# Wholesale Competition in Regions With Organized Electric Markets > Briefs, arguments, decisions, and more. URL: https://www.frixlaw.com/law-library/documents/fr%3AE8-3984 ## Record - **Collection:** Federal Register - **Document type:** Proposed Rule - **Published:** March 7, 2008 - **Citation:** 73 FR 12576 ## Text DEPARTMENT OF ENERGY Federal Energy Regulatory Commission 18 CFR Part 35 [Docket Nos. RM07-19-000 and AD07-7-000] Wholesale Competition in Regions With Organized Electric Markets Issued February 22, 2008. AGENCY: Federal Energy Regulatory Commission, 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, David.Kathan@ferc.gov , (202) 502-6404. Tina Ham (Legal Information), Office of the General Counsel, Federal Energy Regulatory Commission, 888 First Street, NE., Washington, DC 20426, Tina.Ham@ferc.gov , (202) 502-6224. SUPPLEMENTARY INFORMATION: Table of Contents 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. 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. 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 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). 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. 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). 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. 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). 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. 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). 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 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). 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 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. 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. 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). 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. 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). 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 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). 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 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). 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 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. 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. 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. 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. 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. a. Importance of Demand Response to Competition in RTO/ISO Areas 28. A well-functioning competitive wholesale electric market should reflect current supply and demand conditions. Enabling demand-side responses, as well as supply-side resources, improves the economic operation of electric power markets by aligning prices more closely with the value customers place on electric power. 29. Demand response helps to reduce prices in competitive wholesale markets in at least three ways. First, demand response has both a direct effect and an indirect effect on wholesale demand. The direct effect occurs when demand response is bid directly into the wholesale market: lower demand means a lower wholesale price. Demand response at retail, if not bid directly into the wholesale market by a retail customer, affects the wholesale market indirectly because it reduces the need for power by the retail customers' LSE and in turn reduces that LSE's need to purchase power from the wholesale market. 28 28 See Federal Energy Regulatory Commission, Assessment of Demand Response and Advanced Metering: Staff Report, Docket No. AD06-2-000, at 11 (August 8, 2006) ( 2006 FERC Staff Demand Response Assessment ). 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 29 Id. 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 30 Id . at 12. 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 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). 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. 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). 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. 36 Supra note 34. 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 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. 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 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 ). 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 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 . 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 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. 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 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. 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 52 See 2006 FERC Staff Demand Response Assessment at 123. 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. 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. 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 54 The Commission approved this change in 2003. New York Indep. Sys. Operator, Inc. , 102 FERC ¶ 61,313 (2003). 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 55 BlueStar Energy at 2. 56 Industrial Coalitions at 13-14. 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 57 APPA at 48. 58 California PUC at 7. 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 59 NYISO at 28; National Grid at 5. 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 60 Alcoa at 18-19. 61 Strategic Energy at 4. 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. 62 ISO-NE at 19. 63 NYISO at 32. 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 64 EEI at 12. 65 PGC at 10-11. 66 Pepco at 7. 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 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. 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. 69 Bidding rules at RTOs and ISOs such as Midwest ISO and PJM already incorporate aspects of these proposed new bidding parameters. 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 70 The Commission noted that it would refer to the charge that it proposed to eliminate during an emergency as a “deviation charge.” 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 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. 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 74 SoCal Edison-SDG&E at 2-3. 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. 75 DC Energy at 4. 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 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. 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 79 Id. at 54. 80 EEI at 17-19. 81 PJM at 7-8. 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. 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. 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. 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. 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 85 APPA at 56; NRECA at 13; EEI at 19; AEP at 4-5; California Municipals at 8-9. 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 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. 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 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. 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. 91 See, e.g. , PJM at 8; EnerNOC at 5-7; Alcoa at 22; Public Interest Organizations at 6-10. 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. 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). 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 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. 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. 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). 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. 96 We note that in this section of the NOPR, we refer to this emergency period as a period of operating reserve shortage. 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 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. 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. 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. 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 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. 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 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. 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. 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. 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. 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. 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. 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). 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 exerc [Text truncated at 120,000 characters. The full text is on the page linked above.] --- Source: Frix Law Library, https://www.frixlaw.com/law-library/documents/fr%3AE8-3984. Public record. Not legal advice.