# Wholesale Competition in Regions With Organized Electric Markets > Briefs, arguments, decisions, and more. URL: https://www.frixlaw.com/law-library/documents/fr%3AE8-25246 ## Record - **Collection:** Federal Register - **Document type:** Rule - **Published:** October 28, 2008 - **Citation:** 73 FR 64100 ## 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 October 17, 2008. AGENCY: Federal Energy Regulatory Commission. ACTION: Final Rule. SUMMARY: In this Final Rule, the Federal Energy Regulatory Commission (Commission) is amending its regulations under the Federal Power Act to improve the operation of organized wholesale electric markets in the areas of: Demand response and market pricing during periods 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 their customers and other stakeholders, and ultimately to the consumers who benefit from and pay for electricity services. Each RTO and ISO will be required to make certain filings that propose amendments to its tariff to comply with the requirements in each area, or that demonstrate that its existing tariff and market design already satisfy the requirements. DATES: Effective Date: This Final Rule will become effective December 29, 2008. FOR FURTHER INFORMATION CONTACT: Russell Profozich (Technical Information), Office of Energy Market Regulation, Federal Energy Regulatory Commission, 888 First Street, NE., Washington, DC 20426, Russell.Profozich@ferc.gov, (202) 502-6478. 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 10 III. Discussion 15 A. Demand Response and Pricing During Periods of Operating Reserve Shortages in Organized Markets 15 1. Background 16 2. Ancillary Services Provided by Demand Response Resources 20 a. Ancillary Services Market 21 b. New Bidding Parameters 64 c. Small Demand Response Resource Assessment 90 3. Eliminating Deviation Charges During System Emergencies 100 a. Deviation Charges 100 b. Virtual Purchasers 122 4. Aggregation of Retail Customers 128 a. Commission Proposal 128 b. Comments 132 c. Commission Determination 154 5. Market Rules Governing Price Formation During Periods of Operating Reserve Shortage 165 a. Price Formation During Periods of Operating Reserve Shortage 169 b. Four Approaches 208 c. The Commission's Proposed Criteria 238 d. Phase-In of New Rules 254 6. Reporting on Remaining Barriers to Comparable Treatment of Demand Response Resources 259 a. Comments 263 b. Commission Determination 274 B. Long-Term Power Contracting in Organized Markets 277 1. Background 278 2. Commission Proposal 283 3. Comments 286 4. Commission Determination 301 C. Market-Monitoring Policies 310 1. Background 314 2. Independence and Function 317 a. Structure and Tools 318 b. Oversight 333 c. Functions 345 d. Mitigation and Operations 361 e. Ethics 380 f. Tariff Provisions 388 3. Information Sharing 395 a. Enhanced Information Dissemination 395 b. Tailored Requests for Information 425 c. Commission Referrals 460 4. Pro Forma Tariff 470 a. Commission Proposal 470 b. Comments 471 c. Commission Determination 473 D. Responsiveness of RTOs and ISOs to Customers and Other Stakeholders 477 1. Background 479 2. Commission Proposal 481 a. Responsiveness Obligation and Proposed Criteria 481 3. Comments 484 4. Commission Determination 501 5. Board Advisory Committee and Hybrid Board 516 a. Comments 517 b. Commission Determination 534 6. Supermajority Requirement 538 a. Comments 539 b. Commission Determination 546 7. Posting Mission Statement or Organizational Charter on Web site 547 a. Comments 548 b. Commission Determination 556 8. Executive Compensation 558 a. Comments 559 b. Commission Determination 561 9. Compliance Filing Requirement 562 a. Comments 563 b. Commission Determination 565 E. Other Comments 568 1. Comments 568 2. Commission Determination 573 IV. Applicability of the Final Rule and Compliance Procedures 574 A. NOPR Proposal 574 B. Comments 575 C. Commission Determination 578 V. Information Collection Statement 584 VI. Environmental Analysis 587 VII. Regulatory Flexibility Act Certification 588 A. NOPR Proposal 593 1. Comments 596 2. Commission Determination 602 VIII. Document Availability 606 IX. Effective Date and Congressional Notification 609 Regulatory Text APPENDIX: Abbreviated Names of Commenters I. Introduction 1. This Final Rule addresses reforms to improve the operation of organized wholesale electric power markets. 1 Improving the competitiveness of organized wholesale markets is integral to the Commission fulfilling its statutory mandate to ensure supplies of electric energy at just, reasonable and not unduly discriminatory or preferential rates. Effective wholesale competition protects consumers by providing more supply options, encouraging new entry and innovation, spurring deployment of new technologies, promoting demand response and energy efficiency, improving operating performance, exerting downward pressure on costs, and shifting risk away from consumers. National policy has been, and continues to be, to foster competition in wholesale electric power markets. This policy was embraced in the Energy Policy Act of 2005 (EPAct 2005), 2 and is reflected in Commission policy and practice. The Commission balances the mix of regulation and competition based on changing circumstances, taking into account such factors as the opportunities for competition to control market power, advances in technology, changes in economies of scale, and new state and federal laws that affect the energy industry. 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. The following RTOs and ISOs have organized markets: PJMInterconnection, LLC (PJM), New York Independent System Operator, Inc. (NYISO), Midwest Independent Transmission System Operator, Inc. (Midwest ISO), ISO New England, Inc. (ISO New England), California Independent Service Operator Corp. (CAISO), and Southwest Power Pool, Inc. (SPP). 2 Pub. L. 109-58, 119 Stat. 594 (2005). 2. The Commission has a duty to improve the operation of wholesale power markets. To that end, in this Final Rule, the Commission is making reforms to improve the operation of organized wholesale electric markets in the areas of demand response, long-term power contracting, market monitoring policies, and RTO and ISO responsiveness. By making these reforms, the Commission is not seeking to fundamentally redesign organized markets; rather, these reforms are intended to be incremental improvements to the operation of organized markets without undoing or upsetting the significant efforts that have already been made in providing demonstrable benefits to wholesale customers. 3. In the areas of demand response and the use of market prices to elicit demand response, the Commission is requiring RTOs and ISOs to: (1) Accept bids from demand response resources in RTOs' and ISOs' markets for certain ancillary services on a basis comparable to other resources; (2) eliminate, during a system emergency, a charge to a buyer that takes less electric energy in the real-time market than it purchased in the day-ahead market; (3) in certain circumstances, permit an aggregator of retail customers (ARC) 3 to bid demand response on behalf of retail customers directly into the organized energy market; (4) modify their market rules, as necessary, to allow the market-clearing price, during periods of operating reserve shortage, to reach a level that rebalances supply and demand so as to maintain reliability while providing sufficient provisions for mitigating market power; and (5) study whether further reforms are necessary to eliminate barriers to demand response in organized markets. 3 We will use the phrase “aggregator of retail customers,” or ARC, to refer to an entity that aggregates demand response bids (which are mostly from retail loads). 4. With regard to long-term power contracting, the Commission is requiring RTOs and ISOs to dedicate a portion of their Web sites for market participants to post offers to buy or sell power on a long-term basis. This requirement will promote greater use of long-term contracts by improving transparency among market participants. 5. To improve market monitoring, the Commission is requiring that RTOs and ISOs provide their Market Monitoring Units (MMU) with access to market data, resources and personnel sufficient to carry out their duties, and that the MMU (or the external MMU in a hybrid structure) report directly to the RTO or ISO board of directors. 4 In addition, the Commission is requiring that the MMU's functions include: (1) Identifying ineffective market rules and recommending proposed rules and tariff changes; (2) reviewing and reporting on the performance of the wholesale markets to the RTO or ISO, the Commission, and other interested entities; and (3) notifying appropriate Commission staff of instances in which a market participant's behavior may require investigation. The Commission is also expanding the list of recipients of MMU recommendations regarding rule and tariff changes, and broadening the scope of behavior to be reported to the Commission. 4 Our use of the phrase “board of directors” also includes the board of managers, board of governors, and similar entities. 6. The Commission is also modifying MMU participation in tariff administration and market mitigation, requiring each RTO and ISO to include ethics standards for MMU employees in its tariff, and requiring each RTO and ISO to consolidate all its MMU provisions in one section of its tariff. The Commission is expanding the dissemination of MMU market information to a broader constituency, with reports made on a more frequent basis than they are now, and reducing the time period before energy market bid and offer data are released to the public. 7. Finally, the Commission establishes an obligation for each RTO and ISO to make reforms, as necessary, to increase its responsiveness to customers and other stakeholders and will assess each RTO's or ISO's compliance using four responsiveness criteria: (1) Inclusiveness; (2) fairness in balancing diverse interests; (3) representation of minority positions; and (4) ongoing responsiveness. 8. In each of these four areas, the Commission is requiring each RTO or ISO to consult with its stakeholders and make a compliance filing that explains how its existing practices comply with the Final Rule in this proceeding, or its plans to attain compliance. 9. Significant differences exist between regions, including differences in industry structure, mix of ownership, sources of electric generation, population densities, and weather patterns. Some regions have organized spot markets administered by an RTO or ISO, and others rely solely on bilateral contracting between wholesale sellers and buyers. We recognize and respect these differences across various regions. At the same time, wholesale competition can serve customers well in all regions. The focus of this Final Rule is to further improve the operation of wholesale competitive markets in organized market regions. II. Background 10. The Commission has acted over the last few decades to implement Congressional policy to expand the wholesale electric power markets to facilitate entry of new generators and to support competitive markets. Absent a single national power market, the development of regional markets is the best method of facilitating competition within the power industry, and the Commission has made sustained efforts to recognize and foster such markets. 11. In 2007, the Commission held several public conferences to gather information and address issues on competition at the wholesale level and other related issues. 5 At these conferences, the Commission examined issues affecting competition in the RTO and ISO regions, including the levels of wholesale prices, the need for long-term power contracts, the effectiveness of market monitoring, and the lack of adequate demand response. The Commission also addressed concerns related to the RTO and ISO board of directors' responsiveness to their customers and other stakeholders. 5 Three technical conferences were held on February 27, 2007, April 5, 2007, and May 8, 2007. 12. On June 22, 2007, the Commission issued an Advance Notice of Proposed Rulemaking (ANOPR), 6 identifying four specific issues in organized market regions that were not being adequately addressed or were not under consideration in other proceedings. These areas were: (1) The role of demand response in organized markets and greater use of market prices to elicit demand response during periods of operating reserve shortage; (2) increasing opportunities for long-term power contracting; (3) strengthening market monitoring; and (4) enhancing the responsiveness of RTOs and ISOs to customers and other stakeholders, and ultimately to the consumers who benefit from and pay for electricity services. The Commission presented preliminary views on proposed reforms for these areas and sought comment on them. 6 Wholesale Competition in Regions with Organized Electric Markets, Advance Notice of Proposed Rulemaking, FERC Stats. & Regs. ¶ 32,617 (2007). 13. After receiving and considering over a hundred comments on the ANOPR, on February 22, 2008, the Commission issued a Notice of Proposed Rulemaking (NOPR). 7 In the NOPR, pursuant to the Commission's responsibility under sections 205 and 206 of the Federal Power Act (FPA), 8 the Commission proposed reforms in the four specific areas identified above that were designed to ensure just and reasonable rates, to remedy undue discrimination and preference, and to improve wholesale competition in regions with organized markets. As noted in the NOPR, these proposed reforms are intended to improve the operation of wholesale competition in organized markets. 9 7 Wholesale Competition in Regions with Organized Electric Markets, Notice of Proposed Rulemaking, 73 FR 12,576 (March 7, 2008), FERC Stats. & Regs. ¶ 32,628 (2008). 8 16 U.S.C. 824d—824e. 9 NOPR, FERC Stats. & Regs. ¶ 32,628 at P 11. 14. In the NOPR, the Commission also noted that the reforms proposed in this proceeding do not represent its final effort to improve the functioning of competitive organized markets for the benefit of consumers; rather, the Commission will continue to evaluate specific proposals that may strengthen organized markets. 10 To that end, for example, the Commission proposed to require each RTO or ISO to study whether further reforms are necessary to eliminate barriers to demand response in organized markets. Any reforms must ensure that demand response resources are treated on a basis comparable to other resources. The Commission also ordered two staff technical conferences: (1) One to investigate proposals by American Forest and the Portland Cement Association, et al. to modify the design of organized markets; 11 and (2) a separate conference to consider several issues related to demand response participation in wholesale markets. 12 Further, the Commission directed each RTO or ISO to provide a forum for affected consumers to voice specific concerns (and to propose regional solutions) on how to improve the efficient operation of competitive markets. 13 10 Id. P 1. 11 The technical conference was held on May 7, 2008. See Supplemental Notice of Technical Conference, Capacity Markets in Regions with Organized Electric Markets, Docket No. AD08-4-000 (April 25, 2008). 12 The technical conference was held on May 21, 2008. See Supplemental Notice of Technical Conference, Demand Response in Organized Electric Markets, Docket No. AD08-8-000 (May 13, 2008). 13 NOPR, FERC Stats. & Regs. ¶ 32,628 at P 11. III. Discussion A. Demand Response and Pricing During Periods of Operating Reserve Shortages in Organized Markets 15. This section of the Final Rule makes several reforms to further eliminate barriers to demand response participation in organized energy markets. These reforms are to ensure that demand response is treated comparably to other resources. To that end, the Commission will require RTOs and ISOs to: (1) Accept bids from demand response resources in their markets for certain ancillary services, on a basis comparable to other resources; (2) eliminate, during a system emergency, certain charges to buyers in the energy market for voluntarily reducing demand; (3) permit ARCs to bid demand response on behalf of retail customers directly into the RTO's or ISO's organized markets; and (4) modify their rules governing price formation during periods of operating reserve shortage to allow the market-clearing price during periods of operating reserve shortage to more accurately reflect the true value of energy. 1. Background 16. Commission policy does not favor granting preference for demand response; rather, our goal is to eliminate barriers to the participation of demand response in the organized power markets by ensuring comparable treatment of resources. This policy reflects the Commission's view that the cost of producing electricity and the value to customers of electric power varies over time and from place to place. 14 Demand response can provide competitive pressure to reduce wholesale power prices; increases awareness of energy usage; provides for more efficient operation of markets; mitigates market power; enhances reliability; and in combination with certain new technologies, can support the use of renewable energy resources, distributed generation, and advanced metering. Thus, enabling demand-side resources, as well as supply-side resources, improves the economic operation of electric power markets by aligning prices more closely with the value customers place on electric power. A well-functioning competitive wholesale electric energy market should reflect current supply and demand conditions. 14 That is, for two customers at the same time and place, one customer may prefer to reduce consumption if the price is high, and the other may be willing to pay a high price to avoid curtailment in an emergency. 17. The Commission's policy also reflects its responsibility under sections 205 and 206 of the FPA to remedy any undue discrimination and preference in organized markets. To that end, the Commission explicitly addressed demand response in its Open Access Transmission Tariff (OATT) Reform (Order No. 890) 15 and reliability standards (Order No. 693). 16 15 Preventing Undue Discrimination and Preference in Transmission Service, Order No. 890, FERC Stats. & Regs. ¶ 31,241 (2007), order on reh'g , Order No. 890-A, 73 FR 2,984 (Jan. 16, 2008), FERC Stats. & Regs. ¶ 31,261 (2007), order on reh'g , Order No. 890-B, 73 FR 39,092 (July 8, 2008), 123 FERC ¶ 61,299 (2008). 16 See Mandatory Reliability Standards for the Bulk-Power System, Order No. 693, FERC Stats. & Regs. ¶ 31,242, order on reh'g , Order No. 693-A, 120 FERC ¶ 61,053 (2007). 18. Additionally, on numerous occasions, the Commission has expressed the view that the wholesale electric power market works best when demand can respond to the wholesale price. 17 Also, the Commission has issued numerous orders over the last several years on various aspects of electric demand response in organized markets, with the goal of removing unnecessary obstacles to demand response participating in the wholesale power markets of RTOs and ISOs. 18 To that end, some of these orders approved various types of demand response programs, including programs to allow demand response to be used as a capacity resource 19 and as a resource during system emergencies, 20 to allow wholesale buyers and qualifying large retail buyers to bid demand response directly into the day-ahead and real-time energy markets and certain ancillary service markets, particularly as a provider of operating reserves, as well as programs to accept bids from ARCs. 21 The Commission also has approved special demand response applications such as use of demand response for synchronized reserves and regulation service. 22 The theme underlying the Commission's approval of these programs has been to allow demand response resources to participate in these markets on a basis that is comparable to other resources. 17 See, e.g., New England Power Pool and ISO New England, Inc., 101 FERC ¶ 61,344, at P 44-49 (2002), order on reh'g , 103 FERC ¶ 61,304, order on reh'g , 105 FERC ¶ 61,211 (2003); PJM Interconnection, LLC, 95 FERC ¶ 61,306 (2001); PJM Interconnection, LLC, 99 FERC ¶ 61,227 (2002); Southwest Power Pool, Inc., 116 FERC ¶ 61,289 (2006). 18 See, e.g., New York Indep. Sys. Operator, Inc., 92 FERC ¶ 61,073, order on clarification, 92 FERC ¶ 61,181 (2000), order on reh'g, 97 FERC ¶ 61,154 (2001); New England Power Pool and ISO New England, Inc., 100 FERC ¶ 61,287, order on reh'g, 101 FERC ¶ 61,344 (2002), order on reh'g, 103 FERC ¶ 61,304, order on reh'g, 105 FERC ¶ 61,211 (2003); PJM Interconnection, LLC, 95 FERC ¶ 61,306 (2001); PJM Interconnection, LLC, 99 FERC ¶ 61,139 (2002); PJM Interconnection, LLC, 99 FERC ¶ 61,227 (2002). 19 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). 20 See, e.g., New York Indep. Sys. Operator, Inc., 95 FERC ¶ 61,136 (2001); NSTAR Services Co. v. New England Power Pool, 95 FERC ¶ 61,250 (2001); New England Power Pool and ISO New England, Inc., 100 FERC ¶ 61,287, order on reh'g, 101 FERC ¶ 61,344 (2002), order on reh'g, 103 FERC ¶ 61,304, order on reh'g, 105 FERC ¶ 61,211 (2003); PJM Interconnection, LLC, 99 FERC ¶ 61,139 (2002). 21 See, e.g., New York Indep. Sys. Operator, Inc., 95 FERC ¶ 61,223 (2001); New England Power Pool and ISO New England, Inc., 100 FERC ¶ 61,287, order on reh'g, 101 FERC ¶ 61,344 (2002), order on reh'g, 103 FERC ¶ 61,304, order on reh'g, 105 FERC ¶ 61,211 (2003); PJM Interconnection, LLC, 99 FERC ¶ 61,227 (2002). 22 See, e.g., PJM Interconnection, LLC, 114 FERC ¶ 61,201 (2006). 19. While the Commission and the various RTOs and ISOs have done much to eliminate barriers to demand response in organized power markets, more needs to be done to ensure comparable treatment of all resources. Therefore, as discussed below, the Commission is taking action in this Final Rule to further eliminate barriers to demand response in organized power markets. 2. Ancillary Services Provided by Demand Response Resources 20. The Commission included several components in the NOPR obligating RTOs and ISOs to accept bids from demand response resources for ancillary services. First, demand response resources were required to meet necessary technical requirements established by the RTO or ISO in order to participate in these markets. Second, the Commission proposed that demand response resources be allowed to specify the frequency and duration of their service through the use of additional bidding parameters. Finally, the Commission proposed that RTOs and ISOs perform a small demand response resource assessment to evaluate the technical feasibility and value to the market of such smaller resources. Comments in response to these issues are addressed below. a. Ancillary Services Market 21. In the NOPR, the Commission proposed to obligate each RTO or ISO to accept bids from demand response resources, on a basis comparable to any other resources, for ancillary services that are acquired in a competitive bidding process, if the demand response resources: (1) are technically capable of providing the ancillary service and meet the necessary technical requirements; and (2) submit a bid under the 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. 23 The Commission stated that this proposal would apply to competitively-bid markets, if any, for energy imbalance, spinning reserves, supplemental reserves, reactive supply and voltage control, and regulation and frequency response as defined in the pro forma OATT, or to the markets for their functional equivalents in an RTO or ISO tariff. 24 23 NOPR, FERC Stats. & Regs. ¶ 32,628 at P 56. 24 Id. 22. The Commission proposed that, on compliance, an RTO or ISO must either propose amendments to its tariff to comply with the proposed requirement or demonstrate that its existing tariff and market design already satisfy the requirement. This filing would be submitted within six months of the date the Final Rule is published in the Federal Register . The Commission proposed to assess whether each filing satisfies the proposed requirement and issue additional orders as necessary. 25 25 Id. P 63. i. Comments 23. Many commenters support the Commission's proposal and agree that allowing demand response resources to participate in ancillary services markets would increase competition, enhance system reliability, and lower the overall price for ancillary services. 26 For instance, Public Interest Organizations assert that the presence of demand response in these markets will mitigate the exercise of market power and allow large amounts of variable resources ( e.g. , wind and solar) to be integrated into the grid. 27 DRAM states that allowing demand response to participate in ancillary services markets and other types of wholesale markets would lead to a more viable and sustainable demand response industry, and to the availability of a larger overall demand response resource. 28 Comverge maintains that the Commission's proposal is particularly appropriate because it enables market participants to simultaneously participate in capacity markets (or resource adequacy) and operating reserve markets. 29 DRAM and APPA, while in support of the Commission's proposal, state that demand response resources must be able to meet the appropriate technical requirements. 30 26 E.g. , American Forest at 5; BlueStar Energy at 1-2; California PUC at 9; Cogeneration Parties at 2-3; Dominion at 4; Duke Energy at 3; Integrys Energy at 9; ISO/RTO Council at 3-4; Industrial Coalitions at 9; Midwest Energy at 2-3; North Carolina Electric Membership at 3-4; NYISO at 5; Public Interest Organizations at 5-6; Reliant at 3; and Wal-Mart at 5. 27 Public Interest Organizations at 4-5. 28 DRAM at 5-6. 29 Comverge at 11. 30 DRAM at 4-5; APPA at 31-32. 24. Several commenters state that they support the Commission's clarification in the NOPR that the proposal would not require the adoption of competitive bidding processes in areas where they were not previously used. 31 APPA states that it opposes the development of new RTO or ISO markets for ancillary services just so demand response resources could participate in them. 32 Similarly, EEI asserts that this proposal should be limited to competitively-bid markets only, as defined in the proposal. 33 Comverge also agrees with the Commission's proposed requirement that this provision apply only to competitively-bid markets, but asks the Commission to include two other services within its proposal: Out-of-Market 34 and Scarcity Pricing. 35 31 NOPR, FERC Stats. & Regs. ¶ 32,628 at P 58. 32 APPA at 34-35. 33 EEI at 11. 34 It is not entirely clear what service Comverge is referring to here. It is possible that Comverge is referring to Out-Of-Market Dispatch, i.e. , RTO or ISO dispatch actions that are not reflected in the ISO's real-time market prices. In CAISO, for example, dispatchers procure energy to make up for imbalances by contacting selected resources or control area operators that chose not to submit any bids into the ISO's or RTO's markets. This practice results in bilateral trades negotiated by the RTO or ISO. 35 Comverge at 13-14. Similarly, it is not clear to the Commission what service Comverge is referring to, as Scarcity Pricing is not an ancillary service. 25. Xcel requests that the Commission clarify that the proposed rule does not require a demand response provider to offer its potential demand response into the market. 36 Xcel argues that a demand response provider should be free to evaluate its willingness to bid its offering into the market. 36 Xcel at 7. 26. In its reply comments, Allied Public Interests Groups note that providing for comparable treatment of demand-side resources in wholesale markets is critical to making those markets competitive, efficient, reliable and sustainable. Therefore, they ask the Commission to clarify the meaning and implication of the term “comparable treatment.” 37 37 Allied Public Interest Groups at 1. 27. NARUC argues that the state-law exemption within the NOPR should be modified to avoid displacing state authority and state policy decisions on demand response. 38 NARUC explains that this exemption places the burden on state regulators to show that the demand response proposal conflicts with state laws or regulations. NARUC would like to see this reversed, and the burden placed on the RTO or ISO to obtain the state regulator's permission to allow the demand response proposal. Similarly, Pennsylvania PUC states that the state exemption highlights a jurisdictional issue and recommends that the Commission continue to work with state authorities to eliminate these types of barriers to demand response. 39 38 NARUC at 7. The proposal for ancillary services market states: “The Commission proposed to obligate each RTO or ISO to accept bids from demand response resources, on a basis comparable to any other resources, for ancillary services that are acquired in a competitive bidding process, if the demand response resources (1) are technically capable of providing the ancillary service and meet the necessary technical requirements, and (2) submit a bid under the 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.” NOPR, FERC Stats. & Regs. ¶ 32,628 at P 56 (emphasis added). 39 Pennsylvania PUC at 11. 28. Some commenters recommend that each RTO and ISO should determine new rules for ancillary services. 40 Dominion states that each RTO and ISO should have flexibility to develop the necessary rules to modify existing ancillary services markets within its stakeholder processes. 41 Comverge suggests that these rules be determined by each RTO and ISO, but initially framed in a Commission technical conference, consistent with the Commission's substantive recommendations to amend RTO and ISO bidding rules. 42 SoCal Edison-SDG&E argue that an overly prescriptive national approach may be counterproductive. 43 40 See, e.g. , Comverge at 17; Dominion at 4; and SoCal Edison-SDG&E at 3. 41 Dominion at 4. 42 Comverge at 17. 43 SoCal Edison-SDG&E at 3. 29. While Midwest Energy supports the proposal, it is concerned that the quest for comparability may evolve into a program that treats demand response preferentially with respect to competitive resource providers. It states that any such preferential treatment could lead to overall increases in costs to customers through the subsidization of demand response. 44 Therefore, Midwest Energy asks that the Commission require that: (1) each RTO or ISO demand response program be subject to a net-benefits test and (2) all demand-side resources be subject to a performance evaluation. 45 44 Midwest Energy at 3. 45 Id. 30. Reliant comments that demand response resources should be subject to penalties for non-performance comparable to those that supply resources face. Reliant also states that demand response resources that supply ancillary services should participate in RTO and ISO ancillary services markets primarily via the entity that schedules and financially settles the load for their meters. 46 Allied Public Interest Groups agrees that demand response resources should face comparable penalties for non-performance, but notes in reply comments that “comparable” penalties does not mean “the same” penalties. 47 46 Reliant at 4. 47 Allied Public Interest Groups at 4. 31. Public Interest Organizations urge the Commission to expand the demand response provisions to include energy efficiency resources, environmentally benign behind-the-meter distributed generation, and all other demand-side resources that are capable of providing the service. 48 Public Interest Organizations explain in their comments that “energy efficient resources produce load reductions for the length of their measured lives, relieving congestion, reducing market costs, and increasing system reliability.” They state that “a bundle of energy efficient resources that reduces energy use on a large scale—an `efficiency power plant' or EPP—can achieve energy savings that are just as predictable and substantial as the energy output of a conventional power plant. The consistent savings from these energy efficiency programs and investments can be thought of as a virtual power plant.” 49 Allied Public Interest Groups assert that the comparable treatment proposed for demand response in the NOPR should be expanded to cover all reliable and efficient demand response resources that are technically capable of providing the service needed. Allied Public Interest Groups notes that limiting participation in ancillary services markets to “traditional” demand response resources may unintentionally exclude innovative new technologies that can help achieve goals of system reliability and efficiency. 50 48 Public Interest Organizations at 4. 49 Id . at 13-14. 50 Allied Public Interest Groups at 7. 32. TAPS asserts that behind-the-meter generation can perform as a demand resource in ancillary services markets. TAPS states that the regulatory language should be modified to include this type of resources as well as reliability-based demand response. They note that reliability-based demand response, or demand response that is not in reaction to an increase in the price of electric energy or to incentive payments, is currently not included in the regulatory definition of Demand Response contained within this proceeding. 51 51 TAPS at 9. 33. Some supporters state that the Commission should address in the Final Rule compensation for demand response resources. For instance, Industrial Consumers suggest that the payment structure for demand response resources should be comparable to the payment of a generator. 52 They also note that to promote the development of demand response resources and fairly compensate these resources for their ancillary services, a methodology for calculating and accurately representing customer baselines must be developed on a consistent basis. 53 EnerNOC agrees and asks the Commission to require RTOs and ISOs to demonstrate in future compliance filings that customer baseline methodologies appropriately address concerns of accuracy, integrity, and comparable treatment of demand response resources. 54 52 Industrial Consumers at 13. 53 Id. at 14. 54 EnerNOC at 11. 34. E.ON U.S. does not support the Commission's proposal. E.ON U.S. believes that the Commission's proposal mandates the purchase of demand response products regardless of price, and that such a practice will distort the market and create additional costs for end-use customers. 55 E.ON U.S. argues that the Commission should only require comparable treatment of demand response resources and not place any extra emphasis or incentive on their use. 55 E.ON U.S. at 14. 35. Several commenters request that the Commission develop a pro forma tariff regarding demand response participation in ancillary services markets. Industrial Consumers argue that the Commission should prescribe specific pro forma tariff language for RTOs and ISOs to adopt within 30 days of the Final Rule's effective date. Otherwise, they assert that piecemeal implementation by RTOs and ISOs may result in delay, inefficiency, and inconsistency. 56 Similarly, Industrial Coalitions state that the Commission should incorporate into a pro forma demand response tariff appropriate minimum standards to enable demand response resources to provide, and be comparably compensated for, ancillary services. Industrial Coalitions and Steel Manufacturers contend that the Commission should obligate RTOs and ISOs to demonstrate that their own tariffs are consistent with or superior to the pro forma provisions and any deviations from the pro forma tariff should only be permitted if they can provide a clear justification for doing so. 57 56 Industrial Consumers at 7-8. Industrial Consumers note that the Commission's practice extending back to Order No. 888 has been to standardize rules and procedures for generators and other transmission users with the pro forma OATT as necessary to promote consistency and to avoid undue discrimination. Id . 57 Industrial Coalitions at 11; Steel Manufacturers at 10. 36. A few commenters express concern about the Western Electricity Coordinating Council's (WECC) regional reliability standard addressing operating reserve requirements because WECC currently allows demand response to supply only non-spinning reserves. 58 For example, CAISO points out that WECC's standard is inconsistent with the Commission's directive in Order No. 890 that a transmission provider must permit non-generation resources to provide ancillary services to the extent they are capable of doing so. It argues that WECC is non-compliant with Order No. 693, which includes a requirement explicitly providing that demand-side management may be used as a resource for contingency reserves. Therefore, CAISO comments that the Commission should direct the Electric Reliability Organization (ERO) to effect a change in WECC requirements. 59 58 California DWR at 8; CAISO at 5; California PUC at 9-10; and PG&E at 6 -7. 59 CAISO at 5; see also California PUC at 10. 37. Several entities ask that the Final Rule not disturb or replace ongoing proceedings in individual regions. Midwest ISO states that the Commission recently approved its integration of demand response resources to participate in Midwest ISO ancillary services markets, on a basis comparable to other resources (ASM Proposal). 60 Given this, Midwest ISO requests that the Commission find that its ASM Proposal satisfies the NOPR's requirement that each RTO and ISO submit for Commission approval standards by which demand response resources are able to participate and bid in the ancillary service markets on comparable terms as other resources. 61 CAISO states that it will comply with the NOPR requirement in the Release 1A enhancements to its Markets Redesign & Technology Upgrade (MRTU). 62 It asks the Commission to clarify that it does not intend to replace the specific schedule that it has accepted for the CAISO's implementation of MRTU with the generic compliance schedule proposed in the NOPR. 63 60 Midwest Independent Transmission System Operator, Inc. , 112 FERC ¶ 61,283 (2005), order on reh'g , 123 FERC ¶ 61,297 (2008) (ASM Order). 61 Midwest ISO at 9. 62 Cal. Indep. Sys. Operator Corp. , 116 FERC ¶ 61,274 (2006), order on reh'g , 119 FERC ¶ 61,076 (2007). 63 CAISO at 2-4. 38. In addition, while Maine PUC agrees that demand response is important to the efficient functioning of wholesale electric markets, it states that the Commission should allow ISO New England to work with state regulators and NEPOOL Participants to make existing programs more robust and to eliminate barriers to demand response participation. 64 Maine PUC notes that demand response programs in New England are achieving price savings and reducing the need for additional generation and transmission, demonstrated by the significant participation of demand response resources in the forward capacity market. Therefore, Maine PUC states that the Commission should not impose the NOPR's specific requirements for demand response on ISO New England. 64 Maine PUC at 3-4. 39. SPP states that it does not currently have an ancillary services market; however, it reports that consideration and incorporation of demand response in future market development is currently being undertaken by SPP's Working Groups and Task Forces. 65 65 SPP at 5. 40. Alcoa maintains that the Commission's proposal is well-intended, but falls short of what is needed to ensure non-discriminatory treatment of demand response bids by industrial customers. Alcoa asserts that the Commission's proposal is incomplete because it relies too heavily on vague concepts such as comparability of resources and reasonable requirements to increase access to ancillary services. Alcoa argues that there should be no restriction on the amount of participation by demand response resources in organized wholesale markets, and suggests that, at a minimum, regional operators should be required to justify such restrictions to the Commission and demonstrate that they are necessary for technical reasons. 66 66 Alcoa at 2-3. 41. Several commenters support the Commission's conclusion that it is not appropriate for the Commission to develop a standardized set of technical requirements. 67 California PUC stresses the importance of allowing RTOs and ISOs the flexibility to modify requirements in the future, as experience is gained with demand response programs. EEI believes that standardization of these requirements could result in unnecessary expense and delay in implementation by requiring incompatible infrastructure across different RTOs and ISOs. EnerNOC believes that the Commission struck the appropriate balance by requiring coordination among the RTOs and ISOs without mandating standardization. 67 E.g. , California PUC at 9; EEI at 12; EnerNOC at 9; NYISO at 6; and North Carolina Electric Membership at 4. 42. North Carolina Electric Membership states that the Commission should require RTOs and ISOs to develop technical requirements in conjunction with stakeholders to ensure that all interests are properly considered. Old Dominion also states that any standards developed in response to the Commission's requirement should be comprehensive and result from a stakeholder process. 43. LPPC supports the Commission's recognition that demand response resources must be technically capable of providing ancillary services. In addition, LPPC agrees with the Commission's statement that RTOs and ISOs need to impose requirements on telemetry and metering to allow demand response resources to fully participate in ancillary services markets. LPPC adds that an important element of any RTO-or ISO-led ancillary services program must be performance monitoring to ensure that demand response resources truly respond when called upon. 68 Also, Old Dominion argues that the ability to accurately measure and verify demand response is necessary to guarantee that these resources are providing real benefits to the market. 69 68 LPPC at 6-7. 69 Old Dominion at 7. 44. APPA supports the Commission's overall proposal, but states that the Commission should recognize that metering, telemetry and performance requirements that may have to be imposed on demand-side resources to ensure their reliable performance will be more stringent than the requirements most retail customers are used to accommodating. APPA questions whether end-use customers will offer ancillary services that may require them to reduce consumption substantially on very short notice. APPA asserts that program participants may drop out when called upon too frequently. APPA states that it may prove difficult to reconcile the rigorous technical requirements for end users necessitated by the instantaneous nature of certain ancillary services with the desire of many larger loads for reliability, flexibility and convenience. 70 70 APPA at 33-34. 45. NYISO recommends that the Final Rule clarify the NOPR's proposed regulatory language to specify that demand response resources must also meet applicable reliability requirements before they are permitted to bid into markets. 71 NYISO states that this language would clearly articulate the Commission's support for the integration of demand resources into ancillary services markets without overriding requirements adopted by NERC or the New York State Reliability Council. Further, it notes that this approach would be consistent with Order 890-A, which allows RTOs and ISOs to adopt reasonable reliability related limitations on demand resource participation. 72 71 NYISO at 5-6. 72 Id. at 6 (citing Order No. 890-A, 73 FR 2984 (Jan. 16, 2008), FERC Stats. & Regs. ¶ 31,261 at P 499). 46. Comverge requests that the Commission ensure that any requirements imposed on demand response resources are not overly technical and burdensome. 73 California PUC states that telemetry, for example, is necessary for resources offering ancillary services, but a telemetry requirement for every participant (such as small commercial and residential customers) may be excessive and could erect a barrier to entry for these smaller customers, particularly when not every demand response supplier has the money to install real-time telemetry and metering. 74 EnerNOC also mentions this concern, and asks that the Commission clarify that its “reasonableness” requirement is aimed at ensuring that reasonable technical requirements not be unduly restrictive on demand response resources, such as those that may add unwarranted and unnecessary costs to participation. EnerNOC states that technical standards should focus on the reliability parameters of the particular ancillary service and allowing demand response resources to utilize alternative methods to meet these standards. 75 73 Comverge at 13. 74 California PUC at 11. 75 EnerNOC at 10-11. ii. Commission Determination 47. In this Final Rule, the Commission adopts the NOPR proposal to require each RTO or ISO to accept bids from demand response resources, on a basis comparable to any other resources, for ancillary services that are acquired in a competitive bidding process, if the demand response resources: (1) are technically capable of providing the ancillary service and meet the necessary technical requirements; and (2) submit a bid under the generally-applicable bidding rules at or below the market-clearing price, unless the laws or regulations of the relevant electric retail regulatory authority do not permit a retail customer to participate. All accepted bids would receive the market-clearing price. 48. The Commission's policy has been, and continues to be, to identify and eliminate barriers to participation of demand response resources in organized power markets. Development of demand response resources provides benefits to consumers by providing competitive pressure to reduce wholesale power prices, providing for the more efficient operation of organized markets, helping to mitigate market power and enhance system reliability, and encouraging development and implementation of new technologies, including renewable energy and energy efficiency resources, distributed generation and advanced metering. The reforms implemented in this Final Rule will benefit energy consumers by removing several barriers to the development and use of demand response resources in organized wholesale electric power markets. 49. As noted in the NOPR, this requirement would apply to competitively-bid markets, if any, for energy imbalance, spinning reserves, supplemental reserves, reactive supply and voltage control, and regulation and frequency response as defined in the pro forma OATT, or to the markets of their functional equivalents in an RTO or ISO tariff. 76 The Commission requires that demand response resources that are technically capable of providing the ancillary service within the response time requirements, 77 and that meet reasonable requirements adopted by the RTO or ISO as to size, telemetry, metering and bidding, be eligible to bid to supply energy imbalance, spinning reserves, supplemental reserves, reactive and voltage control, and regulation and frequency response. 78 76 NOPR, FERC Stats. & Regs. ¶ 32,628 at P 56. 77 Some technologies may be capable of responding to an RTO's or ISO's control signal and providing certain ancillary services, such as regulation and frequency response service, more quickly than under existing response time requirements. 78 The RTO or ISO may specify certain requirements, such as registration with the RTO or ISO, creditworthiness requirements, and certification that participation is not precluded by the relevant electric retail regulatory authority. The RTO or ISO should not be in the position of interpreting the laws or regulations of a relevant electric retail regulatory authority. 50. In response to Allied Public Interest Groups, we decline to define “comparable treatment.” Each RTO and ISO is unique, and the Commission hesitates to impose a uniform definition. Each RTO and ISO therefore should establish policies and procedures in cooperation with its customers and other stakeholders that ensure that demand response resources are treated comparably to supply-side resources. The Commission will have ample opportunity to evaluate concerns that may arise when it reviews the compliance filings required by this Final Rule. 51. In light of APPA's comments, we clarify that this requirement applies only to competitively-bid markets for those ancillary services specified, as well as to the markets of their functional equivalents in an RTO or ISO tariff. This requirement does not obligate RTOs or ISOs to create new competitively-bid ancillary services markets. 52. In response to Xcel and E.ON U.S., we note that the Commission proposed in the NOPR to obligate RTOs and ISOs to accept bids from demand response resources on a comparable basis to supply resources for ancillary services. For Xcel, we clarify that demand response providers are not required to offer potential demand response into the ancillary services markets. Demand response resources may evaluate market prices and other factors before making a determination to bid or not. Regarding E.ON U.S.'s comments, the Commission did not propose (and does not require) that RTOs or ISOs must purchase ancillary services from demand response resources without regard to whether these resources are lower-bid alternatives to supply resources. 53. In response to NARUC and others who comment that the Commission's proposal would place the burden on retail regulatory authorities to show that a demand response proposal conflicts with state or local laws or regulations, we clarify that we will not require a retail regulatory authority to make any showing or take any action in compliance with this rule. 79 Rather, this rule merely requires an RTO or ISO to accept bids for ancillary services from demand response resources, unless the laws or regulations of the relevant electric retail regulatory authority do not permit a retail customer to participate. 79 In reply to the Pennsylvania PUC's recommendation that the Commission continue to work with state authorities to eliminate barriers to demand response, we note that NARUC and the Commission, through their Demand Response Collaborative, are working to outline options to coordinate retail and wholesale regulatory policies in order to stimulate participation in demand response by reducing or eliminating jurisdictional barriers. 54. We disagree with commenters who argue that requiring RTOs and ISOs to allow demand response resources to participate in ancillary services markets may be counterproductive or unnecessary. 80 This requirement removes a barrier to participation of demand response resources in organized wholesale markets and allows these resources to provide ancillary services on a basis comparable to generation sources. This requirement would potentially expand the resource pool in these organized markets, thereby lowering the overall market price for ancillary services, as well as potentially mitigating the exercise of market power. The competitiveness within ancillary services markets, as well as the system reliability, would be enhanced through increased participation. 80 The Commission has approved actions by some RTOs and ISOs to incorporate demand response into their ancillary services markets. See , e.g. , California Indep. Sys. Operator , 116 FERC ¶ 61,274 (2006); PJM Interconnection, LLC , 114 FERC ¶ 61,201 (2006). 55. Contrary to Midwest Energy's comments, we do not find that this requirement will lead to any preferential treatment for demand response resources or supply-side resources. Both sets of resources would be treated and penalized comparably in instances of non-performance. 56. In response to Public Interest Organizations, the Commission has not excluded from eligibility any type of resource that is technically capable of providing the ancillary service, including a load serving entity's (LSE) or eligible retail customer's behind-the-meter generation or any other demand response resource. Further, the Commission appreciates the value of energy efficiency, and is aware of RTO and ISO efforts to integrate energy efficiency into organized markets. Nothing in this rule precludes an RTO or ISO from appropriately including energy efficiency into any of its markets. The Commission did not propose to include energy efficiency as a provider of competitively procured ancillary services, and does not have an adequate record to address this issue here. 57. With regard to Industrial Consumers' and EnerNOC's comments requesting the resolution of customer baseline issues, the Commission agrees that customer baselines are an important factor in the appropriate compensation for demand response resources. Customer baselines are designed to depict, as accurately as possible, a customer's normal load on a given day. Establishing this baseline helps system operators to measure and verify load reductions, thus giving RTOs and ISOs the ability to not only determine if demand response resources showed up, but also what the proper value of the demand reduction should be. Many RTOs and ISOs currently establish such bidder baselines as part of their demand response programs, or they are working with their stakeholders to modify such methodologies. Accordingly, RTOs and ISOs should describe in their compliance filings their efforts to develop adequate customer baselines. 58. Regarding comments related to WECC's provisions for demand response resources in its reliability standards, we note that this rule requires comparable treatment for demand response resource participation in ancillary services markets. This is a general rulemaking and is not the proper venue for adjudicating the alleged issue regarding WECC's regional reliability standards. 81 81 Concerns regarding WECC's regional reliability standards can be addressed by filing a complaint under section 206 of the FPA, 16 U.S.C. 824e, or by filing a notice under section 215 of the FPA, 16. U.S.C. 824o. Under section 215, “[i]f a user, owner or operator of the transmission facilities of a Transmission Organization determines that a [r]eliablity [s]tandard may conflict with a function, rule, order, tariff, rate schedule, or agreement accepted, approved, or ordered by the Commission * * *. the Transmission Organization shall expeditiously notify the Commission * * *.” 18 CFR 39.6. 59. In response to comments, the Commission again finds that it is not appropriate in this rulemaking to develop a standardized set of technical requirements for demand response resources participating in ancillary services markets. Instead, the Commission will allow each RTO and ISO, in conjunction with its stakeholders, to develop its own minimum requirements. However, as proposed in the NOPR, the Commission will require RTOs and ISOs to coordinate with each other in the development of such technical requirements, and provide the Commission with a technical and factual basis for any necessary regional variations. 82 In addition, having RTOs and ISOs work in conjunction with stakeholders as well as with each other should ensure that any developed requirement is not so full of technical detail or so burdensome that it discourages demand response resource participation. 82 NOPR, FERC Stats. & Regs. ¶ 32,628 at P 64. 60. With respect to NYISO's request that the Commission clarify its proposed regulatory language to specify that demand response resources must also meet “applicable reliability requirements,” the Commission does not see a need to include this provision in this Final Rule. To do so would merely duplicate existing regulations that require reliability standards, and that set out certain reliability requirements. This duplication would serve no useful purpose. 61. As part of the compliance filing to be submitted within six months of the Final Rule, each RTO or ISO is required to file a proposal to adopt reasonable standards necessary for system operators to call on demand response resources, and mechanisms to measure, verify, and ensure compliance with any such standards. These standards would be subject to Commission approval. 62. The Commission is mindful of the progress being made in California with MRTU and in the Midwest ISO with its ASM Order. Our requirement is that, where there are markets for acquiring ancillary services, these markets must be open to qualified demand response bidders. This requirement allows each RTO or ISO to work with stakeholders to develop the appropriate implementation rules for its own market design. This approach allows for regional variation and should alleviate the concerns of Midwest ISO, CAISO, and Maine PUC. 63. The Commission will not now rule on CAISO's request that the Commission not interfere with its current timeline to implement MRTU, or Midwest ISO's request that the Commission find Midwest ISO already satisfies the proposed requirements through its ASM Proposal. CAISO and Midwest ISO must submit, within their respective compliance filings, a description of how their current activities comply with the requirements of this Final Rule. Upon review, the Commission will determine if further action on behalf of either RTO or ISO is necessary. b. New Bidding Parameters 64. The Commission proposed to require RTOs and ISOs to allow demand response resources to specify limits on the frequency and duration of their service in their bids to provide ancillary services—or their bids into the joint energy-ancillary services market in the co-optimized RTO markets. 83 These limits would include a maximum duration for dispatch, a maximum number of times per day that demand response resources could be called, or a maximum amount of energy per day or week that a resource can produce. 83 Id. P 62. 65. The Commission requested comment on this proposed requirement and whether these new parameters should be available for all bidders, not just for demand response resources. Further, the Commission intended that the bidding parameters would be implemented by all RTOs and ISOs, and proposed to require them to confer with each other and to provide a technical and factual basis for any necessary regional variations. i. Comments 66. Most commenters support the Commission's proposal to require RTOs and ISOs to incorporate new parameters into their bidding rules to allow demand response resources to specify in their bids the duration and frequency of their service. 84 For instance, several commenters state that allowing new bidding parameters would increase the number and type of demand response resources participating in the ancillary services markets. 85 Some commenters note that generators face certain constraints (including start-up costs, ramp rates, and limits on the number of hours that they may operate efficiently), which are reflected within their bids. They assert that allowing demand response resources to specify similar constraints within their bids is consistent with the Commission's principle of comparability between demand-side and supply-side resources. 86 DC Energy states that, similar to generators, demand response providers should have the choice to observe market signals and make an informed decision on whether to bid into these markets. 87 84 E.g., Ameren; American Forest; APPA; BlueStar Energy; Beacon Power; Mr. Borlick; BP Energy; California DWR; California PUC; Cogeneration Parties; Comverge; DC Energy; Detroit Edison; DRAM; Duke Energy; EEI; EnergyConnect; EnerNOC; Exelon; FTC; First Energy; Industrial Coalitions; Industrial Consumers; ISO New England; ISO/RTO Council; Midwest ISO; North Carolina Electric Membership; Ohio PUC; Old Dominion; Organization of Midwest ISO States; PG&E; Public Interest Organizations; Reliant; Steel Producers; TAPS; Wal-Mart; and Xcel. 85 E.g., American Forest at 5; Exelon at 5. 86 American Forest at 5; Cogeneration Parties at 3; DRAM at 6-7; Duke Energy at 3-4; Exelon at 5-6; FTC at 25-27; FirstEnergy at 7; Industrial Consumers at 12; ISO/RTO Council at 4; North Carolina Electric Membership at 4; Old Dominion at 8; and Public Interest Organizations at 6. 87 DC Energy at 4. 67. The ISO/RTO Council asserts that the implementation of these new bidding parameters must be done in a way that assures demand response resources participating in ancillary services markets meet the same product requirements as supply-side resources. 88 Several commenters express their support for this concept provided that demand response resources are not afforded an undue advantage over supply-side resources. 89 88 ISO/RTO Council at 4. 89 E.g., Old Dominion at 8; Reliant at 4; and Wal-Mart at 5. 68. Two commenters state that they support the proposal provided that certain conditions are met. Ameren states there should be no adverse effect on system reliability and that any market rules that provide this flexibility should be limited in scope so as to avoid the potential for gaming. 90 BP Energy agrees with the Commission's proposal only to the extent that bidding parameters submitted by demand response resources can be incorporated into the RTO and ISO software in a cost effective manner while maintaining the algorithm's ability to perform timely cost minimizing optimizations. 91 90 Ameren at 18. 91 BP Energy at 14. 69. ISO New England supports granting individual demand response resources the opportunity to specify additional bidding parameters, but notes that such specification may limit the resource's qualification (under market rules) on an individual basis to bid to supply operating reserves. 92 However, ISO New England itself notes that demand response aggregators should be in a position to formulate bids combining individual demand resources so as to be able to meet the reserves market's availability requirements in a manner comparable to that of generation. 92 ISO New England at 5. 70. Duke Energy notes that the NOPR proposal would allow demand response resources to manage the risk that they would be called upon too frequently or for too long a period relative to their individual constraints. In that respect, Duke Energy asserts that if RTOs and ISOs are not required to account for such bid flexibility, demand resources could potentially be eliminated from the ancillary services markets through voluntary means. 93 Duke Energy argues that without any knowledge of how and when they will be used, demand resources may view the ancillary services markets as too risky and, therefore, not participate in them. APPA states that large end-use customers' desire to reduce consumption on short notice decreases the more frequently they are called upon. 94 93 Duke Energy at 3-4. 94 APPA at 36-37. 71. Steel Producers asserts that demand response resources' unique characteristics need to be taken into account, and recommends that the Commission require RTOs and ISOs to allow, at a minimum, the following optional bidding parameters in addition to the three mentioned in the NOPR: (1) Minimum notice requirement; (2) minimum/maximum shut-down time; (3) minimum duration for dispatch; (4) targeted demand reduction level; (5) bids “down to” a designated megawatt level; and (6) guaranteed minimum LMP. 95 95 Steel Producers at 4-5. 72. Similarly, California PUC requests that the Commission expand its proposal to include all demand response resource bids in all aspects of wholesale markets, and also permit each demand resource bidder to submit, as part of its bid and a master file, its output constraints such as minimum load reduction, minimum load, load reduction initiation time, minimum load reduction time, maximum load reduction time, minimum base load time, maximum number of daily load curtailments, minimum and maximum daily energy limits, load pick up rate, load drop rate, load reduction initiation cost, and minimum load reduction cost. 96 96 California PUC at 13-14. 73. Multiple commenters argue for a regional approach in implementing the Commission's proposal. 97 For instance, EEI and Detroit Edison state that they support the Commission's proposal provided that RTOs and ISOs can establish lower or minimum limits for such service. 98 EEI asks that RTOs and ISOs be allowed to specify the minimum duration in hours or minimum number of times per day or week that a resource may be called upon. Duke Energy states that the specific bid parameters, as well as the methodologies and procedures that RTOs and ISOs use to implement the Commission's proposal, should be developed on a regional basis within their stakeholder processes, rather than through a Commission-imposed uniform requirement in the Final Rule. 99 NYISO also contends that a regional approach is appropriate because specifying bidding parameters in the regulations may prove problematic in the future as regional market designs continue to evolve. 100 Exelon agrees with the Commission that minimum requirements for bidding parameters should not be prescribed by the Commission in this rulemaking, but rather should be developed by RTOs and ISOs. Exelon also supports the Commission's proposed requirement that RTOs and ISOs provide justification for any necessary regional variations. 101 EnerNOC believes the Commission, by requiring coordination and justification for variations, without mandating standardization, has articulated the correct compromise. 102 97 E.g., EEI; Detroit Edison; Duke Energy; ISO/RTO Council; North Carolina Electric Membership; NYISO; and Kansas CC. 98 EEI at 13; Detroit Edison at 2-3. 99 Duke Energy at 4. 100 NYISO at 6. 101 Exelon at 6. 102 EnerNOC at 9. 74. Midwest ISO and CAISO state that their market designs already satisfy the NOPR's proposed bidding parameters requirement. Midwest ISO states that it developed its bidding parameters through the stakeholder process and that the parameters were approved by the Commission within its ASM Order. 103 Therefore, Midwest ISO asks that the Commission find that its ASM proposal satisfies the NOPR's requirement regarding bidding parameters. Similarly, CAISO states that it is developing its ancillary services market and it will comply with the proposed bidding parameters in the Release 1A enhancements to MRTU. 104 103 Midwest ISO at 10. Midwest ISO states that its tariff allows market participants (both generators and demand response resources) to specify hourly ramp rates, hourly economic minimum and maximum limits, hourly regulation minimum and maximum limits, minimum and maximum run times, as well as a maximum start-up limit, which establishes the maximum number of times the resource can be called upon within a twenty-four-hour period. 104 CAISO at 2. 75. Further, several commenters support making additional parameters available for all bidders, to include both demand and supply resources. 105 Wal-Mart states that comparable rules could apply to supply resources as long as neither supply nor demand resources are provided with an advantage. 106 Old Dominion states that all resources bidding into the ancillary services markets should be susceptible to the same penalties, performance and reliability requirements. 107 Exelon states that as long as the specification of operational limitations does not impair market efficiency, demand and supply resources should be treated on a comparable basis because they provide reliable and efficient capacity to RTOs and ISOs. 108 105 E.g., California DWR at 12; Duke Energy at 4; EEI at 14; EnerNOC at 8; Exelon at 6; Midwest ISO at 10; Reliant at 4; and Wal-Mart at 5. 106 Wal-Mart at 5. 107 Old Dominion at 8. 108 Exelon at 5-6. 76. The California DWR supports making new parameters available to all resources because certain facilities have a specific purpose that is distinct from sales to, or support of, the electric grid. For instance, hydroelectric generation sites must satisfy water storage, water delivery, and related operational requirements. The California DWR asserts that any RTO or ISO requirements must accommodate this primary purpose for these resources. 109 109 California DWR at 12-13. 77. Several commenters state that new bidding parameters should not be available to all resources. 110 For instance, TAPS states that there is already ample bidding flexibility for generators, and it is concerned about the possibility of creating unintended consequences such as new gaming opportunities. APPA states that RTO and ISO ancillary services markets are already complex and accommodating additional bid parameters for generators in their software and problem solving algorithms would make the markets even more complicated. Although EEI is in agreement with making new bidding parameters available for all bids, it is concerned that applying the new parameters to generation resources without evaluating the implications could result in creating unintended incentives. Therefore, EEI suggests that RTOs and ISOs should not be required to apply the new parameters across all generating resources as long as they provide justification for treating some generating resources differently. 110 E.g., APPA at 37; Mr. Borlick at 2; and TAPS at 8. 78. Finally, among the supporters of this proposal, EEI states that the addition of new parameters to bidding rules must not result in any fundamental change to existing market designs or affect the efficiencies of co-optimized markets. 111 111 EEI at 14. 79. Several commenters state that demand response providers should be allowed to sell into the ancillary services markets without being required to sell into the energy market. 112 Comverge is in favor of this, but notes that demand response providers should also be allowed to sell into the energy market on a voluntary basis. Beacon Power states that a generator is always capable of supplying energy and, therefore, does not face the financial risks and barriers that a non-generator faces if it is forced to bid into the energy market. 112 E.g., Beacon Power at 9; Comverge at 12; and Wal-Mart at 5. 80. NEPOOL Participants opposes the Commission's proposal to implement new bidding parameters for demand response resources. NEPOOL Participants states that each region needs an opportunity to evaluate this issue more fully and consider whether bidding limits are the most appropriate solution and whether such limits or other reforms should be restricted to just demand response or include other kinds of resources. It asserts that any change in bidding requirements needs to ensure comparability with others resources and that system reliability is maintained. 113 Maine PUC agrees. 114 113 NEPOOL Participants at 11-12. 114 Maine PUC at 3-4. ii. Commission Determination 81. The Commission determines that each RTO and ISO is required to allow demand response resources to specify limits on the duration, frequency and amount of their service in their bids to provide ancillary services—or their bids into the joint energy-ancillary services markets in the co-optimized RTO markets. As noted in the NOPR (and several commenters agree), these limits are comparable to the limits generators may specify on price, quantity, startup and no-load costs, and minimum downtime between starts. 115 All RTOs and ISOs must incorporate new parameters into their ancillary services bidding rules that allow demand response resources to specify a maximum duration in hours that the demand response resource may be dispatched, a maximum number of times that the demand response resource may be dispatched during a day, and a maximum amount of electric energy reduction that the demand response resource may be required to provide either daily or weekly. 115 NOPR, FERC Stats. & Regs. ¶ 32,628 at P 62. 82. This requirement eliminates a major barrier to participation of demand response resources in ancillary services markets by ensuring that demand response resources are treated comparably to supply-side resources. In this regard, the Commission agrees with comments from APPA, Duke Energy, and others that argue that the desire of many end-use customers to reduce their consumption levels on short notice may decrease the more frequently they are called upon. This requirement would allow those customers to limit the frequency with which they are called upon to reduce demand, and thus make it more economically beneficial for these resources to participate in ancillary services markets. 83. The Commission's requirement also enhances competition within ancillary services markets. With demand response resources able to specify the duration, frequency and amount of their service, ancillary services markets will become more attractive for such resources. Increased participation in the market will result in an expanded pool of available resources, thereby potentially improving demand elasticity and system reliability, as well as lessening price volatility. 84. The Commission also finds that this requirement removes barriers to the comparable treatment of demand-side and supply-side resources. Generators include operational constraints in their bids, and permitting demand response resources to do the same results in the comparable treatment of both supply-side and demand-side resources. However, in keeping with this effort of greater comparability, the Commission determines that implementation of its requirement by RTOs and ISOs should not lead to either demand-side or supply-side resources being afforded an undue advantage within ancillary services markets. 85. In the NOPR, the Commission requested comment on whether other bidding parameters should be considered. 116 The Commission noted that any proposed parameters must not have the effect of creating an undue preference for demand response resources. The Commission does not have a sufficient record here to assess whether the proposed additional bidding parameters submitted by the California PUC and Steel Producers may offer demand response resources greater flexibility within their bids as compared to the bids of generators. For this reason the Commission will not accept the proposed additional bidding parameters on a generic basis for all RTOs and ISOs in this rulemaking. Rather, individual RTOs and ISOs are free to propose additional parameters in their compliance filings, as long as they do not provide undue preference to demand response resources vis-a-vis supply-side resources, and interested persons may raise these additional parameters with their deliberations with the individual RTOs and ISOs. 116 Id. P 64. 86. In the NOPR, the Commission stated that it was not appropriate for the Commission to develop in a rulemaking a standardized set of minimum requirements for minimum size bids, measurement, telemetry and other factors, and instead allowed RTOs and ISOs to develop their own minimum requirements, including bidding parameters. 117 The Commission adopts this position in this Final Rule. RTOs and ISOs must incorporate bidding parameters that allow demand response resources to specify limitations on the duration, frequency and amount of their service. However, the development of specific parameters and the methods used to implement the Commission's requirement are the responsibility of the RTOs and ISOs, in consultation with their respective stakeholders. RTOs and ISOs are also required to confer with each other on such parameters and methods and to provide a technical and factual basis for any necessary regional variations. This approach adequately accounts for regional variation between the RTOs and ISOs and alleviates the concerns of those commenters requesting regional flexibility in implementing the Commission's requirement. 117 Id. 87. Midwest ISO asks that the Commission find that it already complies with the additional bidding parameters requirement of the Final Rule. Similarly, the California ISO asserts that it will also be compliant with the requirement upon Release 1A in its MRTU process. The Commission does not intend to interrupt the progress being made in either region. However, as indicated above, the Commission will not at this time determine that either region satisfies the Commission's requirement obligating RTOs and ISOs to incorporate new bidding parameters for demand response resources, and instead will wait until each region submits its necessary compliance filing. 88. In the NOPR, the Commission requested comment on whether these additional parameters should be available for all bids, or for demand response bids only. In light of the comments received, the Commission determines that new requirements for bidding rules allowing demand response resources to specify the duration, frequency and amount of their service pertain only to demand response resources. Individual RTOs and ISOs are free to propose to apply them more broadly. While the Commission understands that making these new parameters available for all resources could benefit hydropower resources and other environmentally restricted, or run-time limited resources, the Commission agrees with TAPS and others that there is already sufficient bidding flexibility afforded to generators, and is concerned about the possibility of creating unintended consequences. For these reasons, at this time the Commission will not require an RTO or ISO to make these new bidding parameters available for all resources. 89. With regard to comments that demand response providers should be allowed to sell into the ancillary services markets without being required to sell into the energy market, the Commission notes that the ANOPR proposal permitting such action was removed at the NOPR stage, and replaced with a proposal to allow demand response resources to specify limitations on the duration, frequency and amount of their service. 118 The Commission had received comments previously that argued that allowing demand response resources to bid into the ancillary services markets without also bidding into the energy markets could upset certain market efficiencies in co-optimized markets. Therefore, the Commission put forth a compromise proposal, which allows demand response resources to specify operational limits in their bids as a way for these resources to minimize the risk that they are called on too frequently, thereby making participation in ancillary services markets more feasible. No one has persuaded us otherwise; therefore, the Commission will adopt this provision from the NOPR. 118 Id. P 62. c. Small Demand Response Resource Assessment 90. The NOPR proposed to direct RTOs and ISOs to assess the value and technical feasibility of small demand response resources providing ancillary services one year from the effective date of the Final Rule, including whether (and how) smaller demand response resources can reliably and economically provide operating reserves through pilot projects or other mechanisms. 119 119 Id. P 59. i. Comments 91. Several commenters support the NOPR proposal for small demand response resource assessment. 120 For example, Reliant states that accommodating smaller demand response resources may result in an increase in operating reserves. 121 EnerNOC believes that the assessment effort will reveal ways for smaller demand response resources to provide ancillary services while maintaining reliable operations and appropriate measurement and verification. 122 APPA believes that pilot programs could be particularly valuable in assessing technical feasibility of accommodating smaller demand-side resources. 123 It notes that accurate metering and telemetry would be significant factors in any efforts associated with this assessment, primarily because “communication and operational performance standards applicable to demand-side resources are more demanding than the current requirements applicable to retail customers.” Public Interest Organizations request that “RTOs and ISOs be directed to specifically address the issue of comparable treatment of smaller loads.” 124 Allied Public Interest Groups believe that the Commission should include in its Final Rule a directive to RTOs and ISOs to initiate pilot programs for small demand response resources similar to the ISO New England Demand Response Reserves Pilot Program. 125 In their view, pilot programs aid grid operators in determining whether a diverse portfolio of demand response resources that includes small resources can provide cost-effective and reliable ancillary services. 120 E.g. , APPA, Public Interest Organizations, EnerNOC; DRAM; Old Dominion; and Reliant. 121 Reliant at 4. 122 EnerNOC at 3. 123 APPA at 35. 124 Public Interest Organizations at 6. 125 Allied Public Interest Groups at 9. 92. EnerNOC and DRAM indicate that technical requirements for demand response participation in ancillary services markets may act as a barrier if the technical requirements exceed what is necessary to ensure reliable electric system operations. 126 For example, they note that certain telemetry requirements may preclude smaller loads from participating in ancillary services markets. However, EnerNOC states that an assessment on how to accommodate these resources could result in reasonable standards for smaller loads that take into account the operational characteristics of such loads so as to capture their value efficiently. DRAM states that the proposed assessment should allow parties to focus on how best to modify the requirements for small demand response resource participation without creating a bias against supply-side resources. 127 Neither EnerNOC nor DRAM suggests that smaller demand response resources be allowed to participate in these markets with less stringent standards than other resources. Further, EnerNOC asserts that the small demand response resource assessment requirement should not be used as an excuse to delay currently underway pilot programs or other smaller resource reforms taking place in RTOs and ISOs. In addition, this requirement should not create an opportunity to avoid addressing barriers to smaller resource participation in ancillary services markets. 128 126 EnerNOC at 4; DRAM at 16. 127 DRAM at 16. 128 EnerNOC at 6. 93. Old Dominion supports the proposal and agrees that incorporating smaller demand response resources would be beneficial to the market, but notes that measurement and verification standards specific to these smaller resources may be necessary to ensure proper allocation of costs and to address any reliability concerns. 129 129 Old Dominion at 8. 94. Two commenters disagree on how smaller demand response resources should be defined. EnerNOC recommends that the Commission clarify that “smaller demand response resources” should be construed more broadly than the residential class of customers because a more diverse portfolio is more valuable to the market. EEI, however, disagrees and recommends that the Commission not define what constitutes smaller demand response resources, and instead allow each RTO or ISO to propose a definition that reflects its particular market design and characteristics. 130 130 EEI at 12. 95. The ISO/RTO Council comments that its Markets Committee is already addressing certain aspects of this issue by developing a communications protocol for small demand resources, and that these efforts will be discussed at a technical conference on integrating small demand resources into organized markets. The ISO/RTO Council asserts that its report will not supplant the Commission's proposed assessment, but still urges the Commission to coalesce its proposal with the work of the ISO/RTO Council Markets Committee. 131 131 ISO/RTO Council at 6. 96. Finally, ISO New England notes that it currently has a demand response reserve pilot program in place to assess the ability of smaller demand resources to provide reserve products to the wholesale market, and to develop comparable communication, metering, telemetry and other technical infrastructure solutions that are more suitable and cost effective for smaller, dispersed demand resources. 132 132 ISO New England at 4. ii. Commission Determination 97. The Commission will require RTOs and ISOs, in cooperation with their customers and other stakeholders, to perform an assessment, through pilot projects or other mechanisms, of the technical feasibility and value to the market of smaller demand response resources providing ancillary services, within one year from the effective date of the Final Rule, including whether (and how) smaller demand response resources can reliably and economically provide operating reserves and report their findings to the Commission. The choice between either a pilot program or other mechanisms in this assessment is appropriately left to the discretion of the RTO or ISO and its customers and other stakeholders. Additional issues raised here by commenters, such as the need for measurement and verification standards and a definition of what constitutes a “small demand response resource” should be addressed in the assessments. 98. The Commission finds that, based on the comments, accommodating smaller demand response resources through adjusted minimum size thresholds and telemetry requirements could result in an increase in potential operating reserves. Allowing more resources to participate in operating reserves and other ancillary services markets may increase the competitiveness of these markets and could lower the overall price for such services. 99. The Commission agrees that this assessment should not delay pilot programs that are currently underway or other smaller load reforms taking place in RTOs and ISOs, nor should it create an opportunity to avoid addressing barriers to smaller load participation in ancillary services markets. In addition, while not part of the Commission's requirement, the Commission encourages the ISO/RTO Council to continue developing a communications protocol for small demand response resources and encourages RTOs and ISOs to consider the ISO/RTO Council's work in developing their individual assessments. 3. Eliminating Deviation Charges During System Emergencies a. Deviation Charges 100. The Commission proposed in the NOPR to require that all RTO and ISO tariffs be modified as necessary to eliminate a charge-referred to as a deviation charge 133 —to a buyer 134 in the energy market for taking less electric energy than it planned to take in the real-time market, during a real-time market period for which the RTO or ISO declares an operating reserve shortage or makes a generic request to reduce load to avoid an operating reserve shortage. 135 133 Deviation charges recover certain costs, including generators' costs (such as start-up costs) that exceed their energy market revenues when real-time demand is less than forecast. These “uplift” costs may include the cost of extra generators committed after the close of the day-ahead market to serve anticipated load, if those costs are not recovered from sales of energy at real-time LMPs. 134 Examples of buyers in RTO and ISO energy markets include an LSE that purchases electricity to meet the load requirements of its retail customers and a retail customer that purchases electricity directly from the wholesale market. 135 NOPR, FERC Stats. & Regs. ¶ 32,682 at P 72. 101. The Commission proposed that an RTO or ISO must either propose amendments to its tariffs to comply with this requirement or demonstrate through a compliance filing that its existing tariff and market design meet this requirement. The Commission proposed that this filing be submitted within six months of the date that this Final Rule is published in the Federal Register . 102. The Commission's proposal applies to real-time demand response that occurs in addition to the demand response of participants in an RTO's or ISO's wholesale demand response program. Under the proposal, deviation charges would be eliminated only when the RTO or ISO announces an emergency situation after the close of the day-ahead market. The Commission also proposed that since deviation charges cover real costs to generators and others that are not recovered from the sale of energy in real time, these costs should be allocated to all loads of the RTO or ISO. i. Comments 103. A majority of commenters supports the Commission's proposal and agree that eliminating deviation charges during periods when the RTO or ISO declares an operating reserve shortage or makes a generic request to reduce load to avoid an operating reserve shortage would eliminate a barrier to demand reduction in wholesale energy markets. 136 For instance, Energy Curtailment and PG&E state that penalizing an LSE for taking less energy in real-time during system emergencies would be counterproductive. 137 Many commenters agree that this proposal would result in several benefits, including reduced market prices, mitigation of market power, and improved system reliability. 138 136 Ameren at 23; American Forest at 6; APPA at 3; BlueStar Energy at 2; Mr. Borlick at 2; BP Energy at 15; California DWR at 15; CASIO at 1; California PUC at 15; Cogeneration Parties at 3; Comverge at 17; DC Energy at 5; Dominion Resources at 6; DRAM at 18; Duke Energy at 5; EEI at 14; Energy Curtailment at 4; EnerNOC at 11; Exelon at 6; FirstEnergy at 8; Industrial Coalitions at 11; Industrial Consumers at 15; Integrys Energy at 9; ISO New England at 8; ISO/RTO Council at 6; LPPC at 7; MADRI States at 6; Maine PUC at 3; Midwest Energy at 2; Midwest ISO at 11; NCPA at 5; NEPOOL Participants at 12; NIPSCO at 9; North Carolina Electric Membership at 4; Ohio PUC at 7; Old Dominion at 9; OMS at 3; OPSI at 4; Pennsylvania PUC at 11; PG&E at 8; Public Interest Organizations at 6; Reliant at 4; Steel Manufacturers at 11; Steel Producers at 5; TAPS at 9; Wal-Mart at 5; and Xcel at 8. 137 Energy Curtailment at 4-5; PG&E at 8. 138 While APPA supports this proposal, it states that if bid and offer caps are eliminated during system emergencies, it cannot support uplifting such charges.APPA at 3. 104. Several supporters also agree with the Commission's proposal to allocate to all loads of the RTO and ISO uplift charges to cover costs associated with the elimination of such deviation charges. 139 However, NIPSCO and Old Dominion state that uplift charges should be allocated only within the zones where the emergency occurred. 140 Dominion Resources and ISO/RTO Council urge the Commission to allow each region to decide how the costs should be allocated based on market constraints and input from stakeholders. 141 139 E.g. , Ohio PUC at 7-8; Public Interest Organizations at 6; EEI at 14-15; DRAM at 18-19. 140 NIPSCO at 9; Old Dominion at 9. 141 Dominion Resources at 8-9; ISO/RTO Council at 6-8. 105. Several commenters seek clarification of various aspects of the proposal. For instance, EEI asks the Commission to clarify that deviation charges would be eliminated only when the RTO or ISO announces an emergency situation after the close of the day-ahead market. 142 TAPS suggests that the Commission clarify that it intends to encompass all forms of demand response that could be activated to reduce load during emergencies, including programs that operate behind the meter of the LSE with a reduction reflected in the wholesale market participant's demand. 143 Cogeneration Parties note that it is unclear whether the costs caused by uninstructed deviations during normal operations would also be incurred during a system emergency, and recommend that the Final Rule require RTOs and ISOs to verify their actual costs incurred during system emergencies before such charges are imposed on customers. 144 Similarly, Midwest Energy suggests that the net benefits for load reductions be verified before costs are imposed on customers. 145 142 EEI at 14-15. 143 TAPS at 9-11. 144 Cogeneration Parties at 3. 145 Midwest Energy at 3. 106. A few commenters urge the Commission to clearly define “deviation charge” and the circumstances under which deviation charges would be eliminated. For example, NYISO requests that the Commission clarify its proposed regulatory text to more specifically define deviation charges. 146 Others state that circumstances under which an RTO or ISO merely seeks to avoid an operating reserve shortage are significantly different from those in which it has experienced an actual operating reserve shortage or emergency. Therefore, they suggest that the Commission define the conditions when elimination of deviation charges would take place. 147 NIPSCO states that the Commission should clarify that deviation charges should also be waived when an RTO or ISO declares a NERC Energy Emergency Alert. 148 The Pennsylvania PUC states that there are two types of emergencies, generation insufficiency and generation excess, and while generation insufficiency is of greatest concern to the public, excess generation emergencies are not uncommon. At such times locational marginal price or LMP may go negative in an effort to resolve a rapidly dropping load situation. For such reasons the Pennsylvania PUC asks that the Commission clarify whether eliminating a deviation charge is appropriate for both kinds of emergencies. 149 146 NYISO at 7-8. 147 E.g. , DRAM at 18-19; Comverge at 17-18; and NIPSCO at 12-14. 148 NIPSCO at 12-14. The NERC reliability standard provides procedures that RTOs and ISOs must follow when capacity emergencies are declared and requires that all resources be used to meet load before operating reserves are tapped to address an emergency. 149 Pennsylvania PUC at 11. 107. Additionally, some commenters recommend that the proposal should be expanded so that deviation charges would be eliminated not just in emergency situations, but in all situations when demand deviates from schedule by using less energy. 150 Duke urges the Commission to eliminate deviation charges so long as the load remains within an appropriate demand response “bandwidth.” 151 No deviation charges would be assessed in emergency or non-emergency situations, so long as the load behaves consistently with the price-sensitive demand schedule provided to the RTO or ISO. Other commenters suggest that the proposal be expanded to include other contractual arrangements, 152 demand-reduction services, 153 and programs that compensate market participants for demand reductions during system emergencies. 154 150 E.g., California PUC at 15-16; Industrial Consumers at 15-16 and Steel Manufacturers at 11-12. 151 Duke suggests that a reasonable solution to preventing inequitable cost shifts is to establish a bandwidth that would determine whether deviation charges should apply. Duke at 5-7. 152 NCPA states that the Commission's proposal to allow RTOs and ISOs to waive deviation charges should be expanded to include other contractual arrangements to the degree that ARCs are permitted to perform aggregations of retail load. NCPA at 5-6. 153 OMS recommends that the Commission direct RTOs and ISOs to explore the development of programs that compensate market participants for demand reductions during system emergencies. OMS at 3. 154 Id. at 3. Similarly, EEI asks the Commission to allow RTOs and ISOs to propose compensation sufficient to encourage demand response resources to incur the cost of reducing consumption. EEI at 14-15. 108. Several commenters support a regional approach to establishing methods for dealing with deviation charges. For example, ISO/RTO Council urges the Commission to allow each RTO or ISO to develop its own appropriate rules to implement the proposal to account for regional operating considerations and to establish appropriate details, including defining what system conditions constitute an emergency. 155 California Munis urges regional flexibility to ensure that specific facts pertaining to each RTO or ISO can be fully considered in assessing whether this proposal will be beneficial to consumers or merely shifts costs among consumers. 156 Similarly, SoCal Edison-SDG&E state that, rather than having the Commission eliminate deviation charges in a uniform manner for all RTOs and ISOs, a method for dealing with deviations from the day-ahead energy market purchases must be considered comprehensively by each RTO or ISO within the framework of its overall market design. 157 155 ISO/RTO Council at 6-8. 156 California Munis is not opposed to the Commission's proposal, but states that there are California-specific issues that must be considered, which may lead to a policy conclusion that elimination of deviation charge may not be appropriate for California. California Munis at 11-12. 157 SoCal Edison-SDG&E state that eliminating charges in a uniform manner to all demand does not recognize the locational benefits of reducing demand in certain areas or cases where decreasing demand could hinder efforts to address grid reliability concerns. SoCal Edison-SDG&E at 3. 109. NEPOOL Participants states that the Commission should not impose its proposal on RTOs and ISOs before allowing NEPOOL Participants to evaluate, through its stakeholder process, issues around how deviation charges are calculated and assessed, including ISO New England's ability to separate out the types of deviation charges that the Commission has proposed. 158 158 NEPOOL Participants at 14. 110. Constellation opposes this proposal, stating that eliminating deviation charges during system emergencies could create unintended consequences. Constellation believes that the proposal provides preferential treatment for energy providers that supply load reductions over generators that supply a similar product. Constellation argues that deviation charges are appropriate because such charges provide: (1) an incentive for LSEs to accurately forecast and bid their load into the day-ahead market; and (2) a source of funds to compensate out-of-market generators that are necessary to meet peak load when the real-time load deviates from its day-ahead load bid. 159 In addition, Constellation states that opportunities for the demand side of the market to respond are lost whenever supply resources are compensated outside of market-clearing prices through the use of uplift charges. It believes this problem can be alleviated through proper price formation. 160 For these reasons, Constellation recommends that the Commission leave the deviation charge in place and institute a shortage pricing regime, and address other issues that socialize out-of-market costs in order to minimize socialized uplift charges. 161 159 Constellation at 6. 160 Id. at 7. 161 Id. at 6-7. ii. Commission Determination 111. The Commission adopts the NOPR proposal to require all RTOs and ISOs to modify their tariffs to eliminate a deviation charge to a buyer in the energy market for taking less electric energy in the real-time market than was scheduled in the day-ahead market during a real-time market period for which the RTO or ISO declares an operating reserve shortage or makes a generic request to reduce load in order to avoid an operating reserve shortage. This requirement does not apply to RTO or ISO wholesale demand response program participants, but rather to market buyers who voluntarily provide additional demand response either during or prior to an RTO- or ISO-directed operating reserve shortage in an effort to improve system reliability. 112. Removal of the deviation charge during a system emergency will eliminate a disincentive for participation of demand response in the real-time market. A buyer may be deterred from reducing demand during periods of reserve shortage if that buyer is subject to a charge for reducing its real-time consumption below its day-ahead purchases at the request of the RTO or ISO market operator. This unintended disincentive may result in the buyer maintaining a higher level of demand or discourage an LSE from calling on the demand response resources in its retail market. Removal of this disincentive will help maintain system reliability and help reduce prices during system emergencies. 113. Demand response program participants currently are not levied a deviation charge if they reduce demand as directed by the RTO or ISO, and the Commission's requirement in this Final Rule does not alter this practice. In addition, the Commission is not requiring that RTOs and ISOs remove penalties for day-ahead bidders of demand response that fail to follow dispatch instructions to reduce demand in real time. What this requirement does focus on is demand response that is provided by LSEs and other market buyers that consume less total energy in real time during system emergencies or at the request of the RTO or ISO than they had scheduled in the day-ahead market. The intent of the Commission's requirement is not only to ensure that market buyers who voluntarily reduce their energy consumption during system emergencies at the request of the RTO or ISO are not penalized for their deviation, but also that demand-side and supply-side resources are treated comparably. 114. As noted above, a majority of commenters support this requirement and agree that removal of these deviation charges would remove a disincentive for demand reduction. Elimination of deviation charges for a buyer's response to RTO and ISO calls for demand reductions also will further comparable treatment of demand and supply resources. RTO and ISO tariffs already do not impose deviation charges on generators that generate more power during system emergencies than scheduled in the day-ahead market. 115. An RTO or ISO must either propose amendments to its tariff to comply with this requirement or demonstrate in a compliance filing that its existing tariff and market design already satisfy this requirement. This compliance filing must be filed with the Commission within six months of the date that this Final Rule is published in the Federal Register . The Commission will assess each filing to determine if it satisfies the requirements of this section and will issue additional orders, as needed. This process addresses comments by RTO/ISO Council, California Munis, SoCalEdison-SDG&E, NEPOOL Participants and others recommending regional flexibility in addressing this issue. 116. The Commission encourages each RTO and ISO to work with its customers and other stakeholders in making tariff revisions and other changes to its market design necessary to comply with this requirement. The Commission's goal is to remove barriers to the development and use of demand response resources in wholesale energy markets, and the Commission expects that barriers can be effectively removed if each RTO and ISO works effectively and cooperatively with its customers and stakeholders. 117. Although the majority of commenters express support for this requirement, as noted above, a significant number ask for clarification or suggest changes to the NOPR proposal. Customer demand reduction in response to an emergency appeal benefits all customers, by averting or reducing the severity of a power shortage, so voluntary reductions during system emergencies can provide system-wide benefits. They can help maintain system reliability and reduce overall energy prices, which benefits all customers. As a result, the Commission finds that socialization of these costs is justified. However, in response to comments by NIPSCO and Old Dominion that the deviation charge should be allocated locally rather than on a system wide basis, this matter is best addressed in each RTO's or ISO's compliance filing. Any proposal for local allocation of these costs should be accompanied by an explanation of when costs would be spread across the entire RTO or ISO region and when applied locally, how the local area would be determined, and why local cost recovery is justified. Further, in response to comments by EEI and NIPSCO, we clarify that deviation charges would be eliminated only when the RTO or ISO announces an emergency situation or requests a voluntary load reduction after the close of the day-ahead market. 118. In response to TAPS's request for clarification on what forms of demand response this requirement would apply to, we note that this requirement applies to all buyers in the wholesale energy market, outside of an RTO's or ISO's demand response program, that may respond to an RTO or ISO request for voluntary load reduction during a system emergency. In response to comments by Cogeneration Parties and Midwest Energy state that the costs and benefits of load reduction must be verified before costs are imposed on customers, measurement and verification protocols should be addressed within the RTO's or ISO's compliance filing, and therefore will not require a net benefits test. In order to accommodate regional differences, we will also defer NYISO's request that the Commission specify more clearly the definition of “deviation charge” to the compliance filing process (which will permit stakeholder input). 119. The Pennsylvania PUC asked for clarification of whether it is appropriate to eliminate deviation charges during periods of excess generation, when RTOs and ISO might call upon generators to reduce supply. The Commission notes that the intent of this Final Rule is to remove disincentives to demand-side resources so that they can be treated similarly and comparably in relation to supply-side resources. While it may be appropriate to remove deviation charges for supply-side resources during periods of excess generation, issues involving periods of excess generation are not addressed in this rulemaking. 120. We disagree with comments by the California PUC, Industrial Consumers and Steel Manufacturers recommending that deviation charges be eliminated any time demand deviates from schedule by using less energy. As noted in the NOPR, a reduction in demand during a system emergency benefits the RTO or ISO and its customers by better matching demand with available supply. 162 The Pennsylvania PUC mentions in its comments that if actual demand deviates from scheduled demand during non-emergency periods, such load reductions may result in periods of excess supply and impose costs on the RTO or ISO and its customers. Similarly, Duke's request that no deviation charges be assessed, so long as load remains within a specified bandwidth, may lead to greater disparity between day-ahead and real-time market purchases and could result in additional costs to consumers without providing consumer benefits. In particular, eliminating deviation charges for all periods could result in over-scheduling, which has cost consequences for generators. Therefore, the Commission does not accept these recommendations. 162 NOPR, FERC Stats. & Regs. ¶ 32,628 at P 77. 121. With regard to Constellation's recommendation that the Commission leave the deviation charge in place and institute a shortage pricing regime to better match supply and demand, the Commission is addressing shortage pricing issues in another part of this Final Rule. As noted above, we find that elimination of deviation charges for demand reduction during system emergency periods provides benefits to consumers distinct from those inherent in a shortage pricing regime and removes a disincentive to participation of demand-side resources by treating demand and supply comparably. The Commission therefore declines to adopt Constellation's recommendation. b. Virtual Purchasers 122. In the NOPR, the Commission asked for comments on whether it should require RTOs and ISOs to modify their tariffs to eliminate deviation charges for virtual purchases during system emergencies. 163 The Commission noted that virtual purchasers may not cause significant additional costs during an emergency. Instead, virtual purchases may enhance reliability by increasing the amount of generation resources available in real time during a system emergency. Therefore, the Commission noted that assessing a deviation charge on virtual purchasers during an emergency may be unfair and may discourage helpful virtual purchases when system resources are expected to be tight. 164 163 A virtual purchase (or sale) is a purchase (or sale) in the RTO or ISO day-ahead market that does not go to physical delivery. For example, an entity that does not serve load may make a purchase in the day-ahead market, which it must pay for, and then take no power in real time. This lack of consumption is treated as a sale of the purchased power into the real-time spot market. By making virtual energy purchases and sales in the day-ahead market and settling these positions in the real-time market, a market participant can arbitrage price differences between the two markets. 164 NOPR, FERC Stats. & Regs. ¶ 32,628 at P 78. i. Comments 123. Several commenters state that virtual purchasers should be treated in the same manner as other “physical” purchasers by exempting their day-ahead market bids from deviation charges during system emergencies. 165 MADRI States and BP Energy assert that there is no need to assess deviation charges to virtual purchasers because such purchasers enhance reliability by increasing the amount of generation resources available in real-time during an emergency. 166 Mr. Borlick asserts that virtual bids in the day-ahead market do not impose any costs on the system; he states this is because an RTO and ISO is able to differentiate between virtual and physical bids and it can ignore the virtual bids when determining unit commitment for the next day's real-time operations. 167 Further, DC Energy claims that all buyers of energy (physical and virtual buyers) in the real-time market should be treated equally. 168 165 E.g., Mr. Borlick at 2-3; BP Energy at 15; Exelon; MADRI States; and DC Energy at 5-6. 166 MADRI States at 6-7; BP Energy at 15. 167 Mr. Borlick at 3. 168 BP Energy at 5. 124. Exelon agrees with the elimination of charges for virtual purchasers during system emergencies, but suggests that the Commission allow each RTO or ISO to implement such a rule after exploring the consequences of such action through its stakeholder process. 169 169 Exelon at 6-8. 125. Other commenters oppose this option and state that virtual purchasers should be subject to deviation charges. 170 For instance, First Energy and TAPS state that virtual purchasers provide no load reduction benefit and, therefore should not be exempt from paying the deviation charge. TAPS also states that the NOPR record contains no evidence that the hypothetical benefits of eliminating the deviation charge for virtual bidders would outweigh the harm that would result from removing deviation charges, as they act to discourage bidding behavior that imposes significant costs on consumers. 171 Several commenters believe that exempting virtual purchasers from deviation charges (1) may encourage speculation; (2) result in over commitment of generation when it is not needed; and (3) result in cost shifts to other market participants, thereby distorting markets. 172 APPA asserts that virtual bidders may be able to game the system and receive a payment when no benefit is provided to the region. 170 E.g., Ameren at 24; APPA at 3; ISO New England at 9; ISO/RTO Council at 8; Old Dominion at 10; and TAPS at 10. 171 First Energy at 8; TAPS at 9-11. 172 ISO New England at 8-9; RTO/ISO Council at 6-8; and NYISO at 7-8. 126. NEPOOL Participants believes that it is important to more fully evaluate the issues around virtual bidding and whether it is necessary to include virtual bidding in any discussion regarding the removal of deviation charges. 173 173 NEPOOL Participants at 13. ii. Commission Determination 127. The Commission agrees with the comments that virtual purchases can enhance reliability by increasing the amount of generation resources available in real-time during an emergency. Further, assessing a deviation charge on virtual purchasers during an emergency may be unfair and may discourage such virtual purchasing when it may be most beneficial to other customers. Our preferred policy is to eliminate deviation charges for virtual purchasers as well as physical purchasers during a real-time market period for which the RTO or ISO declares an operating reserve shortage or makes a generic request to reduce load in order to avoid an operating reserve shortage. However, we are concerned an RTO's or ISO's particular market design may not readily accommodate this policy, and we acknowledge commenters' concerns about the possibility of market manipulation under a particular market design if deviation charges are removed for virtual purchasers. Therefore, we direct RTOs and ISOs to modify their tariffs to eliminate deviation charges for virtual purchasers, during the same period as they are eliminated for physical purchasers as set out above, unless the RTO or ISO upon compliance makes a showing that it would be appropriate to assess such deviation charges for virtual purchasers during this period. This approach establishes a reasoned generic policy and still provides an opportunity for each RTO or ISO, on a case-by-case basis, to present a factual record that the generic policy does not fit its overall market design. 4. Aggregation of Retail Customers a. Commission Proposal 128. In the NOPR, the Commission proposed to require RTOs and ISOs to amend their market rules as necessary to permit an ARC to bid demand response on behalf of retail customers directly into the RTO's or ISO's organized markets, unless the laws or regulations of the relevant electric retail regulatory authority do not permit a retail customer to participate. 174 174 NOPR, FERC Stats. & Regs. ¶ 32,628 at P 86. 129. The Commission recognized that each region's market design is different and that it is important for ARC provisions to respect these market design differences. For this reason, the Commission proposed not to mandate generic market rule amendments; rather, it proposed to require RTOs and ISOs to amend their tariffs and market rules as necessary to allow an ARC to bid demand response directly into the RTO's or ISO's organized market, provided that the ARC's demand response bid must meet the same requirements as a demand response bid from any other entity such as an LSE. The NOPR proposed the following flexibilities in RTO and ISO market designs: • The RTO or ISO may require the ARC to be an RTO member if membership is a requirement for other bidders. • RTOs and ISOs may require that an aggregated bid must consist of individual demand response bids from a single area, reasonably defined. • An RTO or ISO may place appropriate restrictions on any customer's participation in an ARC-aggregated demand response bid to avoid counting the same demand response resource more than once. • The market rules do not have to allow bids from an ARC if this is not permitted under the laws or regulations of the relevant electric retail regulatory authority. The RTO or ISO must receive explicit notification from the relevant retail regulatory authority in order to disqualify a bid from an ARC that includes the demand response of that authority's retail customers. 130. The Commission requested comment about whether: (1) These features of the proposal are appropriate and whether there are additional appropriate criteria or features for allowing an ARC to bid demand response; and (2) there is any reason not to subject an ARC to the same requirements as any other bidder in the energy market. 175 175 Id. P 88, 91. 131. The Commission proposed that an RTO or ISO must either propose amendments to its tariff to comply with the requirement or demonstrate in a filing that its existing tariff and market design already satisfy the requirement to permit an ARC to bid demand response on behalf of retail customers. 176 It also proposed that this filing be submitted within six months of the date the Final Rule is published in the Federal Register . The Commission proposed that it would assess whether each filing satisfies the proposed requirement and would issue additional orders as necessary. 176 Id. P 92. b. Comments i. Comments regarding ARC proposal 132. Many commenters support the NOPR proposal to allow ARCs to bid demand response directly into organized markets, unless it is not permitted by the relevant regulatory authority. 177 For instance, EEI asserts that the Commission should adopt this proposal in the Final Rule because it is appropriate for RTOs and ISOs to treat ARCs comparably to wholesale market participants under RTO and ISO rules as long as: (1) State commissions permit aggregation of retail demand response; (2) such treatment is aligned with state requirements; and (3) no preferential treatment is accorded to ARCs, including being subject to monitoring and verification requirements. 178 Some commenters note that experiences in organized markets have demonstrated that allowing ARCs to participate directly in wholesale energy markets has increased market efficiency and led to greater diversity of demand response options. 179 In particular, Comverge and EnerNOC note that allowing ARCs to enter wholesale energy markets has been successful in PJM, ISO New England, and NYISO. 180 177 E.g., American Forest; BlueStar Energy; BP Energy; California PUC; Comverge; DC Energy; Dominion Resources; DRAM; EEI; EnergyConnect; Energy Curtailment; EnerNOC; Exelon; FirstEnergy; IMEA; Industrial Coalitions; Industrial Consumers; Integrys Energy; ISO/RTO Council; LPPC; MADRI States; Midwest ISO; NYISO; Ohio PUC; OMS; OPSI; Pennsylvania PUC; PG&E; Public Interest Organizations; Reliant; Retail Energy; Steel Producers; Wal-Mart; and Xcel. 178 EEI at 16. 179 E.g., DRAM at 20; EnerNOC at 12. 180 Comverge at 18; EnerNOC at 12-13. 133. Industrial Coalitions note that this proposal would expand the pool of potential demand response providers, thereby increasing demand elasticity. American Forest states that the proposal could encourage development of state-level retail programs that may not otherwise be considered. The potential for such participation may encourage the development of state law or retail structures to accommodate participation where none now exists as retail customers seek to avail themselves of the opportunities larger markets offer. 181 181 American Forest at 5-6. 134. Ameren states, however, that unless RTOs and ISOs develop and properly implement clear tariff provisions and market rules that explain how the aggreg [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%3AE8-25246. Public record. Not legal advice.