundamental approaches for the 

Commission to consider for dealing with long-term contracting. Some commenters argue 
Docket Nos. RM07-19-000 and AD07-7-000 - 84 - 

that the Commission should take a more sweeping look at the markets as a whole, noting 

that problems with long-term contracting are merely a symptom of market inefficiency. 

These include a request for an investigation of RTO markets and mandating long-term 

contracting through dedicating portions of transmission lines for long-term arrangements 

or requiring entities to have a percentage of their portfolios as long-term contracts. 

153. Two commenters, American Forest and Portland Cement Association, et al., 

include fairly detailed proposals to address problems with the incentives for long-term 

contracting. American Forest’s proposal, the Financial Performance Obligation (FPO), 

appears to require every generating unit that receives a capacity payment to financially 

guarantee the delivery of energy to the real-time market at or below a specified strike 

price in any hour in which it is dispatched by the RTO to provide service. American 

Forest maintains that the FPO would connect capacity and energy markets and would 

provide a hedge to load by shifting short-term risk of market volatility in energy markets 

to suppliers. It argues that the linked real-time market clearing price and capacity price 

that would result from the FPO would provide an incentive for suppliers to take steps, 

such as long-term contracting, to hedge short-term volatility, and prevent suppliers from 

double recovering revenues from capacity and energy payments. Portland Cement 

Association, et al.’s proposal offers an alternative market design framework, Forward 

Capacity and Energy Market, suggesting that a combination of competitive and 

administrative procedures could be used to obtain the lowest-cost combination of fixed 

and variable costs while preserving the locational economic signals of Locational 

Marginal Pricing. It argues that the proposed framework also would establish economic 
Docket Nos. RM07-19-000 and AD07-7-000 - 85 - 

incentives for both buyers (e.g., LSEs and large customers) and suppliers to negotiate 

long-term bilateral contracts. 

154. A significant number of commenters state that the Commission should take no 

action on the long-term contracting topic, but should instead leave any long-term 

contracting solution to the market. 

5. Proposed Reforms

155. The Commission proposes to require ISOs and RTOs to dedicate a portion of their 

web sites for market participants to post offers to buy or sell power on a long-term basis. 

We are not proposing here the other potential actions considered in the ANOPR and are 

not proposing to address in this docket the other long-term contracting issues raised by 

some commenters. 

156. The proposal for an RTO/ISO web site “bulletin board” for posting long-term 

offers to sell or buy is designed to facilitate the long-term contracting process by 

increasing the transparency of available sellers and buyers for market participants. 

Providing a place for buyers and sellers to offer long-term power transaction 

opportunities should alleviate concerns about sellers and buyers being unable to find one 

another and should encourage more long-term contracting and improve efficiency in the 

market at little cost. Improving information flow can only increase liquidity among 

buyers and sellers. The Commission believes that this requirement will not be 

burdensome for ISOs and RTOs to implement. 

157. The Commission does not propose to mandate the specific type of bulletin board 

that each ISO and RTO must post, but will require each to work with its stakeholders in 
Docket Nos. RM07-19-000 and AD07-7-000 - 86 - 

designing a solution that works for its market participants. We have in mind, however, 

an RTO/ISO bulletin board that would allow persons to post offers to sell or buy without 

making the RTO or ISO responsible for the content of the offers. We are encouraged that 

some ISOs and RTOs have already undertaken this effort. 

158. The Commission proposes to require ISOs and RTOs 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 ISO or RTO has taken to comply with the long-term 

contracts bulletin board requirement and provide information on the bulletin board the 

ISO or RTO has chosen to implement. 

159. The Commission seeks public comment on its proposal not to set by rule the 

specific type of bulletin board that each ISO and RTO must post. This includes comment 

on whether any features are important enough to specify generically, such as the structure 

for the webpage, the extent to which the ISO or RTO must seek feedback on its web 

design, or whether the ISO or RTO or the market participant must post the information. 

Further, we seek comment on our assumption that the costs involved with implementing 

the proposal are minimal and should be recovered in the same manner as other web site 

costs. In addition, the Commission solicits comment on the proposal that the RTO or 

ISO should not be responsible for the content of the offers on its bulletin board. Is a web 

site that includes a clear disclaimer adequate to protect RTOs and ISOs from liability, or 

should the Commission take additional action? Do market participants that post offers 

but fail to reach agreement with counterparties on contract terms and conditions have any 

liability issues? 
Docket Nos. RM07-19-000 and AD07-7-000 - 87 - 

160. As we noted earlier, PJM recently has conducted a series of forums on long-term 

contracts to gather information and facilitate the exchange of ideas.120 We encourage 

similar efforts by other RTOs or ISOs, and the ISO/RTO Council. We encourage RTOs 

and ISOs already working on solutions to these issues to take appropriate steps to ensure 

timely implementation of reasonable solutions as soon as they are ready. The 

Commission also directs Commission staff to perform an analysis of the level of longterm contracting in organized market regions. 

161. In addition, while we appreciate the proposals of American Forest and Portland 

Cement Association, et al. to resolve disincentives to conduct long-term contracting, we 

have concerns that various aspects of the proposals, such as the impact of the proposal on 

capacity markets, would require additional development, review and consideration before 

it would be ripe for inclusion in a rulemaking. The shift of revenues from the spot market 

to some form of forward obligation or hedging option that could occur with the FPO may 

well have advantages, but this shift may create new concerns among LSEs and others 

about capacity market operations and price levels. To help develop a greater level of 

understanding of the proposals we direct staff to conduct a technical conference in a 

separate proceeding to examine the FPO and Portland Cement Association, et al.’s 

alternative market designs and related issues. 

 120 More information on the PJM forums is available at 

http://www.pjm.com/committees/stakeholders/drs/ltc.html. 
Docket Nos. RM07-19-000 and AD07-7-000 - 88 - 

C. Market-Monitoring Policies

162. This section of the NOPR proposes regulations implementing market monitoring 

policies. 

1. Background

163. Market monitors have played an integral role in the organized electric markets 

since the latter’s inception, providing valuable reporting and analysis services not only to 

the Commission, but also to RTOs and ISOs, to market participants, and to state 

commissions. In light of their importance, the Commission has required that all RTOs 

and ISOs incorporate a market monitoring function.121 

164. The span of years over which market monitors have now been in existence has 

given the Commission and others in the industry a track record upon which to evaluate 

the appropriate roles MMUs should play and the protections that might be adopted to 

assist them in performing those roles. In this NOPR, we propose reforms for MMUs 

designed to improve their abilities to monitor and report on the operation of organized 

wholesale electric markets. 

2. Prior Commission Actions Regarding Market Monitoring 

165. The Commission undertook its first generic consideration of market monitoring in 

Order No. 2000, which required an RTO to include market monitoring as one of its 

minimum functions and to submit a market monitoring plan as part of its RTO 

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

31,089 at 31,155 (1999), order on reh’g, Order No. 2000-A, FERC Stats. & Regs. ¶ 

31,092, at 30,993 (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 - 89 - 

proposal.122 The Order did not, however, impose a specific MMU structure on the RTOs. 

The Commission noted in Order No. 2000 that while MMUs were not intended to 

supplant Commission authority, they should be designed in such a way as to provide the 

Commission with an additional means of detecting market power abuses, market design 

flaws and opportunities for improvements in market efficiency.123 The Commission 

ordered RTOs to incorporate in their market monitoring plans certain standards to be met 

by the MMUs, which included ensuring objective information about the markets that the 

RTO operates or administers, proposing appropriate action regarding opportunities for 

efficiency improvement, identifying market design flaws or market power abuses, and 

evaluating whether market participants comply with market rules.124 The Commission 

observed that the information to be gleaned from market monitoring would be beneficial 

not only to the Commission, but also to state commissions and market participants.125 

 122 Prior to this first generic consideration of market monitoring, the Commission 

addressed market monitoring in connection with individual RTO/ISO proposals. See

Pacific Gas and Electric Co., 77 FERC ¶ 61,265 (1996), order on reh’g, 81 FERC ¶ 

61,122 (1997), order on clarification, 83 FERC ¶ 61,033 (1998) (requiring the ISO to file 

a detailed monitoring plan and listing minimum elements for such a plan); PennsylvaniaNew Jersey-Maryland Interconnection, 81 FERC ¶ 61,257 (1997) (PJM Formation 

Order) (requiring PJM to develop a market monitoring program to evaluate market power 

and design flaws). 

123 Order No. 2000, FERC Stats. & Regs. ¶ 31,089 at 31,156. 

124 Id. 

125 Id. 
Docket Nos. RM07-19-000 and AD07-7-000 - 90 - 

166. The Commission next addressed the role of market monitors in its 2003 Order 

Amending Market-Based Rate Tariffs and Authorizations.126 The Commission clarified 

the duties of MMUs in connection with enforcement matters, directing that MMUs refer 

compliance issues to the Commission127 and limiting direct enforcement action by the 

MMUs to objectively identifiable and sanctioned behavior expressly set forth in the 

RTO/ISO tariffs.128 In its subsequent Order on Rehearing, the Commission clarified that 

MMU personnel were not a substitute for Commission enforcement staff.129 Instead, 

MMUs were to provide information to the Commission and its staff, so that the 

Commission could take appropriate action under the FPA. 

167. In May of 2005, the Commission issued a Policy Statement on Market Monitoring 

Units, 130 identifying four tasks which MMUs perform for which they need access to data 

and other resources.131 In an Appendix to the Policy Statement, the Commission set forth 

 126 Investigation of Terms and Conditions of Public Utility Market-Based Rate 

Authorizations, 105 FERC ¶ 61,218 (2003) (Market Behavior Rules Order), order on 

reh’g, 107 FERC ¶ 61,175 (2004) (Market Behavior Rules Rehearing Order). 

127 Market Behavior Rules Order, 105 FERC ¶ 61,218 at P 184. 

128 Id. P 182. 

129 Market Behavior Rules Rehearing Order, 107 FERC ¶ 61,175 at P 165. 

130 Market Monitoring Units in Regional Transmission Organizations and 

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

131 Id. P 2-3. These functions were: (1) to identify ineffective market rules and 

tariff provisions and recommend proposed rule and tariff changes to the ISO or RTO that 

promote wholesale competition and efficient market behavior; (2) to review and report on 

the performance of wholesale markets in achieving customer benefits; (3) to provide 

support to the ISO or RTO in the administration of Commission-approved tariff 

provisions related to markets administered by the ISO or RTO; and (4) to identify 
Docket Nos. RM07-19-000 and AD07-7-000 - 91 - 

detailed Protocols for the MMUs to follow in referring potential tariff or Market 

Behavior Rule violations to the Commission.132 

168. In 2006, PJM Interconnection, L.L.C. (PJM) filed proposed revisions to the MMU 

sections of its tariff, with the general aim of conforming its tariff to the provisions of the 

Policy Statement.133 Several parties filed comments, arguing that PJM’s tariff should 

contain a clear statement of the MMU’s independence and should set forth all the rules 

relevant to the responsibilities and functions of the MMU. In the Commission’s Order on 

Rehearing and Compliance Filing, we noted that these concerns were of a generic nature 

and not necessarily limited to PJM.134 

3. The Need for Commission Action

169. The concerns raised by intervenors in the PJM case impressed upon the 

Commission the need to undertake a generic examination of MMUs, to see if their roles 

could be enhanced so as to improve the efficiency and transparency of organized 

 

instances in which a market participant’s behavior may require investigation and 

evaluation to determine whether a tariff violation has occurred, or which may be a 

potential Market Behavior Rule violation, and immediately notify appropriate 

Commission staff for possible investigation. 

132 Id. at Appendix A. The Market Behavior Rules extant at the time of the Policy 

Statement have since been in part rescinded, with the remainder codified. See Conditions 

for Public Utility Market-Based Rate Authorization Holders, Order No. 674, FERC Stats. 

& Regs. ¶ 31,208 (2006) (Order No. 674). Rescinded Market Behavior Rule 2 has been 

replaced by the Commission’s Anti-Manipulation Rules. See Prohibition of Energy 

Market Manipulation, Order No. 670, FERC Stats. & Regs. ¶ 31,202 (Order No. 670), 

order denying reh’g, 114 FERC ¶ 61,300 (2006). 

133 PJM Interconnection, L.L.C., 116 FERC ¶ 61,038 (2006) (PJM Tariff Order). 

134 PJM Interconnection, L.L.C., 117 FERC ¶ 61,263, at P 19 (2006) (PJM Tariff 

Rehearing Order). 
Docket Nos. RM07-19-000 and AD07-7-000 - 92 - 

wholesale electric markets. To that end, the Commission announced that we would hold 

a technical conference to explore the issues raised by the commenters.135

170. The Commission held the technical conference on market monitoring policies on 

April 5, 2007. At the conference, the Commissioners heard from interested commenters 

on several general subjects.136 Two principal issues received the bulk of attention from 

the commenters at the technical conference. Those were: (i) the need for, and suggested 

methods of achieving, independence on the part of MMUs so they can perform their 

assigned functions; and (ii) the content and proper recipients of the market data and 

analysis developed by the MMUs. These issues are in accord with our own observations 

of areas within the market monitoring function that need reform. For that reason, we 

have included proposals in this NOPR designed to strengthen market monitoring and 

thereby enhance the performance and transparency of organized RTO/ISO markets. 

4. Proposed Reforms

171. The Commission advanced proposals in the ANOPR that responded to the 

concerns expressed by commenters at the technical conference and that reflected the 

Commission’s own observations formed from working within the framework of the 

existing market monitoring provisions. These proposals were designed to strengthen 

 135 Id. P 20. 

136 These subjects included: the development of the concept and functions of 

market monitoring, the MMUs’ role with respect to the Commission, the MMUs’ role 

with respect to ISOs and RTOs, and the MMUs’ role with respect to the various 

stakeholders such as states, generators, transmission providers, and customers. See

Second Notice of Technical Conference, Review of Market Monitoring Policies, Docket 

No. AD07-8-000 (March 9, 2007). 
Docket Nos. RM07-19-000 and AD07-7-000 - 93 - 

market monitoring by safeguarding MMU independence and fostering useful and 

transparent market analysis. The Commission sought comment on the proposals, which 

fell within the two general areas of (i) independence and function and (ii) information 

sharing. In this NOPR, the Commission analyzes the comments received and presents 

revised proposals. 

a. Independence and Function

172. In the ANOPR, the Commission acknowledged the importance of independence on 

the part of MMUs, and stated that there are several means by which to balance 

independence and accountability. The Commission proposed a balanced and flexible 

approach to the problem which 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. 

i. Structure and Tools

(a) Preliminary Proposals in the ANOPR

173. The Commission declined in the ANOPR to propose a “one size fits all” approach 

to the structure of MMUs, noting that there was no appreciable difference among the 

performance of the market monitors that could be attributed to whether they were 

external (an independent contractor who is hired by the RTO or ISO) or internal (one 

whose personnel are employees of the RTO or ISO). Therefore, the Commission 

proposed that it be left to the discretion of each RTO or ISO to decide whether it should 

have an internal MMU, an external MMU, or a hybrid MMU (consisting of both an 

internal market monitor and an external market monitor). 
Docket Nos. RM07-19-000 and AD07-7-000 - 94 - 

174. To ensure that MMUs would have adequate tools with which to do their job, the 

Commission proposed requiring each RTO or ISO to 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. We 

also proposed that RTOs and ISOs include a tariff provision directing the MMU to report 

to the Commission any concerns it has with inadequate access to market data, resources, 

or personnel, and to describe the steps it has taken with the RTO or ISO to resolve these 

concerns. 

(b) Comments on the ANOPR Proposals and Questions

175. The overwhelming bulk of the commenters agreed with the Commission’s 

proposal and opposed imposition of a “one size fits all” approach. A few favored one or 

the other structure. Exelon, Strategic Energy, and Suez favored an external model, on the 

grounds it could best ensure independence.137 NJBPU favored an internal model, at least 

with respect to PJM.138

176. There was also limited support for an alternative reporting structure. The Ohio 

PUC proposed that MMUs report to federal-state boards,139 and the FTC suggested the 

Commission consider the costs and benefits of alternative arrangements, which 

 137 Exelon at 25; Strategic Energy at 13; Suez at 9. 

138 NJBPU at 1-2. 

139 Ohio PUC at 9-14. 
Docket Nos. RM07-19-000 and AD07-7-000 - 95 - 

presumably would involve a structure other than an employment or contractual 

relationship between the MMU and the RTO or ISO.140

177. APPA stated that the real issue to be resolved is not structure but assuring the 

independence of the MMU. It proposed “rules of the road” to accomplish that objective, 

most of which have to do with providing the MMU with adequate tools with which to do 

its job.141 Joint Consumers Advocates also proposed specific MMU principles, most 

involving oversight or tools.142 

178. Most commenters supported the Commission’s proposal that RTOs and ISOs 

include in their tariffs a requirement that they must provide the MMU with adequate tools 

with which to do its job.143 Some stated that access to resources must be full and 

unfettered.144 Others, while generally supporting the proposal, called for budgetary and 

cost containment provisions.145 The North Carolina Commission proposed transparency 

of budget, with any disputes being made subject to Commission review.146 Some 

commenters proposed that the MMU’s offices be located on the premises of the RTO or 

 140 FTC at 16-17. No particular alternative arrangement was suggested. 

141 APPA at 72-73. 

142 Joint Consumer Advocates at 16-19. 

143 See, e.g., Ameren at 36-37; Duke Energy at 20; FirstEnergy at 10; NYISO at 

16; Ohio PUC at 12-14; Portland Cement at 17; Xcel at 23. 

144 American Forest at 45; APPA at 70; The Alliance at 17. 

145 EEI at 42; EPSA at 4; Mirant at 11; North Carolina Commission at 7; Pepco at 

15; PJM Power Providers at 8; PSEG at 17; Reliant at 16. 

146 North Carolina Commission at 7. 
Docket Nos. RM07-19-000 and AD07-7-000 - 96 - 

ISO.147 The PJM MMU argued for control over its own data repository.148 EEI stated it 

did not believe a tariff provision requiring the MMU to report to the Commission any 

concerns it has with adequacy of resources was needed, as MMUs are in regular contact 

with the Commission and can convey any concerns they may have in this regard.149

(c) Commission Proposal

179. The Commission agrees with the bulk of the commenters that the nature of the 

MMU structure is not determinative of either independence or quality of performance, 

and proposes that each RTO and ISO decide for itself, through its appropriate stakeholder 

process, whether it will have an external, internal or hybrid MMU structure. The 

Commission also declines to remove MMUs from overview by their RTOs and ISOs; the 

MMU’s principal duties involve monitoring RTO/ISO markets and advising the RTO or 

ISO on market performance. The fact that MMUs also have reporting obligations to 

outside parties does not change the relationship they have with the RTOs and ISOs, 

which are, by Commission policy, required to maintain a market monitoring function. It 

is also doubtful that an alternative outside structural arrangement, such as reporting to a 

federal-state board, could as effectively replicate the existing close exchange of data 

between the RTO or ISO and the MMU, which all acknowledge is vital if the MMU is to 

properly perform its duties. 

 147 See, e.g., NYISO at 20; North Carolina Commission at 6. 

148 PJM MMU at 10. 

149 EEI at 43. 
Docket Nos. RM07-19-000 and AD07-7-000 - 97 - 

180. The Commission further proposes 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 RTO or ISO should, in addition, also 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/ISO 

data, be kept within the exclusive control of the MMU. 

181. The Commission declines to micro-manage the RTO/ISO relationships with their 

MMUs to the extent of requiring that MMU offices be located on the RTO/ISO premises. 

We are of the view that concerns of this type, as well as appropriate budgetary 

constraints, are best worked out on an individual basis. 

182. The Commission has reconsidered its ANOPR proposal regarding inclusion of a 

tariff provision directing the MMU to report to the Commission any concerns it has with 

inadequate access to market data, resources, or personnel, or to describe the steps it has 

taken with the RTO or ISO to resolve these concerns. The inclusion of such a 

requirement may suggest that the Commission anticipates non-compliance on the part of 

the RTOs and ISOs, whereas the opposite is true. Furthermore, as EEI notes, adequate 

mechanisms are already in place for the MMU to bring any concerns it may have to the 

Commission’s attention, including the complaint process, referrals to the Commission’s 

Office of Enforcement, and informal discussions with Commission staff. 
Docket Nos. RM07-19-000 and AD07-7-000 - 98 - 

ii. Oversight

(a) Preliminary Proposals in the ANOPR

183. The Commission noted that an inherent tension exists in a structure that requires 

MMUs to report to RTO/ISO management yet, at the same time, perform evaluations and 

issue reports that may be critical of that management. We stated that it could be difficult 

for an MMU to discharge these oversight and reporting obligations effectively unless it 

had some degree of independence from RTO/ISO management. The Commission 

proposed that each RTO and ISO, in addition to maintaining a market monitoring 

function, be required to have its MMU, whether internal, external, or a hybrid 

combination of the two, report either directly to the RTO’s or ISO’s board of directors or 

directly to a committee of independent board directors.150 The ANOPR sought comment 

on the Commission’s authority to impose this type of requirement on RTOs and ISOs, as 

well as on the proposal itself. 

(b) Comments on the ANOPR Proposals and Questions

184. The great preponderance of commenters agreed with the Commission’s proposal, 

stating that reporting to the RTO or ISO board would give the MMU more independence 

than if the MMU were to report to management.151 However, CAISO and NYISO 

propose that in the case of a hybrid structure such as theirs (i.e., one which has both an 

 150 The ANOPR noted that this policy would mark a departure from the holding in 

the PJM Tariff Order. PJM Tariff Order, 116 FERC ¶ 61,038 at P 38 (2006). 

151 See, e.g., BP Energy at 29-30; BlueStar Energy at 6; Dynegy at 4; EPSA at 45; 

FirstEnergy at 10; Industrial Consumers at 21; Joint Consumer Advocates at 19; Mirant 

at 11; NARUC at 10; NEPOOL Participants at 28; Pepco at 15; Steel Producers at 18. 
Docket Nos. RM07-19-000 and AD07-7-000 - 99 - 

internal, employee-staffed MMU and an external, non-employee-staffed MMU), the 

internal MMU be permitted to report to management, with the external MMU reporting 

to the board.152 CAISO states that this reporting arrangement ensures that the chief 

executive officer is attuned to the needs of the MMU and that other employees in the 

organization are committed to supporting its functions, while NYISO states that the 

arrangement enables its internal market monitor to work closely with the rest of company 

staff and have greater opportunities to review real-time market operations. Others 

suggested that the MMU report to management for administrative purposes (such as 

human resources and payroll).153 

185. A few commenters opposed any RTO or ISO reporting requirement at all, 

preferring that the MMU report to the Commission or to a joint federal/state board.154 

NRECA proposed that the Commission periodically audit the quality of the MMU’s 

reports and investigations,155 and TAPS proposed that any change in the MMU’s status, 

such as contract termination or renewal, be reviewed and approved by the 

Commission.156

 152 CAISO at 3; NYISO at 26. 

153 EEI at 43; SoCal Edison-SDG&E at 10. 

154 See, e.g., OMS at 14-15; OPSI at 4-6; Ohio PUC at 9; North Carolina 

Commission at 6. 

155 NRECA at 26. 

156 TAPS at 58. 
Docket Nos. RM07-19-000 and AD07-7-000 - 100 - 

186. Reliant proposed that the MMU must report to a full cross-section of the board.157 

Conversely, other commenters felt that management representatives on the board should 

be excluded from MMU oversight.158 PJM agreed with the ANOPR proposal, but 

expressed concern that the board might be given an oversight responsibility without the 

authority to actually oversee the MMU.159 PJM states that any approach that does not 

place responsibility in the Commission for the functioning and performance of MMUs, 

while limiting the RTO’s ability to supervise or oversee the MMU, would “raise serious 

legal questions about the Commission’s ability to limit a public utility’s management of 

its business.”160 This conditional objection was the only comment that suggested the 

Commission may not have the authority to order the proposed reporting relationship.161

(c) Commission Proposal

187. The Commission proposes 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 proposes that management representatives on the 

 157 Reliant at 16. 

158 OPSI at 4-6; Old Dominion at 22. 

159 PJM at 22-24. 

160 PJM at 24. PJM argues that the Commission does not have jurisdiction over 

utility employment relationships or contracts with service providers, on the grounds these 

functions do not constitute “a sale for resale or transmission of electric power in interstate 

commerce.” PJM at n. 41. 

161 California PUC did not disagree that the Commission can require MMUs to 

report to the RTO or ISO board, but requested the Commission to set forth the basis for 

this authority and provide an opportunity to comment. California PUC at 17. 
Docket Nos. RM07-19-000 and AD07-7-000 - 101 - 

board be excluded from this oversight function. However, the RTOs and ISOs, should 

they deem it appropriate, may have the MMU report to management for administrative 

purposes, such as pension management, payroll and the like. Furthermore, the 

Commission is sympathetic to the desires expressed by CAISO and NYISO to retain the 

advantages they see in their hybrid reporting structures. Thus, if an RTO or ISO has two 

market monitoring bodies, an internal and an external one, the Commission proposes that 

the RTO or ISO may have the internal MMU report to management with respect to both 

its market monitoring and administrative functions, and the external MMU report to the 

board. 

188. The Commission, as noted above, finds little merit in the suggestions that the 

MMU report to a body other than the RTO or ISO, such as to the Commission or to a 

federal/state board. Commenters afford no details as to how this structural arrangement 

could be achieved, either from an economic, jurisdictional, or practical point of view, or 

how such a potentially cumbersome structure as a joint inter-governmental body could 

oversee MMUs in a timely and responsive manner. The Commission itself will be 

adequately informed of the results of MMU monitoring through the referral process and 

through the various venues for the sharing of market information; this sharing of market 

information applies as well to the states and other interested bodies, who will thereby be 

adequately apprised of MMU performance and can bring any concerns they may have in 

this regard to the RTO or ISO or to the Commission. 

189. The Commission declines to propose a formal auditing procedure for MMUs, but 

expects that their work product will be of the highest quality. The Commission remains 
Docket Nos. RM07-19-000 and AD07-7-000 - 102 - 

free to undertake an audit in any given instance, should that appear to be appropriate, and 

any concerns regarding the quality of MMU work product can always be brought to the 

Commission’s attention. The Commission also declines to propose a blanket requirement 

that all changes in MMU status, such as contract termination or renewal, be subject to 

Commission review and approval. Although requirements of this type are currently 

contained in the contractual arrangements of certain RTOs and ISOs,162 the Commission 

declines to propose extending this requirement to all RTOs and ISOs, in accordance with 

our reluctance to impose a “one size fits all” approach in structural areas. We believe the 

issue should be dealt with on a case-by-case basis. 

190. With respect to PJM’s concern that it may be burdened with oversight 

responsibility over MMUs without possessing full authority to carry out that 

responsibility, the Commission notes that its reporting proposal does nothing to increase 

the limitations on an RTO’s or ISO’s authority over its MMU. For MMUs that currently 

report to management, the proposal merely shifts oversight from management to the 

board.163 Furthermore, the monitoring functions of MMUs affect sales for resale and the 

 162 E.g, 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 No.1, Attachment 

AJ, § 11, Second Revised Sheet No. 699 (2006). The same is true for ISO-NE. 

Participants Agreement among ISO New England, Inc. and the New England Power 

Pool, et al., § 9.4.5. 

163 PJM cites Cal. Indep. Sys. Operator Corp. v. FERC, 372 F.3d 395 (D.C. Cir. 
Docket Nos. RM07-19-000 and AD07-7-000 - 103 - 

transmission of electric power in interstate commerce, and as such are properly subject to 

Commission regulation to ensure MMU objectivity. As we noted in Order No. 2000,164

the Commission has a responsibility to protect against anticompetitive effects in 

electricity markets,165 and an independent MMU is an important element upon which we 

rely to safeguard such competition. Our proposal maintains oversight authority within 

the RTO or ISO, while fostering MMU independence through the elimination of direct 

management control. For these reasons, the Commission believes the proposal strikes the 

appropriate balance between MMU independence and RTO/ISO oversight. 

iii. Functions

(a) Preliminary Proposals in the ANOPR

191. Noting that the issue of independence is integrally related to that of the functions 

MMUs are expected to perform, the Commission proposed continuing the following 

existing functions of MMUs: (1) identifying ineffective market rules and tariff 

 

2004), in support of its concern. However, that case involved FERC’s attempt to replace 

existing CAISO board members with a slate proposed by an independent search firm. 

Obviously, alteration of the very composition of an RTO or ISO board is an entirely 

different matter from a requirement that MMUs report to the board, instead of to 

management. The latter requirement in no way interferes with the internal composition 

of the board. Furthermore, the cited case noted that if FERC concluded that CAISO 

lacked the independence or other necessary attributes to constitute an ISO, it need not 

approve CAISO as an ISO. Id. at 404. Similarly, it is the Commission’s view that the 

MMU may lack sufficient independence if it reports to management, rather than to the 

board; thus we may require RTOs and ISOs, as a condition of their continued RTO/ISO 

status, to incorporate the proposed requirement in their tariffs. 

164 Order No. 2000, FERC Stats. & Regs. ¶ 31,089 at 31,155.

165 See Gulf States Utilities v. FPC, 411 U.S. 747, 758-59 (1973). 
Docket Nos. RM07-19-000 and AD07-7-000 - 104 - 

provisions and recommending proposed rule and tariff changes; (2) reviewing and 

reporting on the performance of the wholesale markets; and (3) identifying and notifying 

the Commission staff of instances in which a market participant’s behavior may require 

investigation. The Commission also proposed requiring the MMUs to advise the 

Commission and other interested entities, in addition to the RTO or ISO, of 

recommendations for rule or tariff changes; retaining the existing Protocols (with 

appropriate updates) governing referral of potential market violations to the Commission, 

which are included as an Appendix to the Policy Statement;166 and expanding the subject 

matter of such referrals to include suspected rule or tariff violations committed by an 

RTO or ISO as well as by market participants, as well as suspected violations of other 

Commission-approved rules and regulations, such as Affiliate Restrictions167 and 

Standards of Conduct. 

(b) Comments on the ANOPR Proposals and Questions

192. There was general agreement from commenters concerning continuation of the 

three functions identified in the ANOPR. Several commenters stated that MMUs should 

not themselves participate in effectuating market design, although they should advise the 

 166 The Commission clarified that since issuance of the Policy Statement, Market 

Behavior Rule 2, referred to in the Protocols, has been rescinded and replaced by the 

Commission’s Anti-Manipulation Rules. Therefore, violations currently to be referred to 

the Commission include conduct suspected of violating the Anti-Manipulation Rules, as 

well as tariff violations and violations of the remaining, codified Market Behavior Rules. 

See Order No. 674 and Order No. 670.

167 The previous term “Code of Conduct” has been replaced by “Affiliate 

Restrictions” in the final rule for Market-Based Rates for Wholesale Sales of Electric 

Energy, Capacity, and Ancillary Services by Public Utilities, Order No. 697, 72 Fed. Reg. 

39,904 (July 20, 2007), FERC Stats. & Regs. ¶ 31,252 (2007). 
Docket Nos. RM07-19-000 and AD07-7-000 - 105 - 

RTO or ISO on proposed weaknesses in the existing market design and make suggestions 

for improving it.168 A few commenters opposed reporting suspected RTO or ISO 

violations, arguing that this would impair the frank exchange of information between 

RTO or ISO employees and the MMU.169 However, most comments on the subject 

supported such reporting, and several commenters suggested that such reporting be 

expanded to include instances of inappropriate dispatch (either too conservative or too 

aggressive) which, although not constituting tariff violations, might nonetheless impair 

optimal market performance.170

193. Several commenters opposed a requirement that MMUs report suspected 

violations of the Standards of Conduct or Affiliate Restrictions, arguing that the MMUs 

do not have expertise in this area and should not be diverted from their main task of 

monitoring the markets.171 A number of the comments suggested that the MMUs should 

not audit for such violations, but should report them if they come across them in the 

ordinary course of business.172 Similarly, some commenters suggested that MMUs 

 168 See, e.g., Old Dominion at 23; OMS at 18; OPSI at 9; NY TO at 15. 

169 NYISO at 25-26; CAISO at 7-8. 

170 Strategic Energy at 13. 

171 See, e.g., EEI at 45; EPSA at 47; Exelon at 26; FirstEnergy at 10-11; Pepco at 

17. 

172 Duke Energy at 23; NYISO at 25-26; ISO-NE at 8-9. 
Docket Nos. RM07-19-000 and AD07-7-000 - 106 - 

should not audit for suspected rule or tariff violations by the RTOs or ISOs, but should 

report them if they came across them in the ordinary course of business.173

194. The commenters generally supported reporting proposed tariff or rule changes to 

other interested parties as well as to the RTO and ISO, particularly mentioning market 

participants and stakeholders.174 NEPOOL Participants, however, cautioned that in 

certain instances this might effectively broadcast the existence of a “loophole” that could 

be exploited before a rule or tariff change could be accomplished.175

(c) Commission Proposal

195. The Commission notes that its proposals in the ANOPR did not contemplate that 

the MMU make market design decisions itself, which are within the purview of the RTO 

or ISO through stakeholder processes and Commission approval, but rather that the 

MMU should advise the RTO or ISO and the Commission in this area. It was also not 

the Commission’s intention that the MMU be required to seek out potential violations by 

the RTO or ISO, or audit for Standards of Conduct or Affiliate Restrictions violations. 

The Commission agrees that any proactive investigations in these areas would divert the 

resources of the MMU from its primary responsibilities and potentially embroil it in areas 

not within its core expertise. Standards of Conduct and Affiliate Restrictions violations 

in particular may be difficult to identify without possession of specialized knowledge. 

 173 ISO-NE at 8; Duke Energy at 22. 

174 See, e.g., Old Dominion at 23;, Pepco at 16; Ameren at 13; APPA at 76-77. 

175 NEPOOL Participants at 29-30. 
Docket Nos. RM07-19-000 and AD07-7-000 - 107 - 

Therefore, the Commission agrees that any suspected violations in these areas need be 

referred only if discovered in the ordinary course of the MMU’s monitoring duties. Any 

final determination as to whether a violation has occurred would, of course, be the 

responsibility of the Commission. 

196. However, the Commission finds little merit in the suggestion that our proposal to 

require MMUs to report suspected misconduct by RTOs and ISOs would impair the frank 

exchange of information between RTO or ISO employees and the MMU. Such an 

argument could equally be applied to scrutiny by any independent entity and, taken to its 

logical conclusion, would effectively exempt RTOs and ISOs from investigation. 

Permitting such an exemption might encourage a culture of lax adherence to rule and 

tariff requirements. 

197. The Commission agrees that an RTO or ISO could conduct dispatch in such a way 

as to result in unnecessary market inefficiencies, and therefore proposes that the MMU 

should advise Commission staff of any substantial concerns it has along these lines.176 

With respect to broadening the reporting of proposed rule and tariff changes to other 

interested parties as well as to the RTO or ISO, the Commission finds merit in the 

concern that such broad dissemination of information might make entities aware of a 

“loophole” that could be exploited before the necessary rule or tariff change could be 

 176 If the MMU believes the dispatch practice rises to the level of a tariff violation, 

the MMU should follow the procedures outlined in the Protocols for referring market 

violations to the Commission, which involve a written referral to the Office of 

Enforcement with copies to the Office of Energy Market Regulation and the 

Commission’s Office of the General Counsel. Otherwise, its concerns should be brought 

to the attention of the Division of Energy Market Oversight in the Office of Enforcement. 
Docket Nos. RM07-19-000 and AD07-7-000 - 108 - 

effected. For that reason, the Commission proposes that an exception be made to the 

general rule of full disclosure, which exception would provide that in the event the MMU 

believes broad dissemination of such information in a given instance could lead to 

exploitation, that it limit distribution of the information to the RTO or ISO and to 

Commission staff, with an explanation of why further dissemination should be avoided at 

that time. 

198. The Commission therefore proposes that the functions an MMU is to perform 

include the following: (1) evaluating existing and proposed market rules, tariff 

provisions and market design elements for their effectiveness, 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 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, 
Docket Nos. RM07-19-000 and AD07-7-000 - 109 - 

including suspected rule or tariff violations, market manipulation, inappropriate dispatch, 

and suspected violations of Commission-approved rules and regulations. 

199. In furtherance of its goal of ensuring independent analysis on the part of MMUs, 

the Commission also proposes that RTOs and ISOs include a provision in their tariffs 

specifying that they may not alter the reports generated by the MMUs nor dictate the 

conclusions reached by the MMUs, although they may establish a reasonable mechanism 

for review and comment on MMU reports while still in draft form. The Commission 

believes this proposal will enable the MMU to receive potentially helpful comment, 

while removing the ability of the RTO or ISO to unreasonably influence or impede the 

MMU’s analysis. 

iv. Mitigation and Operations

(a) Preliminary Proposals in the ANOPR

200. The Commission expressed concern about whether it was possible for MMUs to 

maintain independence in evaluating and reporting on market performance while at the 

same time providing support to the RTO or ISO in the administration of its tariff, which 

often takes the form of MMU-conducted market power mitigation. The Commission 

noted that because the operation and mitigation functions performed by MMUs directly 

affect market outcomes and performance, an inherent conflict arises when an MMU 

reports on market outcomes that the MMU itself has influenced. For these reasons, the 

Commission proposed requiring that MMUs refrain from assisting the RTO or ISO in 

tariff administration, from participating in RTO/ISO market operations such as 

mitigation, and from taking direct actions to influence the market, and instead concentrate 
Docket Nos. RM07-19-000 and AD07-7-000 - 110 - 

on their role of providing market evaluation, reports, and advice. 

(b) Comments on the ANOPR Proposals and Questions

201. As to the issue of tariff administration, there was substantial, although not 

universal, agreement that this was a task which properly falls within the purview of the 

RTO or ISO, not the MMU. A few commenters took a middle position, suggesting that 

in a hybrid structure, the internal MMU could be involved in tariff administration, but not 

the external MMU.177 Some commenters requested clarification as to what was 

envisioned in the concept of tariff administration.178

202. There was no such agreement on the proposal to remove MMUs from mitigation, 

and this issue proved to be the most contentious one in the entire market monitoring 

section. A substantial minority of commenters concurred in the ANOPR proposal, 

agreeing that it constituted a conflict of interest for the MMUs to conduct mitigation, and 

stating that it would compromise the MMU’s independence for it to both evaluate market 

performance and conduct mitigation.179 A number of market participants, such as 

Dominion Resources, FirstEnergy, Duke Energy, Dynegy and Pepco, support the 

proposal. NCEMC, AWEA, and Silicon Valley Power also support the proposal. 

203. EPSA stated that the MMU should not assist tariff administration or market 

operations, including mitigation, on any independent basis not clearly outlined in the 

 177 EEI at 46; New York PSC at 11-12; NY TO at 16-17. 

178 See, e.g., OMS at 25-26; OPSI at 20-22; PSEG at 17-19. 

179 See, e.g., Ameren at 39; Xcel at 24; Dynegy at 5; Duke Energy at 23; EPSA at 

45-46; Mirant at 13. 
Docket Nos. RM07-19-000 and AD07-7-000 - 111 - 

tariff.180 EEI agreed that there should be a functional separation between the MMUs and 

the operational activities of the RTOs and ISOs, which EEI states can be accomplished 

either by having the RTOs and ISOs perform operational functions, or having the internal 

market monitor perform them.181 

204. A majority of commenters, representing a spectrum of market participants, 

consumer groups, and RTOs and ISOs, opposed the proposal to remove the MMU from 

mitigation, and advanced a variety of reasons against it.182 Several commenters, 

including Portland Cement, the Pennsylvania PUC, OPSI and OMS, maintained that it 

would create an even greater conflict of interest, because the RTO or ISO would have a 

role both in rule development and implementation.183 Commenters also stated that the 

RTO or ISO would be more heavily influenced than would an MMU by market 

participants, upon whom it depends for its existence, and that its employees have close 

personal relationships with market participants and are often former employees of market 

participants.184 OMS suggested RTO or ISO management might be hesitant to perform a 

needed mitigation measure if the measure were to affect a market participant with a 

 180 EPSA at 45. 

181 EEI at 46. 

182 See, e.g., American Forest at 47-49; APPA at 74-77; BP Energy at 31; 

California PUC at 21-23; Industrial Coalitions at 21-23; Joint Consumer Advocates at 20-

21; NARUC at 11; NEPOOL Participants at 30-32; Northeast Utilities at 13-14; New 

England Power Generators at 12-13; OMS at 23; OPSI at 13-19; Pennsylvania PUC at 

16-17. 

183 Portland Cement at 19; Pennsylvania PUC at 16; OPSI at 17; OMS at 23. 

184 See, e.g., Portland Cement at 19. 
Docket Nos. RM07-19-000 and AD07-7-000 - 112 - 

credible threat to leave the RTO or ISO.185 Potomac Economics suggested the RTO or 

ISO can be insulated from market participant influence by having the MMU administer 

mitigation, whereas if the RTO or ISO had responsibility for the task it would face the 

full brunt of market participant displeasure and influence.186 Midwest ISO and OPSI 

opined that consumers would feel less confidence in the fair application of mitigation 

were the function to be transferred to the RTO or ISO.187 

205. Another argument against the proposal was voiced by the Pennsylvania PUC, 

which stated that RTO and ISO managers have acquired their primary expertise in 

transmission or generation operations and have little expertise in economics.188 ISO-NE 

and TAPS suggested that administering mitigation gives the MMU better familiarity with 

the working of the market and assists it in performing its analytical functions.189 Other 

commenters stated that most mitigation is non-discretionary, and therefore would not 

draw the MMU into a substantial conflict of interest as far as its analytic tasks are 

concerned.190 One commenter suggested that a technical conference be convened to 

examine the issue.191

 185 OMS at 23. 

186 Potomac Economics at 7-8. 

187 Midwest ISO at 25-26; OPSI at 13. 

188 Pennsylvania PUC at 16-17. 

189 ISO-NE at 10-12; TAPS at 59. 

190 See, e.g., Potomac Economics at 6. 

191 New England Conference at 19. 
Docket Nos. RM07-19-000 and AD07-7-000 - 113 - 

206. The RTOs and ISOs, including ISO-NE, Midwest ISO, and NYISO, were mainly 

opposed to removing the MMU from mitigation.192 CAISO stated it had no opinion, but 

wanted clarification as to whether the ISO or an independent entity would do the 

mitigation.193 SPP stated it did not object, but indicated that it believed it would be in 

compliance if its internal MMU administered the mitigation (which was not the intent of 

the ANOPR proposal).194 PJM, whose market monitor does not administer mitigation, 

supports the proposal.195

(c) Commission Proposal

207. The ANOPR proposal to remove MMUs from tariff administration was designed to 

strengthen their independence. The current practice of allowing MMUs to support the 

RTOs and ISOs in tariff administration necessarily makes their role subordinate to that of 

the RTOs and ISOs, and thus weakens that independence. Furthermore, freeing MMUs 

from tariff administration would allow them to objectively monitor the markets, without 

the bias that might arise from their personal involvement in tariff administration. 

208. Some commenters argue that RTOs and ISOs do not currently have individuals 

qualified to carry out mitigation. If true, this condition is simply a reflection of the fact 

that the RTOs and ISOs have not needed to hire such personnel, since the MMUs were 

already performing the task for them. If necessary, RTOs and ISOs could acquire the 

 192 ISO-NE at 9-12; Midwest ISO at 25; NYISO at 23-24. 

193 CAISO at 8. 

194 SPP at 10. 

195 PJM at 25-27. 
Docket Nos. RM07-19-000 and AD07-7-000 - 114 - 

staff needed to carry out mitigation functions, and once this was accomplished the MMUs 

would be able to concentrate on their core job of monitoring the markets, without the 

potential conflict of interest that arises from reviewing their own mitigation. 

209. Several commenters contend that RTOs and ISOs are more susceptible to influence 

from market participants than are MMUs, and therefore would not be as diligent in 

performing mitigation. However, mitigation is supposed to be nondiscretionary in nature. 

RTOs and ISOs, as well as MMUs, are required to limit the administration of tariff 

compliance to those provisions expressly set forth in the tariff, involve objectively 

identifiable behavior, and do not subject the seller to sanctions or consequences other 

than those expressly approved by the Commission and set forth in the tariff, with the right 

of appeal to the Commission.196 That being the case, any failure by the RTO or ISO to 

carry out required mitigation would be readily apparent to the MMU, whose job of 

monitoring the markets necessarily includes determining whether mitigation has been 

properly performed. Any persistent or substantial failure by the RTO or ISO in this 

regard would constitute a tariff violation and, as such, should be referred to the 

Commission’s Office of Enforcement staff. 

210. The Commission therefore proposes that MMUs be removed from tariff 

administration, including mitigation. Although we believe the advantages of doing so 

outweigh the temporary transition pains that may result, we are nonetheless sensitive to 

the many concerns raised by those commenters who oppose the proposal. We therefore 

 196 Market Behavior Rules Order, 105 FERC ¶ 61,218 at P 182; Policy Statement, 

111 FERC ¶ 61,267 at P 5. 
Docket Nos. RM07-19-000 and AD07-7-000 - 115 - 

solicit comments on the activities that would be needed to make the transition to 

RTO/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 wish to raise regarding the proposal. 

v. Ethics

(a) Preliminary Proposals in the ANOPR

211. The Commission proposed imposing certain minimum ethics standards upon 

market monitor personnel, in particular prohibiting such personnel from owning financial 

interests in any market participants. The Commission noted that all existing RTOs and 

ISOs have some type of conflict of interest or other ethics provisions, although not 

always in their tariffs, and proposed standardizing such provisions and requiring their 

inclusion in the tariffs themselves. 

(b) Comments on the ANOPR Proposals and Questions

212. Most commenters agreed that certain minimum ethical standards should be 

imposed on MMU employees, citing in particular conflict of interest provisions.197 Many 

argued that the RTOs and ISOs be allowed the flexibility to develop their own provisions, 

in addition to the core minimum set forth by the Commission.198 Some commenters 

 197 See, e.g., Duke Energy at 24; Old Dominion at 25; OMS at 27-28; OPSI at 22; 

Silicon Valley Power at 13; Steel Producers at 19. 

198 See, e.g., APPA at 77; EEI at 49; Midwest ISO at 28; NYISO at 17; Pepco at 

18-19. 
Docket Nos. RM07-19-000 and AD07-7-000 - 116 - 

thought it unnecessary to include the standards in the tariffs, suggesting they could be 

posted on the RTO or ISO web site instead.199

(c) Commission Proposal

213. The Commission agrees with the majority of the commenters that ethical standards 

for MMU employees should be included in the RTO or ISO tariff. Such inclusion would 

allow protest by intervenors and permit Commission review and enforcement. 

214. In light of the fact that RTOs and ISOs currently impose ethical standards on their 

MMUs, although not always in their tariffs, and which in some cases are the same 

standards they apply to their other employees, the Commission proposes that 

development of the particular ethical standards to be applied to MMUs be left in the first 

instance to the discretion of the RTOs and ISOs. However, the Commission believes 

these standards should include certain minimum requirements to be imposed on MMU 

employees, as follows: (i) employees shall have no material affiliation (to be defined by 

the RTO or ISO) with any market participant or affiliate; (ii) employees shall not serve as 

an officer, employee, or partner of a market participant; (iii) 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); (iv) employees shall 

not engage in any market transactions other than the performance of their duties under the 

tariff; (v) 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 

 199 EPSA at 46; Exelon at 27. 
Docket Nos. RM07-19-000 and AD07-7-000 - 117 - 

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; (vi) 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 (vii) employees must advise their supervisor (or, in 

the case of the MMU manager himself, advise the RTO or ISO board) 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 such 

market participant.200

vi. Tariff Provisions

(a) Preliminary Proposals in the ANOPR

215. The Commission proposed that each RTO and ISO set forth all its provisions 

involving market monitoring in one section of its tariff, noting that in order for MMUs to 

achieve transparency of function, the detailed obligations imposed upon them must be 

made clear and accessible, and also be subject to approval and enforcement by the 

Commission. 

(b) Comments on the ANOPR Proposals and Questions

216. There was widespread support for this proposal, although some commenters 

proposed that non-substantive MMU provisions be posted instead on the RTO or ISO 

 200 Some external MMUs may currently have business associations which 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 RTO or ISO 

should propose a suitable transition plan in its compliance filing. 
Docket Nos. RM07-19-000 and AD07-7-000 - 118 - 

web site.201 Duke Energy proposed that the RTO or ISO be allowed to perform 

centralization of the tariff provisions the next time it makes an amendment to its market 

monitoring rules.202 The PJM MMU proposed that MMU provisions be included 

elsewhere in the tariff as well as in the MMU section, if the context so requires.203

(c) Commission Proposal

217. In accordance with the bulk of the comments on this subject, the Commission 

proposes that the RTOs and ISOs be required to include in their tariffs, and centralize in 

one section, all their MMU provisions. Including all MMU provisions in the tariff will 

ensure they are subject to the compliance requirements that attach to tariff provisions, and 

will give notice to interested parties, and thus an opportunity to intervene, when a tariff 

filing is made. As noted in the ANOPR, centralization of the MMU provisions has the 

obvious advantage of clarity and ease of reference. The Commission also proposes that 

the RTOs and ISOs include a mission statement for the MMU in the introductory portions 

of the section. This statement should 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. 

218. The Commission disagrees with the comment requesting that the RTOs or ISOs be 

permitted to delay centralization until such time as they may choose, or otherwise be 

 201 EPSA at 46; Pepco at 19. 

202 Duke Energy at 24. 

203 PJM MMU at 17. 
Docket Nos. RM07-19-000 and AD07-7-000 - 119 - 

required, to make an amendment to their MMU rules. Such amendments will in all 

likelihood be required after issuance of a final rulemaking in this proceeding, and in any 

event the requirement should not be unduly onerous. Therefore, the Commission 

proposes that the RTOs and ISOs centralize their MMU tariff provisions when they make 

their compliance filings in connection with this proceeding. The Commission also sees 

no reason to forbid the RTOs and ISOs from posting MMU provisions elsewhere in their 

tariffs as well as in their MMU sections, should clarity and context so require, as long as 

appropriate cross-referencing is made. 

b. Information Sharing

219. The Commission advanced proposals in the ANOPR that responded to requests of 

commenters at the technical conference for dissemination of expanded market 

information, and to a broader group of recipients. In particular, given the integral 

relationship between wholesale and retail rates, the Commission acknowledged the need 

for information by state commissions to assist them in performing their regulatory 

functions. However, the Commission noted that since public disclosure of certain 

information could harm market participants or could facilitate collusion under some 

circumstances, it was necessary to balance the need for information access with 

confidentiality concerns. The Commission solicited comments on the proposed changes. 

i. Enhanced Information Dissemination

(a) Preliminary Proposals in the ANOPR

220. The Commission proposed enhancing the dissemination of information in several 

areas. Specifically, the Commission proposed that MMUs be required to report 
Docket Nos. RM07-19-000 and AD07-7-000 - 120 - 

comprehensively on aggregate market and RTO/ISO performance on a regular basis, but 

no less frequently than quarterly, to Commission staff, to staff of interested state 

commissions, and to the management and board of directors of the RTOs or ISOs. 

Further, the Commission proposed that MMUs should be required to deliver materials 

supporting their conclusions; make one or more of their staff members available for a 

conference call with representatives from the Commission, state commissions, and RTO 

or ISO; and work cooperatively to develop any further materials which might be useful to 

the Commission, to the state commissions and to the RTOs or ISOs.204 Finally, the 

Commission proposed that offer and bid data, without identification of the market 

participants and with a lag of three months, be posted on the RTO or ISO web site. 

221. The Commission requested comment on whether the proposal met the needs of the 

state commissions and whether there were other kinds of information needed by state 

commissions to fulfill their regulatory responsibilities. The Commission further solicited 

comment on whether there was a generic standard or test that could be used to determine 

what specific information should be provided to state commissions. 

(b) Comments on the ANOPR Proposals and Questions

222. No comments were received proposing a generic standard or test to determine the 

specific information that should be provided to state commissions. There were relatively 

 204 The Commission clarified that such reports and meetings were not intended to 

restrict the MMU from meeting individually with Commission staff, staff of state 

commissions, market participants, or other stakeholders, or sharing information with 

these various constituencies, subject to appropriate restrictions on confidentiality. 
Docket Nos. RM07-19-000 and AD07-7-000 - 121 - 

few comments identifying specific types of data needed;205 rather, most commenters 

supporting greater access argued that state agencies should receive all available market 

information in order to assist them in their regulatory tasks.206

223. There was substantial support for the proposal to require quarterly reports and 

conference calls.207 Some commenters, however, thought comprehensive reports would 

be too costly and unduly time consuming.208 Pepco suggested that these quarterly reports 

not be as extensive as the current annual reports, in order to avoid an excessive drain on 

the money and resources of the MMUs.209 There was also concern that confidentiality 

protections be observed.210 At least one commenter suggested that state attorneys general 

be included in the process as well as state commissions, since not all energy providers 

 205 The California PUC set forth a lengthy list of desired market information, such 

as confidential and disaggregated data, bid data, generator dispatch data, generator 

performance data, unit commitment, scheduled and operational levels, and what units set 

clearing prices. It cautioned, however, that California’s needs are specific to its market 

design and structure as a single state ISO, and that data reporting protocols would vary 

from state to state. California PUC at 27-30. 

206 See, e.g., FirstEnergy at 11; NARUC at 6; Massachusetts AG at 5; Joint 

Consumer Advocates at 22; New York PSC at 13. 

207 See, e.g., BlueStar Energy at 6-7; Duke Energy at 26; Industrial Consumers at 

37; NEPOOL Participants at 32; New England Conference at 19; North Carolina Electric 

Membership at 11; NRECA at 24; Old Dominion at 26. 

208 EEI at 50; EPSA at 48; Mirant at 15; Duke Energy at 26. 

209 Pepco at 19-20. 

210 Constellation at 19; J. Aron, Barclays, Morgan Stanley at 6; Old Dominion at 

26. 
Docket Nos. RM07-19-000 and AD07-7-000 - 122 - 

and consumers are associated with entities regulated by state commissions.211 Some 

commenters, although recognizing that inclusion of market participants in conference 

calls would be unwieldy, proposed that they be included in the dissemination of the 

reports.212

224. There was substantial comment on the proposal to reduce the lag period for offer 

and bid data to three months, with a majority either favoring the Commission’s proposal 

or not actively opposing it.213 Some commenters stated that the lag period should be even 

shorter than three months, arguing that such information is released in Australia and the 

United Kingdom in close to real time, with no apparent adverse effects.214 Others 

favored retention of the six-month period.215 There was substantial support for 

something slightly longer than three months, in order to avoid the problem of data release 

within the same season; such release, it was argued, would provide opportunities for 

collusion and market power abuse.216 EEI notes that different RTOs and ISOs have 

reached differing conclusions as to the appropriate lag time, and suggested that the 

 211 APPA at 84. See also LPPC at 15. 

212 See, e.g., Old Dominion at 26. 

213 See, e.g., Reliant at 22; PJM at 29; PSEG at 20; SMUD at 15; CAISO at 10; 

Connecticut and Massachusetts Municipals at 27; DC Energy at 9; Massachusetts AG at 

5; Midwest ISO at 29; NEPOOL Participants at 33. 

214 Industrial Consumers at 37-38; TAPS at 61. 

215 See, e.g., Ameren at 42; Duke Energy at 26-27; Dynegy at 6; Industrial 

Coalitions at 24; NJBPU at 2; PJM MMU at 18. 

216 See, e.g., Dynegy at 6; NJPBU at 2; OMS at 35; OPSI at 29; Old Dominion at 

26. 
Docket Nos. RM07-19-000 and AD07-7-000 - 123 - 

Commission take into account regional differences, with a lag time no greater than six 

months and no less than three months.217 

225. Some commenters argued that masking the identity of the participants harmed the 

smaller players, contending that the larger players already have software programs which 

enable them to ascertain the identities of the participants.218 OPSI supported maintaining 

confidentiality by the aggregation of cost data,219 and Reliant argued that bidding data 

should be masked to avoid matching offers with the known output of the plant in 

question, thereby revealing the identity of the participant.220

(c) Commission Proposal

226. The Commission declines to propose a generic standard or test to determine the 

type of information that may be disseminated to state commissions. Inasmuch as there 

was no support for such a standard, the Commission believes the type of information to 

be released 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. 

 217 EEI at 52-53. 

218 Pennsylvania PUC at 18; TAPS at 62. 

219 OPSI at 30. OPSI includes reference price or unit estimated cost data within 

the term. 

220 Reliant at 22. Reliant used the term “bid data,” which the Commission 

assumes refers to offers, given the company’s concern over matching offers to unit 

output. 
Docket Nos. RM07-19-000 and AD07-7-000 - 124 - 

227. The Commission proposes 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 agrees that including market participants on 

conference calls would be unwieldy, and proposes limiting participation on such calls to 

Commission staff, RTO and ISO staff, staff of interested state commissions, and staff of 

state attorneys general should they express a desire to attend. 

228. The Commission agrees that quarterly reports should not be as extensive as the 

annual state of the market reports. Preparing overly extensive reports would divert the 

attention of the MMUs from their tasks of daily monitoring and of providing 

recommendations to the RTO or ISO and the Commission regarding desirable rule and 

tariff changes. The Commission also believes that the annual state of the market reports 

have proven to be useful documents, and proposes 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. 

229. The Commission is persuaded by the comments that no harm generally would 

result from shortening the current six-month lag period.221 However, the Commission 

acknowledges that in some instances release of such information in the same season 

could afford opportunities for collusion.222 Therefore, the Commission proposes that the 

 221 The Commission recently approved the request of ISO-NE and NEPOOL to 

shorten the lag time for release of ISO-NE offer and bid data from six months to roughly 

three months. ISO New England Inc. and New England Power Pool, 121 FERC ¶ 61,035 

(2007) (ISO-NE Bid/Offer Order). 

222 In the ISO-NE Bid/Offer Order, we found that the combination of ISO-NE’s 
Docket Nos. RM07-19-000 and AD07-7-000 - 125 - 

time period for the release of offer and bid data be reduced to three months, but that the 

RTO or ISO may propose a shorter period, with accompanying justification. However, 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 the release of a report if the 

release were otherwise to occur in the same season as reflected in the data. 

230. The Commission proposes retaining the practice of masking the identity of 

participants when releasing offer and bid data. The possibility raised by a few 

commenters that some players may be able to surmise the identity of participants argues, 

if anything, for further protection, not for less. The Commission further proposes 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. 

ii. Tailored Requests for Information

(a) Preliminary Proposals in the ANOPR

231. The Commission proposed that state commissions may make reasonable requests 

for additional tailored information from the MMUs, acknowledging that information such 

as general analyses of the market and aggregated price data may assist state commissions 

in performing their regulatory functions. The Commission stated that these requests 

 

ability to expeditiously file for a rule change if negative impacts on the market were 

experienced, and the existing tariff language that masks the bid/offer data, adequately 

protected against the risk of collusion. 
Docket Nos. RM07-19-000 and AD07-7-000 - 126 - 

should be limited to information regarding general market trends and performance, and 

not encompass information designed to aid state enforcement or actions against 

individual companies. This restriction was proposed in light of the limited resources of 

MMUs and the fact that states have their own enforcement agencies which are more 

properly employed for such tasks. However, the Commission proposed that a state 

commission could, on a case-by-case basis, request that the Commission authorize the 

release of otherwise proscribed data. The Commission would then evaluate whether 

there was a compelling need for the requested information, and decide whether adequate 

protections could be fashioned for commercially sensitive material. 

(b) Comments on the ANOPR Proposals and Questions

232. There was substantial support for the Commission’s proposal to allow state 

commissions to make tailored requests for information, with the caveat that such requests 

should not be permitted to place too great a burden on the workload of the MMUs.223 

Several commenters suggested this problem could be solved by limiting the information 

provided by the MMU to that generated in the ordinary course of business.224 Other 

commenters objected to the restriction prohibiting the release of information designed for 

enforcement purposes, arguing that the states have little other means of access to the 

necessary information.225 A number of commenters cautioned that requests for 

 223 See, e.g., Reliant at 19; PJM Power Providers at 10. 

224 See, e.g., PJM Power Providers at 10; Exelon at 28. 

225 NARUC at 9; Ohio PUC at 19. 
Docket Nos. RM07-19-000 and AD07-7-000 - 127 - 

information must be accompanied by assurances of confidentiality.226 At least some 

RTOs and ISOs currently have provisions in their tariffs governing the release of 

confidential information;227 however, OMS asserts that such tariff provisions (at least 

with respect to Midwest ISO) are so restrictive as to effectively bar the release of needed 

information.228 Several commenters 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.229

(c) Commission Proposal

233. The Commission notes that entertaining tailored requests for information from 

state commissions subjects the MMU to the risk that it will be diverted from its core 

functions of monitoring the market and making rule and tariff recommendations to the 

RTO or ISO. Therefore, the decision as to whether to respond to such requests, assuming 

they otherwise fall within acceptable parameters, should be made by the MMU, in light 

of its budgetary and time limitations. 

234. The Commission continues to believe its proposed restriction on information 

designed for enforcement purposes is a reasonable one. Such requests would not only 

implicate serious confidentiality concerns, they could overwhelm the MMU’s workload, 

 226 Constellation at 19; Joint Consumer Advocates at 22; Midwest ISO at 30. 

227 See, e.g., Midwest ISO at 30; SPP at 11. 

228 OMS at 31. 

229 See, e.g., EEI at 51; FirstEnergy at 11; DC Energy at 8. 
Docket Nos. RM07-19-000 and AD07-7-000 - 128 - 

as they would likely involve more detailed investigations than would be required for 

general market information or for MMU referrals to the Commission. While states may 

not have the tools and expertise to monitor the market as effectively as can the MMUs, 

they do have access to resources to carry out enforcement functions. Furthermore, the 

costs of state enforcement should rightfully be borne by the states, not by the MMUs or 

RTOs and ISOs. Therefore, the Commission proposes that MMUs may entertain requests 

for information from state commissions, so long as such information pertains to general 

market trends and performance, is not designed to aid state enforcement or actions 

against individual companies,230 and the MMU can accommodate such requests within its 

budgetary and time constraints without jeopardizing its ability to perform its core tariffdefined functions. 

235. The Commission also believes that while confidentiality provisions serve a useful 

purpose, they should not be drafted in such a way as to impose unnecessary barriers to 

the dissemination of information. Therefore, the Commission proposes that RTOs and 

ISOs develop confidentiality provisions for their tariffs that will protect commercially 

sensitive material, but which will not be so restrictive as to permit the release of little if 

any information. 

236. The Commission also agrees that if requested information pertains to specific 

market participants, other than offer and bid data, that as a matter of fairness the named 

 230 However, if during the ordinary course of its activities an MMU were to 

discover evidence of wrongdoing that was within a state commission’s jurisdiction, it is 

expected that the MMU would report such information to the state commission. 
Docket Nos. RM07-19-000 and AD07-7-000 - 129 - 

market participant should be given notice and the opportunity to contest the information. 

Therefore, the Commission proposes that the RTOs and ISOs include such a provision in 

their tariffs. 

237. In the ANOPR, the Commission proposed permitting state commissions to petition 

the Commission on a case-by-case basis for information that does not fall within the 

proposed acceptable parameters. This safety valve should alleviate state concerns that 

they may be prevented from acquiring information for which they have a compelling 

need, while also ensuring that the Commission will be able to examine such requests in 

light both of state needs and the ability to fashion adequate confidentiality protections. 

Therefore, the Commission proposes that the RTOs and ISOs note the availability of this 

exception in their tariffs. 

iii. Commission Referrals

(a) Preliminary Proposals in the ANOPR

238. The Commission stated that MMUs should continue to respect the confidentiality 

of their referrals of suspected wrongdoing to the Commission, and not disclose such 

referrals to other entities, including state commissions. The Commission also expressed 

its intention not to disseminate information regarding its investigations, noting that the 

Commission’s rules require that such information be kept nonpublic unless the 

Commission authorizes, in any given case, that it be publicly disclosed.231 The 

 231 18 C.F.R § 1b.9 (2007). Other exceptions include cases where the information 

has been made a matter of public record in an adjudicatory proceeding, and where 

disclosure is required by the Freedom of Information Act, 5 U.S.C. § 552 et seq. (2006). 
Docket Nos. RM07-19-000 and AD07-7-000 - 130 - 

Commission noted, however, that it intended to continue the practice of Commission staff 

providing the MMUs with generic feedback regarding enforcement issues. 

(b) Comments on the ANOPR Proposals and Questions

239. Comments were received on both sides of this issue, with state representatives 

arguing for release of MMU referral information, for the results of Commission 

investigations, and for disclosure of the progress of Commission investigations.232 Other 

commenters acknowledged the legal and policy considerations noted by the Commission, 

and concurred in the need to maintain confidentiality.233 The California PUC, while 

stating that it understood the need for confidentiality, proposed that in the event 

wrongdoing is discovered that affects a state commission with appropriate jurisdiction, 

that such commission should be notified of the wrongdoing.234 Some commenters argued 

that state bodies have procedures in place to protect confidentiality, and so should not be 

barred from receiving such information from the MMUs and the Commission.235 

Constellation, however, cautions that these procedures may not protect disclosure from 

Freedom of Information Act (FOIA) requests or requests made under equivalent state 

statutes.236

 232 See, e.g., California PUC at 32; Ohio PUC at 19; OMS at 37-38; OPSI at 31-

32. 

233 See, e.g., Reliant at 19; Exelon at 29. 

234 California PUC at 32. 

235 See, e.g., New York PSC at 15; North Carolina Commission at 7; OPSI at 32. 

236 Constellation at 19. 
Docket Nos. RM07-19-000 and AD07-7-000 - 131 - 

(c) Commission Proposal

240. The Commission notes that the commenters that argued for the release of referral 

and investigative information to such bodies as state commissions did not generally 

address the substantial legal and policy arguments against such release, other than to note 

that some state bodies have confidentiality procedures (which may or may not withstand 

FOIA-type requests). As the Commission observed in the ANOPR, not only do 

Commission rules prohibit such release, but release could impede the willingness of 

market participants to self-report and otherwise cooperate in investigations, and could 

injure innocent persons who might be erroneously implicated or adversely affected by 

simply being associated with an investigation. Therefore, the Commission proposes 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. 

c. Pro Forma Tariff

i. Preliminary Proposals in the ANOPR

241. Finally, the Commission in the ANOPR stated our intent to include in this NOPR 

a proposed pro forma MMU section for RTO/ISO tariffs, which would contain 

standardized core provisions but also allow for regional variations. The Commission 

stated that it anticipates including in the pro forma MMU section protocols for the 

referral of tariff, rule and market manipulation violations to the Office of Enforcement, as 

well as protocols for the referral of perceived market design flaws and recommended 
Docket Nos. RM07-19-000 and AD07-7-000 - 132 - 

tariff changes to the Office of Energy Market Regulation. The Commission solicited 

comments on the structure and content of such a pro forma section. 

ii. Comments on the ANOPR Proposals and Questions

242. There was substantial support for a pro forma tariff section of core MMU 

provisions. However, a number of entities, such as the Midwest ISO, cautioned that a pro 

forma tariff would ignore regional variations, disregard stakeholder consensus and 

increase compliance burdens. Those arguing for a pro forma tariff supported the ANOPR 

proposal that each RTO or ISO be given the flexibility to propose individual provisions, 

in order to reflect regional variations. NYISO cautioned against the Commission 

attempting a pro forma mitigation provision. 

iii. Commission Proposal

243. The Commission had proposed in the ANOPR that a pro forma MMU tariff 

section would be limited to essential core MMU provisions, such as functions, oversight, 

tools and information sharing, thus freeing the RTOs and ISOs to propose regional 

variations. In light of the fact that in this NOPR we are proposing that many important 

aspects of the market monitoring relationship with the RTOs and ISOs be left to the 

discretion of the individual RTOs and ISOs, and in light of the fact that there may well be 

other regional variations which the RTOs and ISOs may wish to propose, the 

Commission believes a pro forma tariff section, which would necessarily have a large 

number of blank subsections, would be of limited value. 

244. For that reason, the Commission proposes that instead of requiring the RTOs and 

ISOs to follow the outlines of a pro forma MMU tariff section, that they conform their 
Docket Nos. RM07-19-000 and AD07-7-000 - 133 - 

tariff to the requirements that will be ultimately set forth in the rulemaking to be issued in 

this docket, including centralization of the MMU provisions in one section. The 

Commission also proposes that each RTO and ISO include in its tariff protocols for the 

referral of tariff, rule and market manipulation violations to the Office of Enforcement, 

revised as discussed above, and for the referral of perceived market design flaws and 

recommended tariff changes to the Office of Energy Market Regulation. 

D. Responsiveness of RTOs and ISOs to Stakeholders and Customers

245. In this section of the NOPR, the Commission proposes to establish new criteria 

intended to ensure that an RTO or ISO board is responsive to the RTO’s or ISO’s 

customers and other stakeholders. These criteria will include: (1) inclusiveness; (2) 

fairness in balancing diverse interests; (3) representation of minority positions; and (4) 

ongoing responsiveness. The Commission proposes 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 it is responsive to stakeholders and customers. In the 

compliance filing, the Commission encourages each RTO or ISO to evaluate what 

practices and procedures may best satisfy the responsiveness criteria. 

246. In the ANOPR, the Commission made a preliminary proposal to improve 

responsiveness of RTO and ISO boards of directors to customers and other stakeholders. 

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. We also sought comment on several issues focusing on whether 
Docket Nos. RM07-19-000 and AD07-7-000 - 134 - 

and how RTO and ISO responsiveness to stakeholders can be improved, including 

management practices and stakeholder participation in the budgeting process.

1. Background

247. In Order No. 888, the Commission encouraged but did not require the formation of 

ISOs, delineating eleven principles defining the operations and structure of a properly 

functioning ISO.237 Similarly, in Order No. 2000, the Commission encouraged utilities to 

join RTOs voluntarily and set out the characteristics that an RTO must possess and the 

minimum functions that it must perform.238 Embodied in Order Nos. 888 and 2000 is the 

requirement that the regional transmission entity be independent from market 

participants. 

248. Although it required independence, Order No. 2000 did not mandate detailed 

governance requirements for an RTO board of directors. 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 needs.239 Therefore, the Commission stated that it would review 

 237 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, at 31,730-32 

(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). 

238 Order No. 2000-A, FERC Stats. & Regs. ¶ 31,092 at 30,993. 

239 Id. at 31,073. The Commission noted that existing ISOs have varying forms of 
Docket Nos. RM07-19-000 and AD07-7-000 - 135 - 

governance proposals on a case-by-case basis.240 The Commission also provided 

guidance based on existing governance arrangements, emphasizing the importance of 

stakeholder input regarding both RTO formation and ongoing operations. The 

Commission stated that stakeholder committees should have balanced representation on 

such committees so that no one stakeholder class dominates the committee’s 

recommendations. The Commission added that, in the case of a non-stakeholder board, it 

is important that this board not become isolated.241 For these reasons, the Commission 

explained that both formal and informal mechanisms should be used to ensure that 

stakeholders can convey their concerns to the non-stakeholder board. This standard is no 

different for currently-operating ISOs, as the ISO principle of independence requires fair 

representation of all types of users of the system to ensure that the ISO formulates 

policies, operates the system, and resolves disputes in a fair and non-discriminatory 

manner.

242

2. Preliminary Proposals in the ANOPR

249. In the ANOPR, the Commission made the preliminary conclusion that 

representatives of RTO and ISO customers and other stakeholders should have some 

 

governance. Some used a two-tier form of governance with a non-stakeholder board and 

advisory committees of stakeholders while one ISO in particular, CAISO, employed a 

decision-making board consisting of both stakeholders and non-stakeholders. Id.

240 Id. at 31,073-74. 

241 Id.

242 Order No. 888, FERC Stats. & Regs. ¶ 31,036 at 31,730-31. 
Docket Nos. RM07-19-000 and AD07-7-000 - 136 - 

form of effective direct access to the RTO or ISO board of directors.243 The Commission 

asked whether each RTO and ISO should be required to develop and implement a means 

to ensure that customers and other stakeholders have such access.244 The Commission 

made the preliminary proposal that either of two mechanisms, a hybrid board or a board 

advisory committee, could accomplish the goal of enhancing customer and other 

stakeholder access to the board.245 

250. 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. The Commission 

stated that a hybrid board would directly expose the board to stakeholders’ concerns and 

that it believed that it should be possible to structure a hybrid board without sacrificing 

overall board independence.246 

251. Alternatively, the Commission suggested that a board advisory committee, 

comprised of senior executives of the various stakeholder groups, could serve as an 

expert panel that would inform the board of stakeholder views. The board advisory 

committee would have no voting authority on board decisions, but could make 

recommendations directly to the board on matters before the board and on matters it 

 243 ANOPR, FERC Stats. & Regs. ¶ 32,617 at P 148. 

244 Id. P 149. 

245 Id. P 151, 153. 

246 The Commission also noted that certain restrictions may be necessary for the 

hybrid board proposal to ensure that stakeholder members do not inappropriately serve 

their own interests. Id. P 152. 
Docket Nos. RM07-19-000 and AD07-7-000 - 137 - 

believes the board should address. The Commission stated that it envisioned such a 

committee to include members selected to represent a reasonable range of diverse 

interests.247

252. Based on these two models of improving RTO and ISO responsiveness, the 

Commission sought comments on the following questions: 

• How should any hybrid board be structured? What is an appropriate limit on the 

percentage of non-independent board members? If a variety of customer views 

are to be represented, what implications does this have for the size of the board? 

• What, if any, rules and restrictions should be placed on the stakeholder board 

members of a hybrid board? 

• Can the reform proposed here be met through other means such as increased 

direct board interaction with customers and other stakeholders, e.g., through open 

board meetings or through required attendance of board members at major 

stakeholder meetings of the RTO? 

• Are there measures – such as customer satisfaction measures, cost oversight 

benchmarks, or stakeholder participation measures – that RTOs and ISOs should 

use to assess the success of the mechanism for improving responsiveness? 

253. In the ANOPR, the Commission also requested comment on whether any reforms 

are necessary to increase management responsiveness to stakeholders. Among specific 

topics, the Commission requested comment on whether it should encourage or require 

 247 Id. P 153-54.
Docket Nos. RM07-19-000 and AD07-7-000 - 138 - 

RTOs and ISOs to publish a strategic plan that includes plans for ensuring responsiveness 

to customers and stakeholders, set performance criteria for executive managers based in 

part on responsiveness to stakeholders, and relate executive compensation to a measure 

of responsiveness to stakeholders. 

3. Comments on the ANOPR Proposals and Questions

254. The Commission received numerous responses from commenters regarding the 

questions posed in the ANOPR. A majority agrees with the Commission’s conclusion 

that more effective direct access to RTO and ISO boards is needed. They do not agree, 

however, on the mechanism to achieve that goal. Some commenters favor the hybrid 

board, but many express concern with this approach, preferring the board advisory 

committee. Several commenters support using both a hybrid board and a board advisory 

committee,248 noting that the two approaches are not mutually exclusive.249 Several 

commenters discussed changes in RTO and ISO management practices to improve the 

responsiveness. 

a. Comments on the Hybrid Board Approach

255. Some commenters support the proposal for a hybrid board approach, stating that a 

hybrid board would improve RTO responsiveness and allow stakeholder access to an 

RTO and ISO board.250 While they believe that such a board would be a good 

 248 E.g., AEP at 7; Ameren at 44; APPA at 88. SMUD states that the Commission 

should explore both approaches. SMUD at 20-22. 

249 NYISO suggested a shared governance model as an alternative to the hybrid 

board and the board advisory committee models proposed in the ANOPR. NYISO at 6. 

250 E.g., California Munis at 15; Silicon Valley Power at 15; Connecticut and 
Docket Nos. RM07-19-000 and AD07-7-000 - 139 - 

mechanism to achieve the Commission’s goal, they also state that some requirements on 

how such a board should be structured are necessary. For example, California Munis 

state that stakeholder board members should not form a majority of an RTO’s or ISO’s 

board under a hybrid board form of governance.251 SMUD states that a hybrid board 

should include diverse representation and must be properly balanced so that no single 

interest is unduly influential.252 TAPS recommends that within a hybrid board, 

independent directors should hold a majority of board seats to prevent capture by 

stakeholders.253 Further, before implementing the hybrid board approach, the 

Connecticut and Massachusetts Municipals recommend that the Commission provide 

clarity regarding any possible conflict of interest concerns among stakeholder 

directors.254 

256. Industrial Consumers recommend that the Commission require each RTO or ISO 

to establish a hybrid board, but only if representatives of loads (large and small 

customers) are assured equal representation with supply-side interests. They note that 

Electric Reliability Council of Texas (ERCOT) already has a hybrid board.255 Industrial 

 

Massachusetts Municipals at 16; Wisconsin Industrial at 11; TAPS at 34; Industrial 

Consumers at 40. 

251 California Munis at 15. 

252 SMUD at 21. 

253 TAPS at 34. 

254 Connecticut and Massachusetts Municipals at 17. 

255 Industrial Consumers note that the ERCOT hybrid board is composed of the 

following: (1) five unaffiliated independent board members (two serve as chair and vice 
Docket Nos. RM07-19-000 and AD07-7-000 - 140 - 

Consumers propose that non-independent stakeholder members should represent less than 

half of the total ISO and RTO board (unlike in ERCOT). They add that an equal number 

of stakeholders should represent supply-side and demand-side (consumer) interests.256 

To that end, Industrial Consumers state that it may be necessary to require some form of 

rotation among stakeholder groups. Finally, they note that all existing ISO and RTO 

boards already have a “hybrid” feature because some members are retired utility 

executives, and they urge the Commission to consider counting such members as 

stakeholders in hybrid boards. 

257. Wisconsin Industrial also recommends a hybrid board structure, with the condition 

that end-use customer and supplier representation be equal. Wisconsin Industrial 

believes that a hybrid board has an advantage in that a variety of stakeholder interests can 

be objectively and directly represented without first being filtered through RTO and ISO 

management.257 

258. Further, several of the commenters that support the hybrid board oppose the 

advisory board committee, noting that such a committee would not provide for direct 

 

chair); (2) independent power marketers; (3) industrial consumers; (4) commercial 

consumers; (5) independent retail electric providers; (6) electric cooperatives; (7) 

residential consumers; (8) investor-owned utilities; (9) independent generators; and (10) 

municipally-owned utilities. Industrial Consumers at 41. 

256 For example, a ten-member board would have four stakeholder members: two 

representing suppliers and two representing consumers. Id.

257 Wisconsin Industrial at 11. 
Docket Nos. RM07-19-000 and AD07-7-000 - 141 - 

discussion and information exchange, and that its advice could be ignored by board 

members.258 Others note the disadvantages of an advisory board committee.259

259. Many commenters, however, do not support the hybrid board approach, 

emphasizing that a hybrid board can, among other things, jeopardize the independence of 

an RTO or ISO board.260 They contend that RTO and ISO independence must be 

preserved because it gives participants in organized wholesale markets the confidence 

that: (1) the markets are being administered fairly; (2) proprietary and critical 

infrastructure information is being protected; and (3) customers will ultimately receive 

the benefits of competition. 

260. Many commenters argue that stakeholder representation on a hybrid board would 

conflict with stakeholders’ fiduciary responsibility to their employers, making it difficult 

for the stakeholder member to be impartial when the goal of that member’s organization 

is to maximize its company’s profits. Therefore, they note that it is unrealistic to expect 

 258 E.g., TAPS at 40-42. 

259 For example, Indianapolis P&L notes that, while the Midwest ISO advisory 

committee provides some value, it faces challenges in its communication with the board 

of directors because management views are sometimes at odds with stakeholder views, 

the time for the advisory committee to consult with the board on technically complex 

issues is limited, and competing messages from committee members dilute and muddle 

the message. Indianapolis P&L at 6-7. 

260 E.g., California PUC at 34-35; DC Energy at 9; Comverge at 12; Dominion 

Resources at 10; Duke Energy at 29; Dynegy at 7; FirstEnergy at 12; Industrial Coalitions 

at 27; ITC at 5-13; Joint Consumer Advocates at 24; North Carolina Commission at 8; 

OMS at 42; NARUC at 12; Old Dominion at 31; Pepco at 22; The Alliance at 19; Xcel at 

27. 
Docket Nos. RM07-19-000 and AD07-7-000 - 142 - 

stakeholder board members to refrain from acting in the best interests of the entity with 

which they are affiliated. 

261. Some commenters also question whether a hybrid board can ensure fair 

representation, arguing that smaller companies are less likely to have the resources 

necessary to participate in such a board,261 thus not all sectors of the market would be 

fairly represented, resulting in the potential for undue influence. 

262. To address those concerns for undue influence, commenters have suggested that 

the selection of non-independent board members should require a supermajority vote. 

APPA recommends that RTO and ISO stakeholder directors be elected by a 

supermajority of stakeholder sectors, contending that stakeholder representatives should 

be balanced between generation and load interests.262 APPA further expands on its 

proposal by stating that using a supermajority election process will “ensure that wellrespected and knowledgeable members of the stakeholder community serve in this 

capacity.”263 TAPS suggests that a supermajority vote requirement for selection of 

stakeholder board members would go a long way to mitigate concerns that the 

stakeholder board members would use their position inappropriately to advance their 

parochial interests.264

 261 E.g., Comverge at 12; Industrial Coalitions at 25-28; The Alliance at 19-20. 

262 APPA at 13. 

263 Id. at 93. 

264 TAPS at 45. Both APPA and TAPS reference a similar recommendation from 

a Wisconsin Public Power Inc (WPPI) white paper, contained as Attachment A to the 

TAPS comments. WPPI suggests that “selection of the interested [non-independent] 
Docket Nos. RM07-19-000 and AD07-7-000 - 143 - 

263. Further, some commenters contend that a hybrid board composed of both 

independent and stakeholder members could complicate and impede effective board 

decision-making because of the effort of non-independent stakeholders to serve their own 

interests.265 They note that a hybrid board is far more likely to be unwieldy and 

ineffective because of the need to represent so many different market interests. Several 

commenters also argue that the Commission does not have the legal authority to dictate 

the composition of the board of a Commission-regulated entity.266 

b. Comments on the Board Advisory Committee Approach

264. Many commenters indicate that having a board advisory committee is the 

preferable approach to achieving the Commission’s goal of improving responsiveness of 

RTOs and ISOs.267 They state that a board advisory committee with a wide range of 

stakeholder interests that has direct access to the board of directors would increase RTO 

and ISO responsiveness and be the most effective way to balance the interests of 

stakeholders 

 

board members should require supermajority voting approval” and that “an election of an 

interested board member should require an affirmative vote of 67 [percent] of all 

sectors.” Id. at 70. 

265 E.g., Alcoa at 28; DC Energy at 10; California PUC at 35. 

266 See, e.g., California PUC at 35 (citing Cal. Indep. Sys. Operator Corp. v.

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

267 E.g., California PUC at 36; Comverge at 12; Suez at 9; Old Dominion at 31; 

OPSI at 42; Joint Consumer Advocates at 24; North Carolina Commission at 9; NARUC 

at 12; Pepco at 22-23; Xcel at 27-28. 
Docket Nos. RM07-19-000 and AD07-7-000 - 144 - 

265. Several commenters state that a board advisory committee would be a good 

starting point for improving communications between the board and stakeholders. For 

example, North Carolina Electric Membership believes that a board advisory committee 

would allow stakeholders to provide and receive strategic insight to the boards.268 In 

addition to such a committee, it notes the need for more opportunities for communication 

between the board and the stakeholders. Such communication can be achieved by board 

member attendance at major stakeholder meetings and by board solicitation of 

stakeholder position papers on relevant issues.269 A few of the commenters also note that 

they support open RTO and ISO board meetings.270

266. Some commenters suggest guidelines on how a board advisory committee should 

be structured and how it should function. For example, OPSI states that the board 

advisory committee: (1) must have authority to make recommendations directly to the 

board on matters before the board and on matters it believes the board should address; (2) 

 268 North Carolina Electric Membership at 4. 

269 For example, North Carolina Electric Membership suggests “town hall” 

sessions for members where board attendance is required on topics derived by the liaison 

committee (i.e., board advisory committee). It also notes that requiring the board to 

explain the basis for its decision on particular issues in writing could improve 

communication and add transparency to the process. North Carolina Electric 

Membership at 5. 

270 For example, the OMS believes that an open board meeting would allow 

stakeholders to assess the nature and quality of the information being provided to the 

board, whether the board has adequately understood and considered stakeholder issues 

and concerns, and whether the board has made a fair and balanced decision. OMS at 43. 

In contrast, SMUD does not support open board meetings, but suggests that a better 

alternative may be for boards to hold technical sessions with stakeholders for information 

gathering before board meetings take place. SMUD at 22. 
Docket Nos. RM07-19-000 and AD07-7-000 - 145 - 

must be required to allow for the communication of minority views to the board; and (3) 

should have membership limited to a reasonable number of individuals.271 OPSI and 

NARUC recommend that state commissions and state consumer advocates be entitled to 

representation on the board advisory committee.272 North Carolina Commission proposes 

that the board advisory committee should be given the right to suggest nominees to board 

positions and that the RTO and ISO board could be required to respond in writing to 

proposals submitted by the advisory committee. 

267. Additionally, LPPC states that a board advisory committee must be closely 

involved in RTO and ISO board discussions, must represent a broader range of 

stakeholder interests, and should supplement, not replace, existing stakeholder 

representation on operating technical committees.273

c. Comments on the Need to Increase Management Responsiveness

268. APPA, TAPS, and the Connecticut and Massachusetts Municipals recommend that 

RTO and ISO mission statements and/or charters clearly define consumer-oriented goals. 

They recommend that these documents be modified to require the RTO or ISO to provide 

“reliable service at the lowest possible reasonable rates,"274 or similar wording to that 

 271 OPSI at 43. 

272 Id. See also NARUC at 12. 

273 LPPC at 17. See also Industrial Consumers at 41 (suggesting that a board 

advisory committee should be balanced, be charged with electing the board members, and 

be responsible for approving any changes in the bylaws). 

274 TAPS at 33. 
Docket Nos. RM07-19-000 and AD07-7-000 - 146 - 

effect. APPA would include an explicit obligation that the RTO or ISO work to reduce 

power costs to consumers. 

269. Several commenters also addressed the topic of performance criteria for executive 

managers’ responsiveness to stakeholder and consumer interests. For example, DC 

Energy supports the Commission requiring each RTO and ISO to take steps to ensure 

management responsiveness, such as stakeholder input on public strategic plans, periodic 

measurement of customer satisfaction, and RTO- or ISO-developed performance criteria 

for executive managers with a focus on reliability and market efficiency criteria.275 North 

Carolina Commission suggests the Commission focus on measures of responsiveness 

such as timely responses to customer or stakeholder requests.276 The North Carolina 

Commission also suggests that the Commission should focus on behavior-based measures 

to improve RTO and ISO effectiveness, such as whether the RTO and ISO has clear staff 

assignments; whether it has contact information easily available on its web site; the 

length of time for a stakeholder to secure an answer to a question; how long it takes a 

market participant to receive a correction of a billing or settlement error; and how often 

transmission service or interconnection studies are delayed. LPPC suggest four areas that 

should be covered in performance measures include accomplishment of the mission, 

ability to meet budget projections, compliance with NERC standards, and measured 

 275 DC Energy at 10. 

276 North Carolina Commission at 9-10. 
Docket Nos. RM07-19-000 and AD07-7-000 - 147 - 

stakeholder satisfaction.277 CAISO supports Commission adoption of performance 

criteria for executive managers, stating that it has already implemented most of the 

ANOPR proposals, including an incentive compensation program for all employees that 

contains specific goals for improving stakeholder processes and timely response to 

stakeholder inquiries.278

d. Comments on Regional Differences

270. In addition to the two approaches described in the ANOPR, several commenters 

suggest that the Commission should allow for regional differences, and not administer a 

one-size-fits-all approach.279 Instead, given the differences among RTOs and ISOs in 

governance and stakeholder needs, the Commission should require RTOs and ISOs to 

work with customers and other stakeholders to create programs specific to each regional 

entity. For example, EEI notes that it is important that each RTO and ISO have the 

flexibility to adopt the means of direct stakeholder access that is most effective for that 

particular RTO or ISO.280 NARUC also notes that stakeholder representation in RTO and 

 277 LPPC at 19. 

278 CAISO at 14. 

279 E.g., Allegheny at 7; ISO-NE at 31-33; EPSA at 50; Pepco at 23; SPP at 12-13; 

National Grid at 17-20; EEI at 57-61. 

280 EEI recommends that the Commission issue a policy statement declaring that 

stakeholders should have effective direct access to RTO and ISO boards and executive 

management. It also argues that “the Commission should not take any action that would 

require the basic structure of RTOs and ISOs and their underlying governing contracts, 

such as the transmission owners’ agreement, to be reopened without the consent of the 

parties involved.” EEI at 59. 
Docket Nos. RM07-19-000 and AD07-7-000 - 148 - 

ISO processes is not uniform across all sectors; therefore, it urges the Commission to 

review RTO and ISO processes to ensure equivalent treatment of all stakeholders.281

271. OPSI recommends that the Commission not impose particular mandates, but 

should express its intention to hold RTO and ISO boards accountable, and leave it to the 

boards to develop appropriate ways to ensure such responsiveness. OPSI also urges the 

Commission to establish an annual opportunity for interested parties to submit an 

assessment of the RTO’s or ISO’s performance in the preceding year to the 

Commission.282

4. The Need for Commission Action

272. In Order No. 2000, the Commission determined that independence is a required 

characteristic necessary for an RTO to prevent any undue discrimination and to bring 

benefits to market participants. In that respect, the Commission stated that an RTO’s 

decision-making process must be independent in both reality and perception.283 The 

Commission did not believe that detailed guidance regarding governance structure was 

necessary given the early stage of RTO formation and the varying structures of 

governance among regional entities. Instead, the Commission required RTOs to have an 

“open architecture” so that the organization and its members would have the necessary 

flexibility to improve the structure, geographic scope, market scope, and operations of the 

organization. Although the Commission required that proposed changes continue to 

 281 NARUC at 13. 

282 OPSI at 45. 

283 Order No. 2000, FERC Stats. & Regs. ¶ 31,089 at 31,061. 
Docket Nos. RM07-19-000 and AD07-7-000 - 149 - 

satisfy RTO minimum characteristics and functions,284 open architecture allowed the 

original RTO design to evolve to reflect changes in member needs. 

273. Since Order No. 2000 was issued, RTOs and ISOs have evolved. Given the size 

and complexity of RTOs and ISOs today, it is not surprising that tension has arisen 

between the goals of independent decision-making and responsiveness to stakeholders, as 

an RTO or ISO cannot satisfy every group on every issue. The RTO and ISO 

management and boards of directors face increasing difficulty (as well as increasing 

responsibility) in understanding the impact of their decisions on the various stakeholder 

classes. Attempting to accommodate stakeholders’ needs on each issue has been a 

difficult task borne by the boards and other employees of the RTOs and ISOs. 

274. Creating a mechanism and process to enable the board to be responsive to the 

needs of stakeholders is critical to an independent governance structure. Moreover, it is 

necessary for customers and other stakeholders to have confidence in the decisions that 

come out of RTO and ISO processes. Similarly, management responsiveness to 

customers and stakeholders plays an important role in implementing the RTO and ISO 

policies and achieving its objectives in a manner that customers and other stakeholders 

perceive to be fair, balanced, and effective. The Commission proposes a set of criteria, 

discussed below, for assessing the mechanism or process by which an RTO or ISO 

achieves board responsiveness to its members and customers. 

 284 Id. at 31,170. 
Docket Nos. RM07-19-000 and AD07-7-000 - 150 - 

5. Proposed Reform

275. The Commission proposes to require each RTO and ISO to demonstrate in a 

compliance filing that it is achieving RTO and ISO responsiveness, and we propose to 

assess the filed practices or procedures for achieving RTO and ISO board responsiveness 

using the following criteria: (1) inclusiveness; (2) fairness in balancing diverse interests; 

(3) representation of minority positions; and (4) ongoing responsiveness. We believe 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 considered. We also 

believe that any RTO or ISO practices or procedures that satisfy these criteria will ensure 

that RTO and ISO boards and management are reasonably responsive to the needs of 

RTO and ISO members and customers. 

276. Accordingly, an RTO or ISO must comply with this proposed requirement by 

submitting a filing that proposes changes to its responsiveness practices and procedures 

to comply with the proposed requirement or that demonstrates its practices and 

procedures already satisfy the requirement for responsiveness. This filing would be 

submitted within six months of the date the final rule is published in the Federal Register. 

The Commission will assess whether each filing satisfies the proposed requirement and 

issue additional orders as necessary. 

277. The Commission agrees with commenters that a one-size-fits-all approach may not 

be beneficial given the varying structure and needs of each regional entity. Therefore, 

instead of prescribing a specific mechanism for all RTOs and ISOs, the Commission 

proposes to take a flexible approach. Various mechanisms may satisfy the proposed 
Docket Nos. RM07-19-000 and AD07-7-000 - 151 - 

criteria. We encourage each RTO or ISO to develop a mechanism that best suits its own 

governance structure and stakeholder needs. The Commission presented two options for 

consideration, the board advisory committee and the hybrid board.285 While we view the 

board advisory committee as a particularly strong mechanism for enhancing 

responsiveness, the Commission expects each RTO or ISO and its stakeholders to 

develop the mechanism that best suits its needs. 

278. We seek comment, however, on whether RTOs and ISOs should be encouraged, or 

required, to base their process for selecting non-independent members of the board or of 

a board advisory committee on a supermajority vote of eligible stakeholders. 

279. We propose to require each RTO and ISO, in its compliance filing, to demonstrate 

that it has satisfied the following criteria: 

• Inclusiveness — The 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 or ISO board. 

• Fairness in Balancing Diverse Interests — The 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. 

 285 Any RTO or ISO that chooses to propose a hybrid board structure must ensure 

that the non-independent board members constitute less than a majority of the board and 

must limit the eligibility to be a non-independent board member to market participants in 

that RTO or ISO market. 
Docket Nos. RM07-19-000 and AD07-7-000 - 152 - 

• Representation of Minority Positions — The 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 board at the same time as 

majority positions. 

• Ongoing Responsiveness – The practices and procedures must provide for 

stakeholder input into RTO or ISO decisions as well as mechanisms to provide 

feedback to stakeholders to ensure that information exchange and communication 

continue over time. 

280. The Commission proposes to require that each RTO and ISO post on its web site a 

mission statement or charter for its organization. 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. 

281. We also encourage 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. Such plans should give appropriate 

consideration to important service delivery goals such as reducing congestion costs, 

timely response to transmission service requests, prompt resolution of statements, billing, 

and disputes, and other customer service measures of performance.286

 286 The Commission understands that RTO and ISO executive management 

compensation plans may already be based on various measures of performance. If these 

already adequately take account of customer responsiveness, the RTO or ISO may report 

this in its compliance filing. 
Docket Nos. RM07-19-000 and AD07-7-000 - 153 - 

V. Applicability of the Proposed Rule and Compliance Procedures

282. The Commission has a responsibility under FPA sections 205 and 206 to ensure 

that the rates, charges, classifications, and service of public utilities (and any rule, 

regulation, practice, or contract affecting any of these) are just and reasonable and not 

unduly discriminatory, and to remedy undue discrimination in the provision of such 

services. Our action in this NOPR proposes to fulfill those responsibilities by proposing 

reforms to improve the operation of organized wholesale markets. It is necessary to 

remedy any problems in wholesale markets to ensure that rates and services in RTO and 

ISO markets remain just and reasonable and not unduly discriminatory. 

283. The Commission proposes to apply the final rule in this proceeding to all RTOs 

and ISOs by requiring them to demonstrate compliance with the proposed requirements 

discussed in each section of the NOPR: (1) demand response; (2) long-term power 

contracting; (3) market monitoring; and (4) RTO and ISO responsiveness. The 

Commission proposes to require each RTO and ISO to report to the Commission, on the 

deadlines specified below or six months following its certification as an RTO or 

commencement of operations as an ISO, that describes whether the entity is already in 

compliance with the requirements of the final rule, or describing its plans to attain 

compliance, including a timeline with intermediate deadlines and appropriate proposed 

tariff and market rule revisions. The Commission will assess whether each filing satisfies 

the proposed requirements and issue further orders for each RTO and ISO. 

284. For the proposed requirements under demand response, the filing addressing 

ancillary services and deviation charges, and the filing for ARCs and shortage pricing 
Docket Nos. RM07-19-000 and AD07-7-000 - 154 - 

must be submitted within six months of the date the final rule is published in the Federal 

Register. 

285. The filing to comply with the proposed requirements regarding long-term 

contracts, MMU reforms and RTO responsiveness must be submitted within six months 

of the date the final rule is published in the Federal Register. 

VI. Information Collection Statement

286. The Office of Management and Budget (OMB) regulations require approval of 

certain information collection requirements imposed by agency rules.287 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 NOPR amends the 

Commission’s regulations to improve the operation of organized wholesale electric 

power markets. The objective of this proposed rule is to improve market design and 

competition in organized markets. Through this rule the Commission hopes to provide 

remedies by ensuring (1) that new criteria are established so RTOs and ISOs are 

responsive to their customers and stakeholders; (2) improve 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) transparency in the 

marketplace by requiring RTOs and ISOs to dedicate portions of their web sites so 

 287 5 C.F.R. § 1320.11 (2007). 
Docket Nos. RM07-19-000 and AD07-7-000 - 155 - 

market participants can avail themselves of information concerning offers to buy or sell 

power on a long-term basis; and (4) require RTOs and ISOs to institute certain reforms in 

the demand response programs to remove several disincentives and barriers to provide for 

more efficient operation of markets while at the same time encouraging 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. 

287. The Commission is submitting these reporting requirements to OMB for its review 

and approval under section 3507(d) of the Paperwork Reduction Act.288 Comments are 

solicited 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. 

Burden Estimate: The Public Reporting burden for the requirements contained in the 

NOPR is as follows: 

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 

 288 44 U.S.C. § 3507(d) (2000). 
Docket Nos. RM07-19-000 and AD07-7-000 - 156 - 

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 Commission seeks comments on the costs to comply 

with these requirements. It has projected the average annualized cost 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) 

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 

*differences in RTO/ISO staff hourly rates are to differentiate between administrative 

support staff and senior staff. 

Total cost estimates: $3,690,713. 

 

Title: FERC-516 “Electric Rate Schedule Filings” 
Docket Nos. RM07-19-000 and AD07-7-000 - 157 - 

Action: Proposed Collections 

OMB Control No: 1902-0096 

Respondents: Business or other for profit, and/or not for profit institutions. 

Frequency of Responses: One time to initially comply with the rule, and then on 

occasion as needed to revise or modify. 

Necessity of the Information: This proposed rule, if adopted, would further 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. 

Internal review: The Commission has reviewed the requirements pertaining to 

transmission organizations with organized electricity markets and determined the 

proposed requirements are necessary to meet the provisions of the Federal Power Act. 

288. These requirements conform to the Commission’s plan for efficient information 

collection, communication and management within the energy industry. The 

Commission has assured itself, by means of internal review, that there is specific, 

objective support for the burden estimates associated with the information requirements. 

289. Interested persons may obtain information on the reporting requirements by 

contacting: Federal Energy Regulatory Commission, 888 First Street, N.E., Washington, 
Docket Nos. RM07-19-000 and AD07-7-000 - 158 - 

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 

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>]. 

VII. Environmental Analysis

290. 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.289 The Commission concludes that neither an Environmental 

Assessment nor an Environmental Impact statement is required for this NOPR 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.290

 289 Regulations Implementing the National Environmental Policy Act, Order No. 

486, FERC Stats. & Regs. ¶ 30,783 (1987). 

290 18 C.F.R. § 380.4(a) (15) (2007). 
Docket Nos. RM07-19-000 and AD07-7-000 - 159 - 

VIII. Regulatory Flexibility Act Certification

291. The Regulatory Flexibility Act of 1980 (RFA)291 generally requires a description 

and analysis of rules that will have significant economic impact on a substantial number 

of small entities. Most, if not all, of the transmission organizations to which the 

requirements of this rule would apply do not fall within the definition of small entities.292 

Those entities to be impacted directly by this rule include the following: 

• California Independent Service Operator Corp. (CAISO) is a nonprofit organization 

comprised of more than 90 electric transmission companies and generators operating in 

its markets and serving more than 30 million customers. 

• New York Independent System Operator, Inc. (NYISO) is a nonprofit organization that 

oversees wholesale electricity markets serving 19.2 million customers. NYISO manages 

a 10,775-mile network of high-voltage lines. 

• PJM Interconnection, L.L.C. (PJM) is comprised of more than 450 members including 

power generators, transmission owners, electricity distributors, power marketers and 

large industrial customers and serving 13 states and the District of Columbia. 

• Southwest Power Pool, Inc. (SPP) is comprised of 50 members serving 4.5 million 

customers in 8 states and has 52,301 miles of transmission lines. 

• Midwest Independent Transmission System Operator, Inc. (Midwest ISO) is a nonprofit organization with over 131,000 megawatts of installed generation. Midwest ISO 

has 93,600 miles of transmission lines and serves 15 states and one Canadian province. 

 291 5 U.S.C. § 601-12 (2000). 

292 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 (2000). 

The Small Business Size Standards component of the North American Industry 

Classification system defines a small utility as one that, including its affiliates is 

primarily engaged in the generation, transmission, or distribution of electric energy for 

sale, and whose total electric output for the preceding fiscal years did not exceed 4 MWh. 

13 C.F.R. § 121.202 (Sector 22, Utilities, North American Industry Classification 

System, NAICS) (2004). 
Docket Nos. RM07-19-000 and AD07-7-000 - 160 - 

• ISO New England Inc. (ISO-NE) is a regional transmission organization serving 6 

states in New England. The system is comprised of more than 8,000 miles of high 

voltage transmission lines and several hundred generating facilities of which more than 

350 are under ISO-NE’s direct control. 

Therefore, the Commission certifies that this rule will not have a significant economic 

impact on a substantial number of small entities. Accordingly, no regulatory flexibility 

analysis is required. 

IX. Comment Procedures

292. The Commission invites interested persons to submit comments on the matters and 

issues proposed in this notice to be adopted, including any related matters or alternative 

proposals that commenters may wish to discuss. Comments are due [insert date that is 

45 days from publication in the FEDERAL REGISTER]. Comments must refer to 

Docket Nos. AD07-7-000 and RM07-19-000, and must include the commenter's name, 

the organization they represent, if applicable, and their address in their comments. 

293. The Commission encourages comments to be filed electronically via the eFiling 

link on the Commission's web site at http://www.ferc.gov. The Commission accepts 

most standard word processing formats. Documents created electronically using word 

processing software should be filed in native applications or print-to-PDF format and not 

in a scanned format. Commenters filing electronically do not need to make a paper 

filing. 
Docket Nos. RM07-19-000 and AD07-7-000 - 161 - 

294. Commenters that are not able to file comments electronically must send an 

original and 14 copies of their comments to: Federal Energy Regulatory Commission, 

Secretary of the Commission, 888 First Street, N.E., Washington, DC 20426. 

295. All comments will be placed in the Commission's public files and may be viewed, 

printed, or downloaded remotely as described in the Document Availability section 

below. Commenters on this proposal are not required to serve copies of their comments 

on other commenters. 

X. Document Availability

296. 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. 

297. 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. 

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

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

or email at ferconlinesupport@ferc.gov, or the Public Reference Room at (202) 502-
Docket Nos. RM07-19-000 and AD07-7-000 - 162 - 

8371, TTY (202) 502-8659. E-mail the Public Reference Room at 

public.referenceroom@ferc.gov. 

List of subjects in 18 CFR Part 35 

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

By direction of the Commission. Commissioner Kelly concurring in part and dissenting 

in part with a separate statement attached. 

 Commissioner Wellinghoff concurring with a separate 

statement attached. 

 

 

 Nathaniel J. Davis, Sr., 

Deputy Secretary. 

 
Docket Nos. RM07-19-000 and AD07-7-000 - 163 - 

 In consideration of the foregoing, the Commission proposes to amend, 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), and (b)(7). 

(b) Add a 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 (MMU) means the person or entity responsible for 
Docket Nos. RM07-19-000 and AD07-7-000 - 164 - 

carrying out the market monitoring functions which the Commission has ordered 

Commission-approved ISOs and RTOs to perform. 

 * * * * * 

(g) Tariffs and operations of Commission-approved ISOs and RTOs. 

(1) Demand response and pricing. 

(i) Ancillary services provided by demand response resources. (A) Every 

Commission-approved ISO and RTO that operates organized markets based on 

competitive bidding for energy imbalance, spinning reserves, supplemental reserves, 

reactive power and voltage control, and regulation and frequency response ancillary 

services (or its functional equivalent in the Commission-approved ISO’s or RTO’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 ISO’s or RTO’s bidding rules at or below the market-clearing 

price, unless the laws or regulations of the relevant retail regulatory authority do not 

permit a retail customer to participate. 

(B) The Commission-approved ISO or RTO 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 
Docket Nos. RM07-19-000 and AD07-7-000 - 165 - 

(3) A maximum amount of electric energy that the demand response resource 

may be required to provide either daily or weekly. 

(ii) Removal of deviation charges. A Commission-approved ISO or RTO with 

a tariff that contains a day-ahead 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 realtime market during a real-time market period for which the Commission-approved ISO or 

RTO declares an operating reserve shortage or makes a generic request to reduce load to 

avoid an operating reserve shortage. 

(iii) Aggregation of retail customers. Commission-approved ISOs or RTOs 

must permit a qualified aggregator of retail customers to bid a demand response on behalf 

of retail customers directly into the Commission-approved ISO’s or RTO’s organized 

markets, unless the laws and regulations of the relevant electric retail regulatory authority 

do not permit a retail customer to participate. 

(iv) Price formation during periods of operating reserve shortage. (A) 

Commission-approved ISOs and RTOs must modify their 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 ISO or RTO may phase in this modification of its 

market rules. 

(2) Long-term power contracting in organized markets. A Commissionapproved ISO or RTO must provide a portion of its web site for market participants to 
Docket Nos. RM07-19-000 and AD07-7-000 - 166 - 

post offers to buy or sell power on a long-term basis. 

(3) Market monitoring policies. (i) Commission-approved ISOs and RTOs 

must modify their tariff provisions governing their Market Monitoring Units to reflect the 

directives provided in Order No. [insert order number], including the following: 

(A) Commission-approved ISOs and RTOs must include in their tariffs a 

provision to provide their Market Monitoring Units access to Commission-approved ISO 

and RTO market data, resources and personnel to enable the Market Monitoring Unit to 

carry out their functions. 

(B) The tariff provision must provide the Market Monitoring Unit complete 

access to the Commission-approved ISO’s and RTOs’ database 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 ISO’s and RTO’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 ISO 

or RTO board of directors, with its management members removed, or to an independent 

committee of the Commission-approved ISO or RTO board of directors. A Commissionapproved ISO and RTO that has both an internal MMU and an external MMU may 

permit the internal MMU to report to management and the external MMU to report to the 

Commission-approved ISO or RTO board of directors with its management members 

removed, or to an independent committee of the Commission-approved ISO or RTO 

board of directors.
Docket Nos. RM07-19-000 and AD07-7-000 - 167 - 

(E) Commission-approved ISOs and RTOs may not alter the reports generated 

by the Market Monitoring Unit, or dictate the conclusions reached by the Market 

Monitoring Unit. 

(F) Commission-approved ISOs and RTOs must consolidate the core Market 

Monitoring Unit provisions into one section in their tariffs as provided in paragraph (g) 

(6) of this section. 

(ii) Functions of Market Monitoring Unit. The Market Monitoring Unit must 

perform the following functions: 

(A) Evaluate existing and proposed market rules, tariff provisions and market 

design elements for their effectiveness and recommend proposed rule and tariff changes 

to the Commission-approved ISO or RTO, to the Commission’s Office of Energy Market 

Regulation staff and to other interested entities such as state commissions and market 

participants. 

(B) Review and report on the performance of the wholesale markets to the 

Commission-approved ISO or RTO, 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 ISO’s or RTO’s 

behavior may require investigation, including, but not limited to, suspected rule or tariff 

violations, market manipulation, inappropriate dispatch, and suspected violations of 
Docket Nos. RM07-19-000 and AD07-7-000 - 168 - 

Commission-approved rules and regulations. 

(D) The Market Monitoring Unit, whether internal or external, may not 

participate in the administration of the Commission-approved ISO’s or RTO’s tariff, 

including mitigation. 

(iii) Market Monitoring Unit ethical standards. Commission-approved ISOs 

and RTOs must include ethical standards for employees in their Market Monitoring 

Units. At a minimum, the ethical standards must include the following requirements: 

(A) Market Monitoring Unit employees must have no material affiliation with 

any market participant or affiliate. 

(B) Market Monitoring Unit employees must not serve as an officer, employee, 

or partner of a market participant. 

(C) Market Monitoring Unit employees must have no material financial interest 

in any market participant or affiliate with potential exceptions for mutual funds and nondirected investments. 

(D) Market Monitoring Unit employees must not engage in any market 

transactions other than the performance of their duties under the tariff. 

(E) Market Monitoring Unit employees must not be compensated for any 

expert witness testimony or other commercial services to the Commission-approved ISO 

or RTO or to any other party in connection with any legal or regulatory proceeding or 

commercial transaction relating to the Commission-approved ISO or RTO or to the 

Commission-approved ISO or RTO markets. 

(F) Market Monitoring Unit employees may not accept anything of value from 
Docket Nos. RM07-19-000 and AD07-7-000 - 169 - 

a market participant in excess of a de minimis amount. 

(G) Market Monitoring Unit 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 ISO or RTO obtains 

Commission approval for a different period, Commission-approved ISOs and RTOs must 

release their offer and bid data within three months. 

(ii) Commission-approved ISOs and RTOs may mask the identity of market 

participants when releasing offer and bid data. 

(5) Responsiveness of Commission-approved ISOs and RTOs. Commissionapproved ISOs and RTOs must adopt business practices and procedures that achieve 

Commission-approved ISO and RTO board of directors responsiveness to customers and 

other stakeholders and satisfy the following criteria: 

(i) Inclusiveness. The practices and procedures must ensure that any customer 

or stakeholder affected by the operation of the Commission-approved ISO or RTO, or its 

representative, is permitted to communicate its views to the RTO or ISO board; 

(ii) Fairness in balancing diverse interests. The practices and procedures must 

ensure that the interests of customers or other stakeholders are equitably considered and 

that deliberation and consideration of Commission-approved ISO and RTO issues are not 

dominated by any single stakeholder category; 

(iii) Representation of minority positions. The practices and procedures must 
Docket Nos. RM07-19-000 and AD07-7-000 - 170 - 

ensure that, in instances where stakeholders are not in total agreement on a particular 

issue, minority positions are communicated to the board of directors at the same time as 

majority positions; and 

(iv) Ongoing responsiveness. The practices and procedures must provide for 

stakeholder input into RTO or ISO 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 ISOs and RTOs 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 ISO and RTO 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 of this part, 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 
Docket Nos. RM07-19-000 and AD07-7-000 - 171 - 

comply with 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 - 172 - 

Appendix A: Commenter Acronyms 

Commenters to the ANOPR in Docket Nos. RM07-19-000 and AD07-7-000 

AARP, et al. – AARP; American Antitrust Institute; American Chemistry Council; 

American Forest & Paper Association; American Iron and Steel Institute; 

American Municipal Power–Ohio; American Public Power Association; 

Association of Businesses Advocating Tariff Equity; Citizen Power; Citizens 

Utility Board of Illinois; Coalition of Midwest Transmission Customers; Colorado 

Office of Consumer Counsel; Consumer Federation of America; Council of 

Industrial Boiler Owners; Democracy and Regulation; Electricity Consumers 

Resource Council; Florida Industrial Power Users Group; Illinois Industrial 

Energy Consumers; Illinois Public Interest Research Group; Industrial Energy 

Consumers of America; Industrial Energy Consumers of Pennsylvania; Industrial 

Energy Users–Ohio; Louisiana Energy Users Group; Maryland Office of the 

People’s Counsel; Maryland Public Interest Research Group; Missouri Industrial 

Energy Consumers; National Association of State Utility Consumer Advocates; 

NEPOOL Industrial Customer Coalition; Office of the People’s Counsel of the 

District of Columbia; Ohio Hospital Association, Ohio Manufacturers’ 

Association; Ohio Partners for Affordable Energy; PJM Industrial Customer 

Coalition, Portland Cement Association; Power in the Public Interest, Public 

Citizen, Inc.; Public Utility Law Project of New York, Inc.; Steel Manufacturers 

Association; West Virginia Energy Users Group; Wisconsin Industrial Energy 

Group, Inc.; and Wisconsin Paper Council.

AEP – American Electric Power Service Corporation. 

Alcoa – Alcoa, Inc. 

Allegheny Energy – Allegheny Power and Allegheny Energy Supply Company, LLC. 

Ameren – Ameren Services Company. 

American Forest – American Forest & Paper Association. 

APPA – American Public Power Association. 

ATC – American Transmission Company, LLC. 

AWEA – American Wind Energy Association. 

Blue Ridge – Blue Ridge Power Agency. 

BlueStar Energy – BlueStar Energy Services, Inc. 

BP Energy – BP Energy Company.

Cal DWR – California Department of Water Resources State Water Project. 

CAISO – California Independent System Operator Corporation. 

California Munis – California Municipal Utilities Association. 

California PUC – California Public Utilities Commission. 

COMPETE Coalition – 171 various entities. 
Docket Nos. RM07-19-000 and AD07-7-000 - 173 - 

COMPETE, et al. – 7-Eleven, Inc.; Allegheny Energy, Alliance for Real Energy 

Options; Alliance for Retail Choice, Alliance for Retail Energy Markets; Alliance 

for Retail Markets; Ardmore Power Logistics; Professor Ross Baldick, IEEE 

Fellow, Department of Electrical and Computer Engineering, The University of 

Texas at Austin; Big Lots Stores, Inc.; Nora Mead Brownell, BC Consulting, 

former FERC Commissioner and former PaPUC Commissioner; H. Sterling 

Burnett, Ph.D., Senior Fellow, National Center for Policy Analysis; California 

Alliance for Competitive Energy Solutions; California Grocers Association; 

California Retailers Association; Laura Chappelle, Attorney, former Chairman, MI 

PSC; Colorado Independent Energy Association; Constellation Energy; 

Comverge, Maryland; DC Energy, LLC; David W. DeRamus, Partner, Bates 

White, LLC; Direct Energy Services, LLC; Richard A. Drom, Partner, Powell 

Goldstein LLP; Edison Mission Energy; Electric Power Supply Association; 

Electric Power Generation Association; Energy Association of Pennsylvania; 

Energy Curtailment Specialists, Inc.; Enermetrix; Enerwise Global Technologies; 

Exelon Corporation; FirstEnergy Corp.; William L. Flynn, Partner, Harris Beach 

PLLS, former Chairman, NY PSC; John Hanger, former PaPUC Commissioner; 

Hess Corp.; William W. Hogan, Raymond Plank Professor of Global Energy 

Policy, John F. Kennedy School of Government, Harvard University; Illinois 

Energy Association; Independent Power Producers of New York; JCPenny; 

Kimball Resources, Inc.; Jerry J. Langdon, former FERC Commissioner; LS 

Power Associates, LP; Luminant; Macy’s Inc., Midwest Independent Power 

Suppliers; Mirant Corporation; Elizabeth A. Moler, Exelon Corp., former Chair of 

FERC; National Energy Marketers Association; New England Energy Alliance; 

New England Power Generators Association, Inc.; Northwest and Intermountain 

Power Producers Coalition; NRG Energy, Inc.; Nuclear Energy Institute; 

PennFuture; PetSmart, Inc.; Piney Creek LP; PJM Power Providers Group; 

PowerGrid Systems, Inc.; PPL Corporation; Priority Power management, Ltd.; 

PSEG Companies; John M. Quain, Buchanan Ingersoll & Rooney PC, former 

Chairman of PaPUC; Reliant Energy; Retail Energy Suppliers Association; 

Safeway, Inc.; School Project for Utility Rate Reduction; Sempra Energy; Shell 

Energy North America; Silicon Valley Leadership Group; Vernon L. Smith, Nobel 

Laureate, Professor of Economics and Law, Chapman University; David A. 

Svanda, Svanda Consulting, former MI PSC Commissioner and former President 

of NARUC; Glen Thomas, GT Power, former Chairman of PaPUC; Telga 

Corporation; Texas Competitive Power Advocates; TXU Energy; Wal-Mart 

Stores, Inc.; Western Power Trading Forum; and Pat Wood, III, former Chairman 

of FERC and the PUCT. 

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 - 174 - 

Constellation – Constellation Energy Commodities Group, Inc.; Constellation 

NewEnergy, Inc.; and Constellation Generation Group, LLC. 

DC Energy – DC Energy, LLC.

Detroit Edison – Detroit Edison Company. 

Dominion Resources – Dominion Resources Services, Inc. 

Duke Energy – Duke Energy Corporation. 

Dynegy – Dynegy Power Corporation. 

EEI – Edison Electric Institute and Alliance of Energy Suppliers. 

EnergyConnect – Energy Connect, Inc. 

Energy Curtailment – Energy Curtailment Specialists, Inc. 

EnerNOC – EnerNOC, Inc. 

EPSA – The 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, Inc.; 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. 

Mr. Hogan – William W. Hogan and Susan L. Pope. 

Indianapolis P&L – Indianapolis Power and Light Company. 

Industrial Coalitions –Coalition of Midwest Transmission Customers; NEPOOL 

Industrial Customer Coalition; and PJM Industrial Customer Coalition. 

Industrial Consumers - Electricity Consumers Resource Council; American Iron and 

Steel Institute; and American Chemistry Council. 

ISO-NE – ISO New England, Inc. 

ISO/RTO Council – ISO/RTO Council: California Independent System Operator 

Corporation; ISO New England, Inc.; the Midwest Independent Transmission 

System Operator, Inc.; New York Independent System Operator, Inc.; PJM 

Interconnection, L.L.C.; Southwest Power Pool. 

ITC – International Transmission Company and Michigan Electric Transmission 

Company, LLC. 

Integrys – Integrys Energy Services, Inc. 

J.Aron, Barclays, Morgan Stanley - J.Aron & Company, Barclays Capital, and Morgan 

Stanley Capital Group Inc. 

Joint Consumer Advocates – Ohio Consumers Counsel, District of Columbia Office of 

the People’s Counsel; Pennsylvania Office of Consumer Advocate; Illinois 
Docket Nos. RM07-19-000 and AD07-7-000 - 175 - 

Citizens Utility Board; Maryland Office of People’s Counsel; and New Jersey 

Department of the Public Advocate, Division of Rate Counsel. 

Kansas CC – Kansas Corporation Commission. 

LPPC – Large Public Power Council. 

Massachusetts AG – Massachusetts Attorney General. 

Mr. McCullough – Robert McCullough. 

Midwest ISO – Midwest Independent Transmission System Operator, Inc. 

Midwest ISO TOs – Midwest ISO Transmission Owners. 

Mirant – Mirant Corporation. 

NARUC – National Association of Regulatory Utility Commissions.

National Energy Marketers – National Energy Marketers Association. 

National Grid – National Grid USA. 

NEPOOL Participants – NEPOOL Participants Committee. 

New England Conference – New England Conference of Public Utilities 

Commissioners; Connecticut Department of Public Utility Control; Massachusetts 

Department of Public Utilities; Massachusetts Department of Energy Resources; 

New Hampshire Public Utilities Commission; Rhode Island Public Utilities 

Commission; the Vermont Department of Public Service; and Vermont Public 

Service Board. 

New England Power Generators – New England Power Generators Association. 

New York PSC – New York State Public Service Commission. 

NJBPU – New Jersey Board of Public Utilities. 

NJ BPU Commissioner Bator – New Jersey Board of Public Utilities Commissioner 

Christine V. Bator. 

North Carolina Commission – North Carolina Utilities Commission; Public Staff-North 

Carolina Utilities Commission; and the Attorney General of the State of North 

Carolina. 

North Carolina Electric Membership – North Carolina Electric Membership 

Corporation. 

Northeast Utilities – Northeast Utilities. 

NRECA – National Rural Electric Cooperative Association. 

NRG – NRG Energy, Inc. 

NSTAR – NSTAR Electric Company. 

NYISO – New York Independent System Operator Corp. 

NY TOs – New York Transmission Owners. 

Ohio PUC – Public Utilities Commission of Ohio. 

Old Dominion – Old Dominion Electric Cooperative. 
Docket Nos. RM07-19-000 and AD07-7-000 - 176 - 

OMS – Organization of MISO States. 

OPSI – Organization of PJM States, Inc. 

Otter Tail – Otter Tail Power Company. 

Pennsylvania PUC – Pennsylvania Public Utilities Commission. 

Pepco – Pepco Holdings, Inc.; Delmarva Power & Light Company; Atlantic City 

Electric Company; Conectiv Energy Supply Inc.; and Pepco Energy Services, Inc. 

PGC – PGC Electricity Committee. 

PG&E – Pacific Gas and Electric Company. 

PJM – PJM Interconnection, LLC. 

PJM Power Providers – PJM Power Providers Group. 

PJM MMU – Independent Market Monitoring Unit of PJM. 

Portland Cement – Portland Cement Association. 

Portland Cement Association, et al. – Multiple Intervenors; PJM Industrial Customer 

Coalition; Connecticut Industrial Energy Consumers; Industrial Energy UsersOhio; Mittal Steel USA, Inc. 

Potomac Economics – Potomac Economics, Inc. 

Power in Public Interest – Power in the Public Interest. 

PPL Parties – PPL Parties. 

PSEG – PSEG Companies: Public Service Electric and Gas Company; PSEG Power 

LLC and PSEG Energy Resources & Trade LLC. 

Public Interest Organizations –Center for Energy Efficiency & Renewable 

Technologies; Connecticut Office of Consumer Counsel; Conservation Law 

Foundation; Delaware Division of the Public Advocate; Environmental Law & 

Policy Center; Fresh Energy, Natural Resources Defense Council; New Hampshire 

Office of Consumer Advocate; Office of the Ohio Consumers’ Counsel; Pace 

Energy Project; Project for Sustainable FERC Energy Policy; Renewable 

Northwest Project; Union of Concerned Scientists and West Wind Wires. 

Reliant – Reliant Energy, Inc. 

Safeway – Safeway, Inc. 

Silicon Valley Power – Silicon Valley Power. 

SMUD – Sacramento Municipal Utility District. 

SoCal Edison-SDG&E - Southern California Edison Company and San Diego Gas & 

Electric. 

SPP – Southwest Power Pool, Inc. 

Steel Manufacturers – Steel Manufacturers Association. 

Steel Producers – Steel Producers. 

Strategic Energy – Strategic Energy, L.L.C. 

SUEZ – SUEZ Energy North America, Inc. 
Docket Nos. RM07-19-000 and AD07-7-000 - 177 - 

TAPS – Transmission Access Policy Study Group. 

The Alliance – The Alliance For Retail Energy Markets. 

Utility Savings – Utility Savings & Refund, LLC. 

Wal-Mart – Wal-Mart Stores, Inc. 

Wisconsin Industrial – Wisconsin Industrial Energy Group. 

WSPP – WSPP Inc. 

Xcel - Xcel Energy Services, Inc., on behalf of Northern States Power Company; 

Northern States Power Company; Wisconsin, Public Service Company of 

Colorado; and Southwestern Public Service Company. 
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 February 22, 2008) 

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

 I support many of the efforts enumerated in the Notice of Proposed Rulemaking 

(NOPR) which requests comment on proposals to improve the operation of wholesale 

electric markets. I believe that it is extremely important that we ensure that wholesale 

markets are competitive thereby allowing the Commission to fulfill our statutory mandate 

to ensure adequate and reliable non-discriminatory service at just and reasonable rates. 

Unfortunately, I am concerned regarding the potential impact of several of the proposals 

related to demand response, market monitoring, and promoting regional transmission 

organization (RTO) / independent system operator (ISO) responsiveness. 

 I continue to be troubled by the NOPR’s proposal in the Market Rules Governing 

Price Formation During Periods of Operating Reserve Shortage section. This section 

would attempt to stimulate demand response by allowing RTOs/ISOs to implement 

scarcity pricing by modifying market power mitigation rules in organized markets, such 

as raising energy supply offer caps and demand bid caps. I appreciate the efforts made in 

the NOPR to address market power associated with scarcity pricing and to ensure that 

there is an adequate record regarding any scarcity pricing proposal, including soliciting 

the views of each RTO/ISO market monitor on any proposed reform in this area. 

However, these positive changes in the NOPR proposal have not alleviated my concerns 

regarding the very real impacts on customers associated with raising energy supply offer 

caps and demand bid caps in emergency situations. 

 I believe that absent appropriate resource adequacy requirements and the 

necessary demand response infrastructure to give consumers the ability to respond to 

higher prices, it is not responsible to allow energy supply offer caps and demand bid caps 

to rise without regard to the impacts on consumers. I do not per se oppose scarcity 

pricing. However, I believe that there is a crucial timing issue that we must consider 

regarding any scarcity pricing proposal. Prior to implementing scarcity pricing in any 

market, we must have resources in place to meet demand. One essential way to 

accomplish this goal is through resource adequacy requirements. If a market is resource 

adequate, then there will be fewer emergency situations and, when those emergencies do 

occur, having demand response in place will help reduce prices in times of scarcity. 

Therefore, resource adequacy requirements and the ability of demand response to 

participate in a market go hand in hand with protecting consumers from market power 

and thereby making scarcity pricing proposals just and reasonable. 
Docket Nos. RM07-19-000 and AD07-7-000 - 2 -

 Some may look at this as a chicken and egg debate where if we allow energy 

supply offer caps and demand bid caps to increase without restraint this will raise prices 

thereby encouraging additional generation and demand response to enter the market. On 

the other hand, what happens in the meantime to consumers as we allow prices to rise 

without restraint and we are still waiting for these theoretical incentives to building 

adequate generation and demand response infrastructure to kick in? We must never lose 

sight of the interests of consumers as we engage in this kind of philosophical debate 

because they will be the ones who will lose out if we miscalculate. The necessary 

generation and demand response infrastructure must be in place prior to allowing energy 

supply offer caps and demand bid caps to rise or be eliminated. Unfortunately, this is not 

the case. As Commission staff noted in the 2006 FERC Staff Demand Response 

Assessment, advanced metering currently has low market penetration of less than six 

percent in the United States.1

 This means that consumers do not have the tools they need 

in order to make choices regarding rising prices and respond accordingly. 

 On the issue of market monitoring, I disagree with the NOPR’s proposal to 

remove market monitors from tariff administration, particularly market power mitigation. 

I believe that market monitoring units (MMUs) should continue to perform mitigation. 

The NOPR states that the issue of removing MMUs from mitigation “proved to be the 

most contentious one in the entire market monitoring section.”2

 This is for good reason. 

As Portland Cement noted in its comments, “The MMU’s are better positioned to make 

determinations regarding the exercise of market power than are the RTO/ISO staff 

members who frequently have long standing close personal relationships with the very 

market participants whose actions at times need to be mitigated.”3

 Further, I agree with 

Portland Cement’s statement that having RTO/ISO staff mitigate creates a much greater 

conflict of interest than any incidental conflict created by having the internal MMU both 

mitigate and report on the functioning of the markets.4

 The New York Independent 

System Operator (NYISO) also agrees that the concerns expressed in support of 

removing the MMU from mitigation are misplaced.5

 NYISO further stated that “[t]here 

is no reason to fear that a market monitor would hesitate to report market power problems 

or potential market abuses just because it was involved in implementing mitigation 

 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

 Wholesale Competition in Regions with Organized Electric Markets, Notice of 

Proposed Rulemaking, 122 FERC ¶ 61,617, at P 202 (2008). 

3

 Portland Cement Association Aug. 16, 2007 Comments, Docket Nos. AD07-7, 

RM07-19, at 19. 

4

 Id. 

5

 NYISO Sept. 14, 2007 Comments, Docket Nos. AD07-7, RM07-19, at 23. 
Docket Nos. RM07-19-000 and AD07-7-000 - 3 -

measures in that market.”6

 BP Energy asserts that “shifting the mitigation 

responsibility to RTO staff gives rise to a much larger conflict of interest than exists with 

having mitigation responsibility lie with the independent MMU exclusively.”7

 Therefore, 

I disagree with the NOPR’s proposal to remove MMUs from mitigation. 

 Additionally, I would have strengthened the market monitoring section. For 

example, the NOPR proposes to retain existing provisions regarding the confidentiality of 

the progress and results of the Commission’s own investigations. I believe that, subject 

to appropriate confidentiality limitations, the Commission should provide MMUs with 

information on referrals that the MMU provides to the Commission. I would also have 

supported requiring RTOs/ISOs to file tariff provisions to allow them to take enforcement 

action with respect to objectively identifiable behavior that does not subject the seller to 

sanctions or consequence other than those expressly approved by the Commission and set 

forth in the tariff and with the right of appeal, consistent with the Policy Statement on 

Market Monitoring Units.

8

 

 Further, I disagree with the NOPR’s proposal to promote responsiveness of 

RTOs/ISOs by allowing them to adopt hybrid boards with stakeholder members. 

Providing for stakeholder representatives on an RTO/ISO board is inconsistent with an 

independent governing structure. The Commission has already spoken clearly on the 

importance of RTOs/ISOs being independent of market participants. Having an 

independent board is the cornerstone of RTO/ISO policy. Order Nos. 8889

 and 200010

require that an RTO/ISO be independent from market participants in order to provide 

regional transmission and energy market services on a non-discriminatory basis. If an 

RTO or ISO adopted a hybrid board, I do not believe they could be categorized as 

 6

 Id. at 24 (citation omitted). 

7

 BP Energy Company Sept. 14, 2007 Comments, Docket Nos. AD07-7, RM07-

19, at 31. 

8

 Policy Statement on Market Monitoring Units, 111 FERC ¶ 61,267, at P 5 (2005) 

(citation omitted). 

9

 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). 

10 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 - 4 -

independent. Additionally, I believe that an RTO or ISO with a hybrid board 

jeopardizes the ability of the Commission to apply the independent entity variation 

standard found in Order No. 2003 when considering modifications to such an RTO or 

ISO’s pro forma Large Generator Interconnection Procedures (LGIP) and Large 

Generator Interconnection Agreement (LGIA).11 

 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 

were 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 non-independent board member. 

In contrast, I believe that the NOPR’s proposal to encourage RTOs and ISOs to establish 

a stakeholder advisory committee would meet the NOPR’s goal of improving RTO/ISO 

responsiveness without jeopardizing the fundamental independence of RTOs/ISOs. I also 

believe consideration should be given to the RTO/ISO mission statement as a tool to 

respond to any continuing stakeholder need for more RTO/ISO accountability. 

 Finally, I support the long-term power contracting in organized markets section of 

the NOPR. I agree with the NOPR’s suggestion that RTOs/ISOs conduct forums on 

long-term contracts to gather information and facilitate the exchange of ideas, similar to 

the one recently held by PJM. I believe that such forums will allow for an exchange of 

ideas on long-term contracting concerns and potentially foster solutions to these issues. I 

also agree that Commission staff should perform an analysis of the level of long-term 

contracting in organized market regions. 

 Accordingly, for the reasons stated above, I concur in part and dissent in part on 

this NOPR. 

 ______________________________ 

 Suedeen G. Kelly 

 

 11 Standardization of Generator Interconnection Agreements and Procedures, 

Order No. 2003, FERC Stats. & Regs. ¶ 31,146, at P 26 (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). 
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 February 22, 2008)

 

WELLINGHOFF, Commissioner, concurring:

 

 As the Commission states in this Notice of Proposed Rulemaking (NOPR), from 

the commencement of our first technical conference in this proceeding one year ago, our 

goal has been to identify specific reforms that can be made to optimize the efficiency of 

organized wholesale electric markets for the benefit of customers and, ultimately, the 

consumers who pay for electricity services. This NOPR marks an important step toward 

that goal, and I am pleased to support its issuance. 

 I would like to draw attention to a few areas of this NOPR, on which I particularly 

encourage interested persons to submit comments. 

 In this NOPR, the Commission highlights the importance of demand response to 

the organized markets. The Commission states that demand response helps to reduce 

prices in competitive wholesale markets in several ways, such as by reducing generator 

market power and flattening an area’s load profile. The Commission also recognizes that 

the need for, and the focus on, demand response will continue to increase. 

 The Commission makes several notable proposals in this NOPR related to demand 

response. One issue on which I encourage comments is the Commission’s proposal to 

require each RTO and 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. The Commission states that this policy would increase the 

competitiveness of ancillary services markets, help reduce the price of ancillary services, 

and improve the reliability of the grid. I am interested in hearing from interested parties 

whether our proposals in this area are adequate to achieve those goals. 

 The Commission also states that we intend to direct our staff to convene a 

technical conference shortly after we receive comments on this NOPR to consider critical 

issues related to demand response, such as appropriate compensation for demand 

response and potential solutions to remaining barriers to comparable treatment of demand 

response. We also propose to require each RTO and ISO to submit a study on these 
Docket Nos. RM07-19-000 and AD07-7-000 - - 2 - - 

critical issues within six months of the issuance of a Final Rule in this proceeding. Those 

studies would include proposed solutions along with a timeline for implementation. I 

encourage interested parties to provide comments on this approach and to identify 

particular issues or areas that should be addressed in these RTO and ISO studies. 

 In addition, I strongly encourage interested parties to comment on the 

Commission’s proposal in this NOPR concerning market rules that govern price 

formation during periods of operating reserve shortage. It is important to note that these 

are infrequent periods when more resources, both generation and demand resources, are 

needed to maintain reliable electric service to consumers. I appreciate the extensive 

comments that we received on this issue in response to the ANOPR. I believe that this 

proposal in the NOPR is an improvement in several respects over the discussion in the 

ANOPR. Most notably, the Commission proposes to adopt requirements to ensure that 

proposals for pricing during periods of operating reserve shortage are designed to protect 

consumers against the exercise of market power and are supported by an adequate factual 

record. More specifically, we propose that a primary criterion for approving such pricing 

proposals would be an adequate record demonstrating that provisions exist 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 shortage. I am particularly interested in receiving comments as to 

whether this and the other criteria proposed in this NOPR are appropriate, how the 

Commission should apply these criteria if we adopt them in a Final Rule, and whether 

there are additional criteria that we should consider in evaluating an RTO’s or ISO’s 

proposal for pricing during a period of operating reserve shortage. 

 Finally, I would like to note that the Commission in this NOPR is directing each 

RTO or ISO to provide a forum for affected consumers to voice specific concerns (and to 

propose regional solutions) about market designs in its particular region, including 

concerns as to the value to the market of significant changes to the market rules. We are 

also directing our staff to convene a technical conference on two proposals that were 

submitted in comments in this proceeding. Through these and other steps taken in this 

NOPR, it is my intention for the Commission to demonstrate how seriously we take our 

statement that the proposals in this NOPR do not represent our final effort to enhance the 

efficient functioning of competitive organized markets for the benefit of consumers. 

 

___________________________ 

Jon Wellinghoff 

Commissioner