E8-3984. Wholesale Competition in Regions With Organized Electric Markets

Issued February 22, 2008.

AGENCY:

Federal Energy Regulatory Commission, DOE.

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: Demand response and market pricing during a period of operating reserve shortage; long-term power contracting; market-monitoring policies; and 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 April 21, 2008.

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, NE., Washington, DC 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, NE., Washington, DC 20426, [e-mail], [phone].

Tina Ham (Legal Information), Office of the General Counsel, Federal Energy Regulatory Commission, 888 First Street, NE., Washington, DC 20426, [e-mail], [phone].

SUPPLEMENTARY INFORMATION:

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
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
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

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 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 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 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 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 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 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 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 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 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 large-scale 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 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 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 real-time 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 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 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 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 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.

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, 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, 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]

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 non-peak 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 higher-price 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 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 resource ^[32] 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 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 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 requirement of EPAct 2005 ^[42] 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 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 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 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 co-optimized 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 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 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 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 market-clearing 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 markets. We believe that these proposals ensure comparable treatment of demand response resources. We discuss these proposals in greater detail below.

9. 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 market-clearing 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.

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 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 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 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 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 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, 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 co-optimizing 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 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 co-optimized 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 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 co-optimized 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, 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 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 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 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 non-emergencies “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 buyer ^[83] 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.

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 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 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 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 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 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] 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.

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 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 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.
• 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 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 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 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 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 market-clearing 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.

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 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.

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 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 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 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.

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 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;
• 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 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 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]

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 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 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 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 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 long-term 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 long-term 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 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 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.

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.

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.

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 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 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 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 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 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 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?

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 long-term 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.

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 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]

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 Commission ^[127] 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 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, LLC (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 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 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).

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 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 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.

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.

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 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]

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 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 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 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 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 Restrictions ^[167] 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 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 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. 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 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, 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 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 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 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]

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 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 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 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 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 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 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 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 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 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 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.

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 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 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 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, 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 tariff-defined 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 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 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]

(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 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 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 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 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 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 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 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 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 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 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 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 well-respected 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]

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.

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) 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 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 suggests 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 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 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 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.

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 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.
• 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]

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 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 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
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

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”.

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, NE., Washington, DC 20426, Attention: Michael Miller, Office of the Executive Director, Phone: [phone], fax: [phone], e-mail: [e-mail]. 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, DC 20503, Attention: Desk Officer for the Federal Energy Regulatory Commission, fax [phone], e-mail: [e-mail].

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]

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, LLC (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.
• 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 April 21, 2008. 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.

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, NE., 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 p.m. Eastern time) at 888 First Street, NE., 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 e-mail at [e-mail], or the Public Reference Room at [phone], TTY [phone]. E-mail the Public Reference Room at [e-mail].

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.

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 paragraphs (b)(4), (b)(5), (b)(6), and (b)(7).

b. Add a new paragraph (g).

§ 35.28

Non-discriminatory open access transmission tariff.

* * * * *

(b) * * *

(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 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

(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 real-time 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 Commission-approved ISO or RTO must provide a portion of its Web site for market participants to post offers to buy or sell power on a long-term basis.

(3) Market monitoring policies. (i) 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 RTO's 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 Commission-approved 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 Commission-approved 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.

(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 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 non-directed 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 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. Commission-approved 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 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 after date of publication of Final Rule 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 comply with Order No. [insert order number] and the provisions of paragraphs (g)(1) through (g)(5) of this section before beginning operations.

Note:

The following appendices will not appear in the Code of Federal Regulations.

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.

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, PhD., 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; JC Penny; 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.

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, LLC; 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 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.

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 Users-Ohio; 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, LLC.

SUEZ—SUEZ Energy North America, Inc.

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 Organized Electric Markets—Docket Nos. RM07-19-000 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.

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.^[293] 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.” ^[294] 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.” ^[295] 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.^[296] The New York Independent System Operator (NYISO) also agrees that the concerns expressed in support of removing the MMU from mitigation are misplaced.^[297] 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 measures in that market.” ^[298] 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.” ^[299] 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.^[300]

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. 888 ^[301] and 2000 ^[302] 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 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).^[303]

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.

United States of America Federal Energy Regulatory Commission

Wholesale Competition in Regions With Organized Electric Markets—Docket Nos. RM07-19-000, 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 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.

Footnotes

1.  Organized market regions are areas of the country in which a regional transmission organization (RTO) or independent system operator (ISO) operates day-ahead and/or real-time energy markets.

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 Notice of Proposed Rulemaking, 72 FR 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).

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 (DC Cir. 1975), aff'd, 425 U.S. 662 (1976).

11.  The following RTOs and ISOs have organized markets: PJM Interconnection, LLC (PJM), New York Independent System Operator, Inc. (NYISO), Midwest Independent Transmission System Operator, Inc. (Midwest ISO), ISO New England, Inc. (ISO-NE), California Independent Service Operator Corp. (CAISO), and Southwest Power Pool, Inc. (SPP).

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.

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 (DC 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 (DC Cir. 2007).

16.  PJM Interconnection, LLC, 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).

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 FR 12,266 (Mar. 15, 2007), FERC Stats. & Regs. ¶ 31,241, order on reh'g, Order No. 890-A, FERC Stats. & Regs. ¶ 31,261 (2007)).

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).

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.

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, LLC, 95 FERC ¶ 61,306 (2001); PJM Interconnection, LLC, 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.

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).

29.  Id.

30.  Id. at 12.

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, LLC, 95 FERC ¶ 61,306 (2001); PJM Interconnection, LLC, 99 FERC ¶ 61,139 (2002); PJM Interconnection, LLC, 99 FERC ¶ 61,227 (2002).

32.  See, e.g., PJM Interconnection, LLC, 117 FERC ¶ 61,331 (2006); 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 (DC 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, LLC, 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, LLC, 99 FERC ¶ 61,227 (2002).

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

36.  Supra note 34.

37.  See Mandatory Reliability Standards for the Bulk-Power System, Order No. 693, 72 FR 16,416 (April 4, 2007), FERC Stats. & Regs. ¶ 31,242, order on reh'g, Order No. 693-A, 120 FERC ¶ 61,053 (2007).

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.

42.  Public Law 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.

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.

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.

52.  See 2006 FERC Staff Demand Response Assessment at 123.

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.

54.  The Commission approved this change in 2003. New York Indep. Sys. Operator, Inc., 102 FERC ¶ 61,313 (2003).

55.  BlueStar Energy at 2.

56.  Industrial Coalitions at 13-14.

57.  APPA at 48.

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.

63.  NYISO at 32.

64.  EEI at 12.

65.  PGC at 10-11.

66.  Pepco at 7.

67.  See 2006 FERC Staff Demand Response Assessment at 114.

68.  For example, ISO-NE is assessing whether small demand response resources can provide operating reserves in its Demand Response Reserves Pilot.

69.  Bidding rules at RTOs and ISOs such as Midwest ISO and PJM already incorporate aspects of these proposed new bidding parameters.

70.  The Commission noted that it would refer to the charge that it proposed to eliminate during an emergency as a “deviation charge.”

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.

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.

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.

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.

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.

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.

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 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).

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.

94.  The Energy Independence and Security Act of 2007, Pub. L. No. 110-140, 121 Stat. 1492 (2007).

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.

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.

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.

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.

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.

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 (DC Cir. 2007); PJM Interconnection, LLC, 117 FERC ¶ 61,331 (2006).

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).

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.

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, 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).

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.

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 (2005), aff'd sub nom. Nat'l Ass'n of Regulatory Util. Comm'rs v. FERC, 475 F.3d 1277 (DC 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 (DC Cir. 2007); PJM Interconnection, LLC, 117 FERC ¶ 61,331 (2006).

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.

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.

119.  See Pepco at 13; New England Power Generators at 8; Dynegy at 3.

120.  More information on the PJM forums is available at http://www.pjm.com/​committees/​stakeholders/​drs/​ltc.html.

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 (DC Cir. 2001).

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); Pennsylvania-New 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.

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 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, LLC, 116 FERC ¶ 61,038 (2006) (PJM Tariff Order).

134.  PJM Interconnection, LLC, 117 FERC ¶ 61,263, at P 19 (2006) (PJM Tariff Rehearing Order).

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).

137.  Exelon at 25; Strategic Energy at 13; Suez at 9.

138.  NJBPU at 1-2.

139.  Ohio PUC at 9-14.

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.

147.  See, e.g., NYISO at 20; North Carolina Commission at 6.

148.  PJM MMU at 10.

149.  149 EEI at 43.

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.

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.

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.

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 (DC Cir. 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).

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 FR 39,904 (July 20, 2007), FERC Stats. & Regs. ¶ 31,252 (2007).

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.

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.

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.

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.

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.

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.

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.

196.  Market Behavior Rules Order, 105 FERC ¶ 61,218 at P 182; Policy Statement, 111 FERC ¶ 61,267 at P 5.

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.

199.  EPSA at 46; Exelon at 27.

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.

201.  EPSA at 46; Pepco at 19.

202.  Duke Energy at 24.

203.  PJM MMU at 17.

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.

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.

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.

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.

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 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.

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.

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.

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.

231.  18 CFR 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).

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.

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 (DC 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 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.

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.

247.  Id. P 153-54.

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 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 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.

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.

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] 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 (DC 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.

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.

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.

275.  DC Energy at 10.

276.  North Carolina Commission at 9-10.

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.

281.  NARUC at 13.

282.  OPSI at 45.

283.  Order No. 2000, FERC Stats. & Regs. ¶ 31,089 at 31,061.

284.  Id. at 31,170.

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.

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.

287.  5 CFR 1320.11 (2007).

288.  44 U.S.C. 3507(d) (2000).

289.  Regulations Implementing the National Environmental Policy Act, Order No. 486, FERC Stats. & Regs. ¶ 30,783 (1987).

290.  18 CFR 380.4(a)(15) (2007).

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 CFR 121.202 (Sector 22, Utilities, North American Industry Classification System, NAICS) (2004).

293.  Assessment of Demand Response and Advanced Metering: Staff Report, Docket No. AD06-2-000, at 26 (2006) (2006 FERC Staff Demand Response Assessment).

294.  Wholesale Competition in Regions with Organized Electric Markets, Notice of Proposed Rulemaking, 122 FERC ¶ 61,617, at P 202 (2008).

295.  Portland Cement Association Aug. 16, 2007 Comments, Docket Nos. AD07-7, RM07-19, at 19.

296.  Id.

297.  NYISO Sept. 14, 2007 Comments, Docket Nos. AD07-7, RM07-19, at 23.

298.  Id. at 24 (citation omitted).

299.  BP Energy Company Sept. 14, 2007 Comments, Docket Nos. AD07-7, RM07-19, at 31.

300.  Policy Statement on Market Monitoring Units, 111 FERC ¶ 61,267, at P 5 (2005) (citation omitted).

301.  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 (DC Cir. 2000), aff'd sub nom. New York v. FERC, 535 U.S. 1 (2002).

302.  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 (DC Cir. 2001).

303.  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 (DC Cir. 2007).