Third-Party Provision of Ancillary Services; Accounting and Financial Reporting for New Electric Storage Technologies, 46177-46237 [2013-17746]

Download as PDF Vol. 78 Tuesday, No. 146 July 30, 2013 Part V Department of Energy emcdonald on DSK67QTVN1PROD with RULES3 Federal Energy Regulatory Commission 18 CFR Parts 35 and 101 Third-Party Provision of Ancillary Services; Accounting and Financial Reporting for New Electric Storage Technologies; Rules VerDate Mar<15>2010 17:15 Jul 29, 2013 Jkt 229001 PO 00000 Frm 00001 Fmt 4717 Sfmt 4717 E:\FR\FM\30JYR3.SGM 30JYR3 46178 Federal Register / Vol. 78, No. 146 / Tuesday, July 30, 2013 / Rules and Regulations DEPARTMENT OF ENERGY Federal Energy Regulatory Commission 18 CFR Parts 35 and 101 [Docket Nos. RM11–24–000 and AD10–13– 000; Order No. 784] Third-Party Provision of Ancillary Services; Accounting and Financial Reporting for New Electric Storage Technologies Federal Energy Regulatory Commission, DOE. ACTION: Final rule. AGENCY: The Federal Energy Regulatory Commission (Commission) is revising its regulations to foster competition and transparency in ancillary services markets. The Commission is revising certain aspects of its current market-based rate regulations, ancillary services requirements under the pro forma openaccess transmission tariff (OATT), and accounting and reporting requirements. Specifically, the Commission is revising its regulations to reflect reforms to its Avista policy governing the sale of ancillary services at market-based rates to public utility transmission providers. SUMMARY: The Commission is also requiring each public utility transmission provider to add to its OATT Schedule 3 a statement that it will take into account the speed and accuracy of regulation resources in its determination of reserve requirements for Regulation and Frequency Response service, including as it reviews whether a self-supplying customer has made ‘‘alternative comparable arrangements’’ as required by the Schedule. The final rule also requires each public utility transmission provider to post certain Area Control Error data as described in the final rule. Finally, the Commission is revising the accounting and reporting requirements under its Uniform System of Accounts for public utilities and licensees and its forms, statements, and reports, contained in FERC Form No. 1, Annual Report of Major Electric Utilities, Licensees and Others, FERC Form No. 1–F, Annual Report for Nonmajor Public Utilities and Licensees, and FERC Form No. 3–Q, Quarterly Financial Report of Electric Utilities, Licensees, and Natural Gas Companies, to better account for and report transactions associated with the use of energy storage devices in public utility operations. This rule is effective November 27, 2013. DATES: FOR FURTHER INFORMATION CONTACT: Rahim Amerkhail (Technical Information), Federal Energy Regulatory Commission, Office of Energy Policy and Innovation, 888 First Street NE., Washington, DC 20426, (202) 502–8266. Christopher Handy (Accounting Information), Federal Energy Regulatory Commission, Office of Enforcement, 888 First Street NE., Washington, DC 20426, (202) 502– 6496. Lina Naik (Legal Information), Federal Energy Regulatory Commission, Office of the General Counsel, 888 First Street NE., Washington, DC 20426, (202) 502–8882. Eric Winterbauer (Legal Information), Federal Energy Regulatory Commission, Office of the General Counsel, 888 First Street NE., Washington, DC 20426, (202) 502– 8329. SUPPLEMENTARY INFORMATION: Before Commissioners: Jon Wellinghoff, Chairman; Philip D. Moeller, John R. Norris, Cheryl A. LaFleur, and Tony Clark. Order No. 784 Final Rule Issued July 18, 2013. Table of Contents Paragraph No. emcdonald on DSK67QTVN1PROD with RULES3 I. Background ............................................................................................................................................................................................ II. Discussion ............................................................................................................................................................................................ A. The Avista Policy ......................................................................................................................................................................... 1. Use of Market Power Analyses ............................................................................................................................................. a. Reliance on Existing Indicative Screens ........................................................................................................................ i. Application to Imbalance Ancillary Services ......................................................................................................... ii. Application to Other Ancillary Services ............................................................................................................... b. Optional Market Power Screen ...................................................................................................................................... 2. Alternative Mitigation ............................................................................................................................................................ a. Use of Price Caps ............................................................................................................................................................ i. Single OATT Rate Cap Option ................................................................................................................................ ii. Regional OATT Rate Cap Option ........................................................................................................................... b. Competitive Solicitations ............................................................................................................................................... B. Resource Speed and Accuracy in Determination of Regulation and Frequency Response Reserve Requirements ............... C. Accounting and Reporting for Energy Storage Operations ........................................................................................................ D. Other Issues .................................................................................................................................................................................. III. Summary of Compliance and Implementation ................................................................................................................................. IV. Information Collection Statement ...................................................................................................................................................... V. Environmental Analysis ...................................................................................................................................................................... VI. Regulatory Flexibility Act .................................................................................................................................................................. VII. Document Availability ...................................................................................................................................................................... 1. The Federal Energy Regulatory Commission (Commission) is revising its regulations to enhance competition and transparency in ancillary services markets. The Commission is revising certain aspects of its current marketbased rate regulations, ancillary services requirements under the pro forma openaccess transmission tariff (OATT), and accounting and reporting requirements. VerDate Mar<15>2010 17:15 Jul 29, 2013 Jkt 229001 Specifically, the Commission is revising Part 35 of its regulations to reflect reforms to its Avista Corp.1 policy governing the sale of ancillary services at market-based rates to public utility transmission providers. The Commission is also requiring each 1 See 87 FERC ¶ 61,223 (Avista), order on reh’g, 89 FERC ¶ 61,136 (1999). PO 00000 Frm 00002 Fmt 4701 Sfmt 4700 6 12 12 17 20 22 43 62 75 76 77 86 95 102 122 188 201 207 208 209 210 public utility transmission provider to add to its OATT Schedule 3 a statement that it will take into account the speed and accuracy of regulation resources in its determination of reserve requirements for Regulation and Frequency Response service, including as it reviews whether a self-supplying customer has made ‘‘alternative comparable arrangements’’ as required E:\FR\FM\30JYR3.SGM 30JYR3 Federal Register / Vol. 78, No. 146 / Tuesday, July 30, 2013 / Rules and Regulations emcdonald on DSK67QTVN1PROD with RULES3 by the Schedule. Each public utility transmission provider is also required to post certain Area Control Error data on the open access same-time information system (OASIS). Finally, the Commission is revising the accounting and reporting requirements under its Uniform System of Accounts for public utilities and licensees (USofA) 2 and its forms, statements, and reports, contained in FERC Form No. 1 (Form No. 1), Annual Report of Major Electric Utilities, Licensees and Others,3 FERC Form No. 1–F (Form No. 1–F), Annual Report for Nonmajor Public Utilities and Licensees,4 and FERC Form No. 3–Q (Form No. 3–Q), Quarterly Financial Report of Electric Utilities, Licensees, and Natural Gas Companies,5 to better account for and report transactions associated with the use of energy storage devices in public utility operations. 2. First, the Commission reforms the Avista policy governing sales of certain ancillary services to a public utility purchasing the ancillary service to satisfy its own OATT requirements to offer ancillary services to its own customers. As noted in the Notice of Proposed Rulemaking,6 there is a growing need for ancillary services to support grid functions in the face of potential changes in the portfolio of generation resources and a growing interest of transmission providers to have flexibility in meeting ancillary services needs.7 There is also interest in third-party provision of ancillary services and that interest may be unnecessarily frustrated by the Avista policy. Comments to the NOPR’s proposal to reconsider the Avista restrictions generally supported these concepts. As such, and as discussed further below, we conclude that elements of our existing market-based rate regulations can be modified in a manner that continues to limit the exercise of market power, while also enhancing the ability of third parties to 2 Uniform System of Accounts Prescribed for Public Utilities and Licensees Subject to the Provisions of the Federal Power Act, 18 CFR Part 101 (2012). 3 18 CFR 141.1 (2012). 4 18 CFR 141.2 (2012). 5 18 CFR 141.400 (2012). 6 Third-Party Provision of Ancillary Services; Accounting and Financial Reporting for New Electric Storage Technologies, Notice of Proposed Rulemaking, FERC Stats. & Regs. ¶ 32,690 (2012) (NOPR). 7 Integration of Variable Energy Resources, Order No. 764, FERC Stats. & Regs. ¶ 32,331, order on reh’g, Order No. 764–A, 141 FERC ¶ 61,232 (2012); and Demand Response Compensation in Organized Wholesale Energy Markets, Order No. 745, FERC Stats. & Regs. ¶ 31,322, order on reh’g, Order No. 745–A, 137 FERC ¶ 61,215 (2011). VerDate Mar<15>2010 17:15 Jul 29, 2013 Jkt 229001 compete for the sale of certain ancillary services. 3. Second, we adopt reforms to provide greater transparency with regard to reserve requirements for Regulation and Frequency Response. Under the requirements of the pro forma OATT, transmission customers may either purchase Regulation and Frequency Response service at costbased rates from the public utility transmission provider pursuant to its OATT or self-supply the service, including through purchases from thirdparties.8 With regard to the notion of self-supply, the pro forma OATT Schedule 3 merely states that the transmission customer must make alternative comparable arrangements to satisfy is Regulation and Frequency Response Service obligation. In particular, Schedule 3 provides no discussion of the meaning of the term ‘‘comparable’’ as it relates to reliance on resources with dispatch speed and accuracy characteristics that may differ from those used by the public utility transmission provider. Because the system must be operated reliably at all times, the customer may not decline the transmission provider’s offer of ancillary services unless it demonstrates that it has acquired comparable services from another source.9 In order to clarify the role of resource speed and accuracy in the determination of alternative comparable arrangements, in this Final Rule the Commission requires each public utility transmission provider to add to its OATT Schedule 3 a statement that it will take into account the speed and accuracy of regulation resources in its determination of reserve requirements for Regulation and Frequency Response service, including as it reviews whether a self-supplying customer has made ‘‘alternative comparable arrangements’’ as required by the Schedule. This statement will also acknowledge that, upon request by the self-supplying customer, the public utility transmission provider will share with the customer its reasoning and any related data used to make the 8 See, e.g., Promoting Wholesale Competition Through Open Access Non-Discriminatory Transmission Services by Public Utilities; Recovery of Stranded Costs by Public Utilities and Transmitting Utilities, Order No. 888, FERC Stats. & Regs. ¶ 31,036, at 31,716 (1996), order on reh’g, Order No. 888–A, FERC Stats. & Regs. ¶ 31,048, order on reh’g, Order No. 888–B, 81 FERC ¶ 61,248 (1997), order on reh’g, Order No. 888–C, 82 FERC ¶ 61,046 (1998), aff’d in relevant part sub nom. Transmission Access Policy Study Group v. FERC, 225 F.3d 667 (D.C. Cir. 2000), aff’d sub nom. New York v. FERC, 535 U.S. 1 (2002); pro forma OATT, Original Sheet Nos. 20–21 and Schedule 3, Original Sheet No. 113. 9 Order No. 888, FERC Stats. & Regs. ¶ 31,036 at 31,716. PO 00000 Frm 00003 Fmt 4701 Sfmt 4700 46179 determination of whether the customer has made ‘‘alternative comparable arrangements.’’ To aid the transmission customer’s ability to make an ‘‘applesto-apples’’ comparison of regulation resources, the final rule also requires each public utility transmission provider to post on OASIS historical one-minute and ten-minute Area Control Error data as described in the final rule for the most recent calendar year, and update this posting once per year. 4. With this information, a transmission customer will be in a position to demonstrate to the public utility transmission provider that the resource(s) it selects for self-supply are comparable to those of the public utility transmission provider. As such, these reforms are necessary to address the potential for undue discrimination against transmission customers choosing to self-supply Regulation and Frequency Response, including through purchases from third-parties. Acknowledging the speed and accuracy of the resources used to provide this service will help to ensure that selfsupply requirements of the public utility transmission provider do not unduly discriminate by requiring customers to procure a different amount of regulation reserves than the particular speed and accuracy characteristics of the resources in question justify (i.e., to be comparable, a customer self-supply arrangement that relies on slower, less accurate resources than those of the public utility transmission provider should probably involve a larger reserve requirement than would a purchase from the transmission provider, and vice versa). Moreover, as the Commission has previously stated, because most generation-based ancillary services can be provided by many of the generators connected to the transmission system, some customers may be able to provide or procure such services more economically than the transmission provider can.10 5. Finally, we adopt reforms to our accounting and reporting regulations to add new electric plant and operation and maintenance (O&M) expense accounts for energy storage devices. These reforms are necessary to accommodate the increasing availability of these new resources for use in public utility operations. These reforms are also necessary to ensure that the activities and costs of new energy 10 Id. at 31,718. We note that customers could conceivably procure such services more economically either by paying much less per unit for a larger amount of slower, less accurate resources, or by paying somewhat more per unit for a smaller amount of faster, more accurate resources. E:\FR\FM\30JYR3.SGM 30JYR3 46180 Federal Register / Vol. 78, No. 146 / Tuesday, July 30, 2013 / Rules and Regulations storage operations are sufficiently transparent to allow effective oversight. Background emcdonald on DSK67QTVN1PROD with RULES3 6. The Commission has taken numerous steps over the last several decades to foster the development of competitive wholesale energy markets by ensuring non-discriminatory access and comparable treatment of resources in jurisdictional wholesale markets.11 With regard to ancillary services, the Commission in Order No. 888 delineated two categories of ancillary services: Those that the transmission provider is required to provide to all of its basic transmission customers 12 and those that the transmission provider is only required to offer to provide to transmission customers serving load in the transmission provider’s control area.13 With respect to the second category the Commission reasoned that the transmission provider is not always uniquely qualified to provide the services and customers may be able to more cost-effectively self-supply them or procure them from other entities. The Commission contemplated that third parties (i.e., parties other than a transmission provider supplying ancillary services pursuant to its OATT obligation) could provide ancillary services on other than a cost-of-service basis if such pricing was supported, on 11 See, e.g., Order No. 888, FERC Stats. & Regs. ¶ 31,036, at 31,781; Market-Based Rates for Wholesale Sales of Electric Energy, Capacity and Ancillary Services by Public Utilities, Order No. 697, FERC Stats. & Regs. ¶ 31,252, clarified, 121 FERC ¶ 61,260 (2007), order on reh’g, Order No. 697–A, FERC Stats. & Regs. ¶ 31,268, clarified, 124 FERC ¶ 61,055, order on reh’g, Order No. 697–B, FERC Stats. & Regs. ¶ 31,285 (2008), order on reh’g, Order No. 697–C, FERC Stats. & Regs. ¶ 31,291 (2009), order on reh’g, Order No. 697–D, FERC Stats. & Regs. ¶ 31,305 (2010), aff’d sub nom. Montana Consumer Counsel v. FERC, 659 F.3d 910 (9th Cir. 2011), cert. denied sub nom. Pub. Citizen, Inc. v. FERC, 133 S. Ct. 26 (2012); Preventing Undue Discrimination and Preference in Transmission Service, Order No. 890, FERC Stats. & Regs. ¶ 31,241, order on reh’g, Order No. 890–A, FERC Stats. & Regs. ¶ 31,261 (2007), order on reh’g, Order No. 890–B, 123 FERC ¶ 61,299 (2008), order on reh’g, Order No. 890–C, 126 FERC ¶ 61,228 (2009), order on reh’g, Order No. 890–D, 129 FERC ¶ 61,126 (2009); Wholesale Competition in Regions with Organized Electric Markets, Order No. 719, FERC Stats. & Regs. ¶ 31,281 (2008), order on reh’g, Order No. 719–A, FERC Stats. & Regs. ¶ 31,292 (2009), order on reh’g, Order No. 719–B, 129 FERC ¶ 61,252 (2009). 12 The first category consists of Scheduling, System Control and Dispatch service and Reactive Supply and Voltage Control from Generation Sources service. 13 The second category consists of Regulation and Frequency Response service, Energy Imbalance service, Operating Reserve-Spinning service, and Operating Reserve-Supplemental service. Order No. 890 later added an additional OATT ancillary service to this category: Generator Imbalance service. See Order No. 890, FERC Stats. & Regs. ¶ 31,241 at P 85. VerDate Mar<15>2010 17:15 Jul 29, 2013 Jkt 229001 a case-by-case basis, by analyses that demonstrated that the seller lacks market power in the relevant product market.14 Later, in Ocean Vista Power Generation, L.L.C.,15 the Commission provided guidance regarding such analyses, explaining that as a general matter a study of ancillary services markets should address the nature and characteristics of each ancillary service, as well as the nature and characteristics of generation capable of supplying each service, and that the study should develop market shares for each service. 7. The Commission subsequently acknowledged in Avista 16 that data limitations can impair the ability of sellers to perform a market power study for ancillary services consistent with the requirements of Ocean Vista. The Commission therefore adopted a policy allowing third-party ancillary service providers that could not perform a market power study to sell certain ancillary services at market-based rates with certain restrictions.17 In so doing, the Commission reasoned that the backstop of cost-based ancillary services from transmission providers, in effect, limits the price at which customers are willing to buy ancillary services, thus ensuring that the third-party sellers’ rates would remain just and reasonable even without a showing of lack of market power. However, the Commission found that this backstop failed to provide adequate mitigation of potential third-party market power in three situations: (1) Sales to a regional transmission organization (RTO) or an independent system operator (ISO), which has no ability to self-supply ancillary services but instead depends on third parties; 18 (2) to address affiliate abuse concerns, sales to a traditional, franchised public utility affiliated with 14 Order No. 888, FERC Stats. & Regs. ¶ 31,036 at 31,720–21. 15 82 FERC ¶ 61,114, at 61,406–07 (1998) (Ocean Vista). 16 Avista, 87 FERC at 61,882. 17 These ancillary services included: Regulation and Frequency Response, Energy Imbalance, Operating Reserve-Spinning, and Operating Reserve-Supplemental. The Commission did not extend this Avista policy to Reactive Supply and Voltage Control from Generation Sources service, which means that third parties wishing to sell this ancillary service at market-based rates would remain subject to the pre-Avista market power screen requirement. The Commission also did not extend the Avista policy to Scheduling, System Control and Dispatch service. However, because only balancing area operators can provide this ancillary service, it does not lend itself to competitive supply. 18 Subsequently, as the Commission recognized in Order No. 697, most RTOs and ISOs developed formal ancillary service markets, thus rendering this component of the Avista policy largely superfluous. See Order No. 697, FERC Stats. & Regs. ¶ 31,252 at n.1194 and P 1069. PO 00000 Frm 00004 Fmt 4701 Sfmt 4700 the third-party supplier, or sales where the underlying transmission service is on the system of the public utility affiliated with the third-party supplier; and (3) sales to a public utility that is purchasing ancillary services to satisfy its own OATT requirements to offer ancillary services to its own customers.19 Therefore, the Commission’s Avista policy has allowed third-party suppliers to sell certain ancillary services at market-based rates without showing a lack of market power, except under these three circumstances. 8. In its ongoing effort to enhance competitive markets as a means to ensure just and reasonable rates, including those for ancillary services, the Commission has continued to evaluate its Avista policy, including, with particular regard to this proceeding, the restriction on the sale of ancillary services by third-parties to a public utility that is purchasing ancillary services to satisfy its own OATT requirements to offer ancillary services to its own customers. The Commission’s concern has been to ensure that the cost-based OATT ancillary service rates of public utilities remain a viable backstop or alternative that transmission customers can rely upon instead of the market-based sales from third parties who have not been shown to lack market power. The Commission has reasoned that, if such third-party sellers were permitted to sell to public utilities seeking to meet their OATT ancillary service obligations, the public utility’s ability to seek recovery of such purchase costs in OATT rates might lead to increases in those OATT ancillary service rates that may reflect the exercise of market power thus reducing the rates’ ability to serve as an effective alternative to purchases from a third-party seller unable to show lack of market power. This would undermine the effectiveness of the mitigation measure that the Commission relied upon in Avista to relax the requirement for a market power analysis.20 9. However, as the record in this proceeding demonstrates, the restriction on sales of ancillary services at marketbased rates to a public utility for purposes of satisfying its OATT requirements has proven to be an 19 Avista, 87 FERC ¶ 61,223 at n.12. Avista Rehearing Order, 89 FERC at 61,391–92 (stating that the Commission is ‘‘able to grant blanket authority for flexible pricing only because the price charged by the third-party supplier is disciplined by the obligation of the transmission provider to offer these services under cost-based rates. This discipline would be thwarted if the transmission provider could substitute purchases under non-cost-based rates for its mandatory service obligation.’’). 20 See E:\FR\FM\30JYR3.SGM 30JYR3 Federal Register / Vol. 78, No. 146 / Tuesday, July 30, 2013 / Rules and Regulations unreasonable barrier to entry, unnecessarily restricting access to potential suppliers. In the NOPR, the Commission proposed to address this problem by reforming the Avista restrictions, both by modifying the showing an entity must make to establish that it lacks market power and by establishing market power mitigation options in the absence of such a showing. 10. Building off the Commission’s action in Order No. 755, which found that accounting for a given resource’s speed and accuracy can help ensure just and reasonable rates and prevent against undue discrimination, in the NOPR, the Commission also proposed to require each public utility transmission provider to include provisions in its OATT explaining how it will determine regulation service reserve requirements for transmission customers, including those that choose to self-supply regulation service, in a manner that takes into account the speed and accuracy of resources used. 11. Finally, the Commission proposed to modify its accounting regulations to increase transparency for energy storage facilities. While the Commission’s accounting and reporting requirements associated with the USofA do not dictate the ratemaking decisions of this Commission or State Commissions, these accounting and reporting requirements nevertheless support the rate oversight needs of both this Commission and State Commissions. This information is important in developing and monitoring rates, making policy decisions, compliance and enforcement initiatives, and informing the Commission and the public about the activities of entities that are subject to these accounting and reporting requirements.21 emcdonald on DSK67QTVN1PROD with RULES3 Discussion The Avista Policy 12. As noted above, the Commission’s Avista policy authorizes the sale of certain ancillary services at marketbased rates without showing a lack of market power except under specified circumstances. As relevant here, a thirdparty may not sell ancillary services at market-based rates to a public utility that is purchasing ancillary services to satisfy its own OATT requirements to offer ancillary services to its own customers. In order to overcome this restriction, a potential seller must provide a market power study 21 Applicants for market-based rate authority that do not sell under cost-based rates frequently seek and typically are granted waiver of many or all of these requirements. VerDate Mar<15>2010 17:15 Jul 29, 2013 Jkt 229001 demonstrating a lack of market power for the particular ancillary service in the particular geographic market. Based on the record before us, the Commission adopts a number of the reforms to the ancillary services pricing policy proposed in the NOPR and in some instances adopts a number of modifications to those reforms based on the comments received in response to the NOPR. 13. Specifically, this Final Rule allows a resource with market-based rate authority for sales of energy and capacity to sell imbalance services at market-based rates to a public utility transmission provider in the same balancing authority area, or to a public utility transmission provider in a different balancing authority area, if those areas have implemented intrahour scheduling for transmission service. In addition, upon consideration of the comments to the NOPR, this Final Rule also allows a resource with marketbased rate authority for sales of energy and capacity to sell operating reserve services at market-based rates to a public utility transmission provider in the same balancing authority area, or to a public utility transmission provider in a different balancing authority area, if those areas have implemented intrahour scheduling for transmission service that supports the delivery of operating reserve resources from one balancing authority area to another. As a result, the only remaining limitation on third-party market-based sales of ancillary services is on sales of Reactive Supply and Voltage Control service and Regulation and Frequency Response service to a public utility that is purchasing ancillary services to satisfy its own OATT requirements absent a showing of lack of market power or adequate mitigation of potential market power. In that regard, third-party sales of Reactive Supply and Voltage Control service and Regulation and Frequency Response service to public utility transmission providers will be permitted at rates not to exceed the buying public utility transmission provider’s OATT rate for the same service. Further, to the extent a transmission provider chooses to procure either Reactive Supply and Voltage Control service or Regulation and Frequency Response service through a competitive solicitation that meets the requirements of this Final Rule, third-party sellers of these services may sell at market-based rates. 14. While the record in this proceeding was insufficient for the Commission to relieve the restrictions for Reactive Supply and Voltage Control service and Regulation and Frequency PO 00000 Frm 00005 Fmt 4701 Sfmt 4700 46181 Response service in the same manner as Imbalance and Operating reserves, we remain interested in exploring the technical, economic and market issues concerning the provision of Reactive Supply and Voltage Control service and Regulation and Frequency Response service. As such, the Commission intends to gather further information regarding the provision of Reactive Supply and Voltage Control service and Regulation and Frequency Response service in a separate, new proceeding. 15. Thus, while we decline to adopt some of the reforms proposed in the NOPR based on the record in this proceeding, we expect that this Final Rule substantially enhances the overall opportunities for third-parties to compete to make sales of ancillary services while continuing to limit the exercise of market power. 16. We will first discuss the market power analyses used to establish authority to sell at market-based rates, followed by a discussion of alternative cost-based mitigation in the event a market participant cannot show it lacks market power for a specific product or service. Use of Market Power Analyses 17. The Commission analyzes horizontal market power 22 for sales of energy and capacity using two indicative screens, the wholesale market share screen and the pivotal supplier screen, to identify sellers that raise no horizontal market power concerns and can otherwise be considered for marketbased rate authority.23 The wholesale market share screen measures whether a seller has a dominant position in the relevant geographic market in terms of the number of megawatts of uncommitted capacity owned or controlled by the seller, as compared to the uncommitted capacity of the entire market.24 A seller whose share of the relevant market is less than 20 percent during all seasons passes the wholesale market share screen.25 The pivotal supplier screen evaluates the seller’s potential to exercise horizontal market power based on the seller’s uncommitted capacity at the time of annual peak demand in the relevant 22 18 CFR 35.37(b) (2012). No. 697, FERC Stats. & Regs. ¶ 31,252 at PP 13, 62. See also 18 CFR 35.37(b), (c)(1) (2012). 24 Order No. 697, FERC Stats. & Regs. ¶ 31,252 at P 43. Uncommitted capacity is determined by adding the total nameplate or seasonal capacity of generation owned or controlled through contract and firm purchases, less operating reserves, native load commitments and long-term firm sales. Id. P 38. 25 Id. PP 43–44, 80, 89. 23 Order E:\FR\FM\30JYR3.SGM 30JYR3 46182 Federal Register / Vol. 78, No. 146 / Tuesday, July 30, 2013 / Rules and Regulations market.26 A seller satisfies the pivotal supplier screen if its uncommitted capacity is less than the net uncommitted supply in the relevant market.27 18. Passing both the wholesale market share screen and the pivotal supplier screen creates a rebuttable presumption that the seller does not possess horizontal market power with respect to sales of energy or capacity; failing either screen creates a rebuttable presumption that the seller possesses horizontal market power for such sales.28 A seller that fails one of the screens may present evidence, such as a delivered price test (DPT), to rebut the presumption of horizontal market power.29 In the alternative, a seller may accept the presumption of horizontal market power and adopt some form of cost-based mitigation.30 19. Three of the key components of the analysis of horizontal market power are the definition of products, the determination of appropriate geographic scope of the relevant market for each product, and the identification of the uncommitted generation supply within the relevant geographic market. In Order No. 697, the Commission adopted a default relevant geographic market for sales of energy and capacity.31 In particular, the Commission will generally use a seller’s balancing authority area plus first-tier markets,32 or the RTO/ISO market as applicable, as the default relevant geographic market. For sales of energy and capacity, the product definitions are well understood: the relevant geographic market is generally the default market described 26 18 CFR 35.37(c)(1) (2012). No. 697, FERC Stats. & Regs. ¶ 31,252 at emcdonald on DSK67QTVN1PROD with RULES3 27 Order P 42. 28 18 CFR 35.37(c)(1) (2012). 29 18 CFR 35.37(c)(2) (2012). For purposes of rebutting the presumption of horizontal market power, sellers may use the results of the DPT to refine the default relevant geographic market used to perform pivotal supplier and market share analyses and market concentration analyses using the Herfindahl-Hirschman Index (HHI). The HHI is a widely accepted measure of market concentration, calculated by squaring the market share of each firm competing in the market and summing the results. The Commission has stated that a showing of an HHI less than 2,500 in the relevant market for all season/load periods for sellers that have also shown that they are not pivotal and do not possess a market share of 20 percent or greater in any of the season/load periods would constitute a showing of a lack of horizontal market power, absent compelling contrary evidence from intervenors. Order No. 697, FERC Stats. & Regs. ¶ 31,252 at P 111. 30 18 CFR 35.37(c)(3) (2012). 31 Order No. 697, FERC Stats. & Regs. ¶ 31,252 at P 15. 32 First-tier markets are those markets directly interconnected to the seller’s balancing authority area. See, e.g., Order No. 697, FERC Stats. & Regs. ¶ 31,252 at P 232. VerDate Mar<15>2010 17:15 Jul 29, 2013 Jkt 229001 above; and, the uncommitted generation supply is generally identified as all such supply located within the seller’s balancing authority area, plus potential uncommitted imports, as determined largely by available transmission capacity in the form of simultaneous import limits.33 Except in the circumstances set forth in Avista, entities seeking to sell ancillary services at market-based rates have been required to provide market power analyses that address the nature and characteristics of each ancillary service, as well as the nature and characteristics of generation capable of supplying each service.34 This requirement was based on an assumption that such characteristics might differ from those related to sales of energy and capacity. equipment or suffer from any different geographical limitations compared to resources that provide energy or capacity. As a result, the Commission proposed that sellers passing existing market power analyses should be permitted to sell not only energy and capacity in the relevant geographic market(s), but also Energy Imbalance and Generator Imbalance services at market-based rates. The Commission sought comments on, among other things, any unique technical requirements or limitations that might apply to the provision of the imbalance ancillary services that might impact the Commission’s proposal to find that passage of the existing market power screens also indicates a lack of market power for imbalance services.37 a. Reliance on Existing Indicative Screens Comments 23. The majority of commenters support the Commission’s proposal. AWEA, Beacon, California Storage Alliance, EEI, Electricity Consumers, EPSA, ESA, Iberdrola, Hydro Association, Public Interest Organizations, Powerex, Solar Energy Association, Shell Energy, Southern California Edison, and WSPP support the NOPR proposal to revise the Commission’s regulations governing market-based rate authorizations to provide that sellers passing existing market-based rate analyses in a given geographic market should be granted a rebuttable presumption that they lack horizontal market power for sales of Energy Imbalance and Generator Imbalance ancillary services in that market. 24. ESA, Electricity Consumers, Beacon, and EEI, among others, agree that there are no special technical requirements or other limitations that apply to the provision of the Energy Imbalance or Generator Imbalance ancillary services.38 Electricity Consumers and WSPP, among others, argue that the proposed revisions should reduce barriers to ancillary service providers and increase the supply of needed ancillary services. WSPP agrees that the proposal would enable additional sellers of balancing energy to transact with public utility transmission providers in both bilateral markets or a multi-lateral balancing market, and states that it would likely foster sales of balancing energy even outside of the transmission provider market. AWEA contends that the Commission’s proposed reforms strike 20. In the NOPR, the Commission analyzed whether passage of the existing market-based rate screens for sales of energy and capacity can adequately demonstrate lack of market power for sales of ancillary services, based on the relevant characteristics of resources capable of providing each ancillary service. Based on this analysis, the Commission proposed that only the two imbalance ancillary services (Energy Imbalance and Generator Imbalance), and no other ancillary services, could be encompassed by the existing market-based rate screens.35 The Commission sought comment on both this analysis and the resulting proposal.36 21. As discussed in more detail below, commenters addressed both the Commission’s ancillary service-byancillary service analysis of this issue, and the proposal to apply the existing market power screens to only the imbalance ancillary services. i. Application to Imbalance Ancillary Services Commission Proposal 22. In the NOPR, the Commission stated that resources capable of providing Energy Imbalance and Generator Imbalance do not appear to require any different technical 33 Studies of Simultaneous Transmission Import Limits (SIL) quantify a study area’s simultaneous import capability from its aggregated first-tier area. SIL studies are used as a basis for calculating import capability to serve load in the relevant geographic market when performing market power analyses. 34 See, Ocean Vista, 82 FERC ¶ 61,114, at 61,406– 07 (1998). 35 NOPR, FERC Stats. & Regs. ¶ 32,690 at PP 18– 24. 36 Id. P 24. PO 00000 Frm 00006 Fmt 4701 Sfmt 4700 37 Id. PP 19–20. Comments at 6; Beacon Comments at 5; Electricity Consumers Comments at 3; and EEI Comments at 9. 38 ESA E:\FR\FM\30JYR3.SGM 30JYR3 emcdonald on DSK67QTVN1PROD with RULES3 Federal Register / Vol. 78, No. 146 / Tuesday, July 30, 2013 / Rules and Regulations the appropriate balance between reducing barriers to entry and protecting against market power. 25. WSPP and Powerex, with Iberdrola concurring by reference, urge the Commission to clarify that this proposal includes the capacity associated with balancing energy sales, not just the energy.39 WSPP states that without the underlying capacity, sales of balancing energy could have no firmness and would be of little value in the market, in particular the bilateral market. Further, WSPP contends that the likely market for balancing energy would not differentiate energy and capacity products by OATT Schedules. Rather, sellers would sell ‘‘flexible capacity’’ capable of fulfilling multiple OATT Schedules and operators would look to flexible capacity to support various system stabilizing functions to which the OATT Schedules refer. Thus, WSPP contends that the market would be more efficient if the capacity and energy required to provide OATT services are not required to be unbundled when the natural market for supply would be a bundled ‘‘flexible capacity’’ product.40 26. Solar Energy Association states conceptual support for the proposal, but argues that sellers may have market power in certain ancillary services markets even if not in energy or capacity markets, and urges the Commission to police markets that are created due to the adoption of a rebuttable presumption of lack of market power.41 27. Two commenters express concern with the NOPR proposal. TAPS objects to the NOPR’s preliminary finding that any available unit in a given geographic market is capable of providing energy that helps address imbalances in that market. TAPS contends that significant technical limitations limit the resources that can provide imbalance services absent special arrangements like pseudo-ties, and therefore the first tier resources included in the horizontal market power screen are not generally available to provide intra-hour imbalance service. TAPS asserts that Order No. 890–A supports this contention by allegedly finding ‘‘that generation outside the control area can provide imbalance service when pseudo-tied and thus subject to withinarea dispatch control.’’ 42 TAPS further states that outside organized markets, generators capable of providing imbalance service must have a special relationship with the control area operator in order to supply changing within-the-hour energy needs, without the constraints of hourly transmission scheduling requirements and that even the recently adopted 15-minute scheduling requirement is insufficient, especially when combined with the need to schedule 20 minutes in advance.43 28. TAPS asserts that, in non-RTO regions, imbalance service is typically provided by the energy associated with regulation and operating reserves, and thus resources capable of providing imbalance services would necessarily be subject to the same technical requirements as the NOPR described for regulation and operating reserves.44 TAPS supports this assertion by claiming that Order No. 890 found that ‘‘demand costs of providing imbalance service are already being provided under Schedule 3, 5, and 6 charges [i.e., Regulation and Frequency Response Service, Operating Reserve-Spinning Reserve Services, and Operating Reserve Supplemental Reserve Services].’’ 45 29. TAPS further rejects the Commission’s assertion in the NOPR that this proposal is consistent with the decision in Order No. 890–A to base cost-based imbalance charges in the OATT on the incremental cost of the last 10 MW dispatched by the transmission provider for any purpose, without imposing any requirement that this last 10 MW be based on resources with any particular capabilities.46 TAPS contends that the pricing of OATT imbalance service does not demonstrate the absence of the alleged restrictions described above on the supply of intrahour energy that allows transmission providers to provide energy imbalance service. 30. Morgan Stanley contends that the existing market power screens are flawed even in their application to energy and capacity products and thus should not be applied to additional products. Morgan Stanley argues that the existing market power screens in some cases fail to assess the full import capability into a given geographic market, and thus the true market size. Morgan Stanley ultimately argues that a revised market power screen ‘‘should include any transmission located outside of the relevant market area, but which is interconnected and over which 43 Id. at 11–13. at 12–13. 45 Id. at 12 (citing Order No. 890, FERC Stats. & Regs. ¶ 31,241 at P 690). 46 NOPR, FERC Stats. & Regs. ¶ 32,690 at P 19 (citing Order No. 890–A, FERC Stats. & Regs. ¶ 31,261 at P 309). 44 Id. 39 WSPP Comments at 6; and Powerex Comments at 9–10. 40 WSPP Comments at 7. 41 Solar Energy Association Comments at 4. 42 TAPS Comments at 11–12. VerDate Mar<15>2010 17:15 Jul 29, 2013 Jkt 229001 PO 00000 Frm 00007 Fmt 4701 Sfmt 4700 46183 there is transfer capacity.’’ 47 However, Morgan Stanley does not state opposition to the idea that a lack of market power in energy and capacity can justify an assumption of equivalent lack of market power in Energy Imbalance and Generator Imbalance services. Commission Determination 31. The Commission will adopt its proposal with modification. The Commission will allow third-party sellers passing existing market power screens to sell Energy Imbalance and Generator Imbalance services at marketbased rates to a public utility transmission provider within the same balancing authority area, or to a public utility transmission provider in a different balancing authority area, if those areas have implemented intrahour scheduling for transmission service.48 The Commission continues to believe that there are no unique technical requirements or limitations that apply to a resource’s provision of Energy Imbalance or Generator Imbalance services. However, the Commission agrees with TAPS that the delivery of Energy Imbalance and Generator Imbalance services may be limited by hourly transmission scheduling practices in place within certain regions and, as such, refines the NOPR proposal as discussed below. 32. Energy Imbalance and Generator Imbalance services are a subset of a broader set of ancillary services offered by a public utility transmission provider to manage system conditions and ensure reliable transmission service. Energy Imbalance and Generator Imbalance services involve the balancing of differences between scheduled and actual delivery of energy or output of generation over an hour.49 In comparison, Regulation and Frequency Response service involves the matching of resources to load in a shorter timeframe, requiring automated dispatch at four- or five-second intervals.50 As a result, resources used 47 Morgan Stanley Comments at 2–5. note that sales of Energy Imbalance and Generator Imbalance services to entities other than a public utility transmission provider remain authorized under Avista. 49 See pro forma OATT, Schedules 4 and 9. Under the pro forma OATT, imbalances are calculated and charged on an hourly basis. See Order No. 890, FERC Stats. & Regs. ¶ 31,241 at P 722; Order No. 890–A, FERC Stats. & Regs. ¶ 61,297 at P 325 & n.117; see also Order No. 764, FERC Stats. & Regs. ¶ 32,331 at P 104. Energy Imbalance and Generator Imbalance services also may be self-supplied by a transmission customer. 50 See, e.g., Pro Forma OATT, Schedule 3 Regulation and Frequency Response Service— ‘‘Regulation and Frequency Response Service is 48 We E:\FR\FM\30JYR3.SGM Continued 30JYR3 emcdonald on DSK67QTVN1PROD with RULES3 46184 Federal Register / Vol. 78, No. 146 / Tuesday, July 30, 2013 / Rules and Regulations to provide Regulation and Frequency Response service must be capable of balancing moment-to-moment fluctuations, whereas resources used to provide Energy and Generator Imbalance can respond at longer time frames within the hour. 33. In practice, public utility transmission providers often have a portfolio of resources, some owned and some purchased from third-parties, from which they provide capacity, energy, and ancillary services. This portfolio typically includes resources with automatic generation control (AGC) equipment capable of handling both moment-by-moment frequency adjustments and longer duration imbalance needs, as well as other capacity and energy resources that may only be capable of addressing longer duration imbalance needs because they are not equipped with AGC. These longer duration resources may include block purchases from third parties that are dispatched or otherwise scheduled at varying timeframes. The relative amount of AGC-controlled and other resources used by a public utility transmission provider for intra-hour balancing will depend on the resources available and the public utility transmission provider’s operating practices. 34. In the NOPR, the Commission did not separately discuss this range of resources and, instead, preliminarily concluded that there are no unique technical requirements or limitations that distinguish the resources capable of providing energy and capacity from those capable of providing imbalance services. The majority of commenters agree with the Commission’s preliminary conclusion, arguing that the set of resources available to follow imbalances over an hour is the same set of resources capable of providing energy and capacity. However, TAPS disagrees, arguing that the set of resources capable of providing imbalance services must have a special relationship with the control area operator in order to supply changing within-the-hour energy needs. 35. We understand TAPS’ argument to be that resources used to provide imbalance service must be able to respond to a dynamic four- or fivesecond signal, which might require special arrangements in order to permit imbalance sales outside of the resource’s home balancing authority area such that even the ability to submit transmission schedules on a 15-minute basis would be insufficient to provide intra-hour necessary to provide for the continuous balancing of resources (generation and interchange) with load . . . .’’ VerDate Mar<15>2010 17:15 Jul 29, 2013 Jkt 229001 imbalance energy.51 We agree that some of the public utility transmission provider’s energy imbalance needs are addressed by resources that manage the moment-by-moment difference between load and resources. We also agree that imbalance service would generally require deliveries on intervals shorter than the current hour. But we do not agree, as explained more fully below, that imbalance services require dynamic dispatch or more sophisticated delivery mechanisms than intra-hour transmission scheduling. 36. Under the pro forma OATT, imbalances are calculated on an hourly basis.52 As a result, any energy deliveries within the hour can be used by a public utility transmission provider (or by a transmission customer) to manage imbalances across the hour. That is, energy deliveries within the hour can be included in the portfolio of resources used to follow imbalance trends across the hour, similar to a public utility transmission provider’s decision to redispatch its own internal resources within the hour. While it is true, as TAPS states, that dynamically dispatched resources capable of providing regulation also would be capable of providing imbalance services, it does not follow that resources using intra-hour transmission schedules are incapable of providing imbalance services. As noted above, imbalance service can be provided from a collection of resources so long as they are deliverable within the hour.53 37. The question before the Commission here is whether the set of resources considered available to provide energy and capacity in a market power analysis is sufficiently similar to the set of resources capable of providing imbalance services. Based on the record before us in which numerous commenters agree that the resources are sufficiently similar and given that intrahour transmission schedules are currently being offered by a number of public utility transmission providers, and must be offered by all public utility transmission providers under Order No. 764 on or before November 12, 2013,54 Comments at 13. Order No. 890, FERC Stats. & Regs. at P 722, order on reh’g, Order No. 890–A, FERC Stats. & Regs. ¶ 61,297 at P 325 & n.117; see also Order No. 764, FERC Stats. & Regs. ¶ 32,331 at P 104. 53 The Commission acknowledges that energy purchases scheduled on an hourly basis might enable a public utility transmission provider to use other resources to provide imbalance or other ancillary services more efficiently or precisely. Such hourly sales of energy would not be an indirect sale of ancillary services within the meaning of Avista. 54 In order to comply with Order No. 764, public utility transmission providers must allow PO 00000 51 TAPS 52 See Frm 00008 Fmt 4701 Sfmt 4700 the Commission finds it appropriate at this time to revise the Avista restriction to better reflect current operational realities. 38. With regard to TAPS’ additional comments in support of its basic argument, as stated above, just because a public utility transmission provider may have chosen to rely on the energy associated with regulation or operating reserves to meet imbalances, it does not follow that those are the only resources capable of providing imbalance services. Moreover, TAPS’ reference to a portion of a passage from Order No. 890 referring to demand costs of providing imbalance energy being recoverable through regulation (Schedule 3) and operating reserve (Schedules 5 and 6) services is not dispositive here. The rate mechanisms used by a public utility transmission provider to recover the cost of capacity associated with providing Energy Imbalance or Generator Imbalance service do not precisely reflect the technical capabilities of resources available to provide the imbalance services. There is no requirement, in past Commission pronouncements or otherwise, that imbalance services be provided only from resources capable of providing regulation or operating reserves. Indeed, TAPS criticizes the NOPR for asserting the Commission’s proposal was consistent with the decision in Order No. 890–A to base cost-based imbalance charges on the incremental cost of the last 10 MW dispatched by the transmission provider for any purpose, without imposing any requirement that this last 10 MW be based on resources with any particular capabilities.55 We agree with TAPS that the pricing of OATT imbalance services does not necessarily determine the technical capabilities of resources available to provide those services and reject the NOPR’s assertion in this regard. Similarly, we find that the pricing of regulation and operating reserve services, whether through Schedules 3, 5, 6 or some other mechanism (such as generator regulation service), do not necessarily determine the technical capabilities of resources available to provide imbalance services. 39. TAPS also cites Order No. 890–A as finding that generation outside a control area can provide imbalance transmission customers to modify existing schedules as well as create new transmission schedules at intervals not to exceed 15 minutes, on or before November 12, 2013. Order No. 764, FERC Stats. & Regs. ¶ 32,331 at P 91, order on reh’g, Order 764–A, 141 FERC ¶ 61,232. 55 See NOPR, FERC Stats. & Regs. ¶ 32,690 at P 19 (citing Order No. 890–A, FERC Stats. & Regs. ¶ 31,261 at P 309). E:\FR\FM\30JYR3.SGM 30JYR3 emcdonald on DSK67QTVN1PROD with RULES3 Federal Register / Vol. 78, No. 146 / Tuesday, July 30, 2013 / Rules and Regulations service when pseudo-tied and thus subject to within-area dispatch.56 The cited passage of Order No. 890–A, however, states that a pseudo-tie arrangement causes a control area to ‘‘assum[e] responsibility for ensuring that the load is properly balanced moment-to-moment, for planning for the load, and for providing various other ancillary services including energy or generator balancing service.’’ The Commission made no determination in that passage as to the universe of resources capable, or incapable, of providing imbalance services. Nevertheless, the Commission acknowledges that some public utility transmission providers may choose not to purchase imbalance service from resources that cannot also be dynamically dispatched. While that may inform the relative ability of a resource to find a buyer for its service, it does not define the set of resources from which imbalance services are available, which is the relevant question for market power analyses. 40. We also find the opposing arguments of Morgan Stanley to be beyond the scope of this proceeding. Morgan Stanley does not appear to object to the use of the same market power screens for energy, capacity and imbalance services. Rather, Morgan Stanley argues that the existing indicative screens should be reformulated to include greater transmission imports than are currently assumed. Arguments as to the make-up of the existing market power screens are beyond the scope of this proceeding. The question before us in this proceeding is whether the resources in a given geographic market capable of providing imbalance ancillary services are sufficiently similar to the resources capable of providing energy and capacity that the same market power analysis can apply to both sets of products. Moreover, the Commission already permits applicants to demonstrate that the relevant geographic market is larger or smaller than that default.57 41. Accordingly, this Final Rule establishes that sellers found to lack market power in a geographic market, and which are granted market-based rate authority to make sales of energy and capacity, will also be granted marketbased rate authority for sales of Energy Imbalance and Generator Imbalance services to public utility transmission providers within the same balancing 56 TAPS Comments at 12 (citing Order No. 890– A, FERC Stats. & Regs. ¶ 31,261 at P 631). 57 Order No. 697, FERC Stats. & Regs. ¶ 31,252 at P 268. VerDate Mar<15>2010 17:15 Jul 29, 2013 Jkt 229001 authority area, or to public utility transmission providers in different balancing authority areas, if those areas allow transmission customers to modify or create transmission schedules within the hour. Because, as explained above, such scheduling practices enable the delivery of within-hour imbalance services from one balancing authority area to another, their use ensures that the first-tier resources included in the existing market power screens can compete with resources in the home balancing authority area, and thus that the existing market power screens can be applied to imbalance services without modification. This finding applies both to sellers that currently have a market-based rate tariff on file and applicants seeking market-based rate authority. For administrative convenience, we make this change to the Commission’s ancillary services pricing policy effective as of the effective date of this Final Rule (120 days after publication in the Federal Register), which will result in these changes becoming effective after November 12, 2013, the date by which all public utility transmission providers must offer intra-hour transmission scheduling. As noted above, we acknowledge that some transmission providers already offer intra-hour scheduling. However, rather than performing a transmission provider-bytransmission provider review of current scheduling practices in this rulemaking, the Commission will defer implementation of this change to our ancillary services pricing policy until after the effectiveness of the intra-hour scheduling requirements of Order No. 764, by which time all public utility transmission providers must offer intrahour scheduling. Thus, as of the effective date, all sellers that have a market-based rate tariff on file as of that date may begin making third-party sales of Energy Imbalance and Generator Imbalance services at market-based rates to a public utility transmission provider that is purchasing Energy Imbalance and Generator Imbalance services to satisfy its own open access transmission tariff requirements to offer ancillary services to its own customers, without having to make a separate showing to the Commission. 42. In response to WSPP, we clarify that this authorization to undertake sales at market-based rates may include both the capacity and the energy associated with providing Energy Imbalance and Generator Imbalance services. Imbalance services are products designed to address differences between scheduled and PO 00000 Frm 00009 Fmt 4701 Sfmt 4700 46185 actual deliveries and withdrawals of energy. As such, they can only be provided by ensuring the availability of capacity and then increasing or decreasing the energy output from that capacity as necessary to address these differences.58 ii. Application to Other Ancillary Services Commission Proposal 43. In the NOPR, the Commission proposed to allow the existing marketbased rate screens to be applied to Energy Imbalance and Generator Imbalance services, but sought comment on whether the characteristics of resources used to provide the other ancillary services would necessitate a market power analysis based on a different geographic market or different set of resources as compared to those analyzed to determine market power for sales of energy and capacity.59 44. With regard to Operating ReserveSpinning and Operating ReserveSupplemental, the NOPR discussed the technical considerations, such as minimum ramp and start-up rates for off-line resources and the ability for extended operation below fully loaded set point for online resources, that seemed to indicate that fewer resources would be capable of providing these ancillary services as compared to the set of resources capable of providing energy or capacity. With regard to Reactive Supply and Voltage Control from Generation Sources, the NOPR discussed the technical and geographic considerations that generally limit the resources capable of providing this ancillary service as compared with the broader set of resources capable of providing energy or capacity. With regard to Regulation and Frequency Response, the Commission discussed the technical requirements, such as automatic generation control (AGC) equipment, that limit the set of resources capable of supplying this ancillary service.60 Comments 45. A number of commenters argue for application of the existing market power screens to Operating Reserve-Spinning and Operating Reserve-Supplemental.61 EPSA argues that operating reserves are 58 See, e.g., Order No. 764, FERC Stats. & Regs. ¶ 32,331 at P 240. 59 NOPR, FERC Stats. & Regs. ¶ 32,690 at P 24. 60 Id. PP 22–23. 61 EPSA Comments at 6, WSPP Comments at 8 (with Iberdrola supporting by reference), EEI Comments at 3 and 10, Western Group Comments at 3–4, Hydro Association Comments at 7, and Powerex Comments at 7 and 13. E:\FR\FM\30JYR3.SGM 30JYR3 emcdonald on DSK67QTVN1PROD with RULES3 46186 Federal Register / Vol. 78, No. 146 / Tuesday, July 30, 2013 / Rules and Regulations merely derivatives of a resource’s ability to generate energy.62 46. WSPP argues that the same considerations that led the Commission to believe that the rebuttable presumption should be extended to the imbalance ancillary services also apply to the operating reserve ancillary services. WSPP further asserts that all of these ancillary services are widely deliverable and that all generators capable of being redispatched to higher or lower set-points within a scheduling window are capable of providing these ancillary services.63 47. EEI argues that except for variable energy resources, essentially the same set of resources evaluated as competing supply under the existing market power screens possess the required technical capabilities to provide operating reserves.64 Western Group makes a similar argument, asserting that products in Schedules 3, 5, and 6 (Regulation and Operating Reserves) share operational characteristics of Schedules 4 and 9 (Imbalance services).65 48. While Powerex agrees that resources capable of providing spinning and non-spinning reserves may be limited by response time requirements, Powerex argues that the existing market power screens nonetheless can be applied to operating reserve services.66 49. With respect to Regulation and Frequency Response, some commenters argue that passage of the existing market power screens indicates lack of market power for that service. For example, while EPSA agrees that the market power of sellers of Reactive Supply and Voltage Control service cannot be gauged by the existing market power screens due to significant technical and geographic impediments, it argues that Regulation and Frequency Response service is merely a derivative of a resource’s ability to generate energy. Accordingly, EPSA argues that application of the existing market power screens to this ancillary service would be appropriate.67 50. Powerex agrees that the existing market power screens could be applied to Regulation and Frequency Response service. Powerex believes that technical improvements such as the dynamic scheduling system adopted by some users of the Western Interconnection facilitate widespread delivery of 62 EPSA Comments at 6. Comments at 8. Iberdrola supports these WSPP comments by reference. 64 EEI Comments at 10. 65 Western Group Comments at 3. 66 Powerex Comments at 7 and 13. 67 EPSA Comments at 6. 63 WSPP VerDate Mar<15>2010 17:15 Jul 29, 2013 Jkt 229001 regulating reserves, thus overcoming any locational requirements for that service, while any technical impediments could be overcome because AGC or equivalent power electronic controls could be added by most market participants if the markets provide correct price signals.68 WSPP similarly argues that, while not all generators have the AGC equipment needed to provide Regulation and Frequency Response service, installation of this capability is an economic decision and is not such an impediment that it should be treated as a market defining barrier to entry.69 51. FTC Staff urges the Commission to recognize that even though a particular resource may not currently have the ability to provide a given ancillary service due to lack of relevant equipment, if such equipment could be installed in a timely fashion in response to high prices, then such resource should be considered a potential competitor for purposes of market power analysis. Accordingly, FTC Staff suggests that the Commission revise its market power analysis to incorporate as existing market participants those potential entrants that are likely to enter a given ancillary service market (i.e., install needed equipment such as AGC) rapidly and profitably should market prices justify such entry.70 52. EEI argues that, before extending application of the existing market power screens to Regulation and Frequency Response, the Commission should separate this service into two separate ancillary services: primary frequency control and secondary frequency control. EEI argues that secondary frequency control, which it labels as Regulation, is a prime candidate to be extended the rebuttable presumption (i.e., to be subject to the existing market power screens).71 53. Two parties filed comments opposing the application of existing market power screens to non-imbalance ancillary services. Southern California Edison and TAPS state that they agree with the NOPR’s reasoning as to why the existing market power screens cannot be applied to non-imbalance ancillary services.72 Remaining commenters did not address the question of applying the existing market power screens to non-imbalance ancillary services. Comments at 12. Comments at 8. Iberdrola supports these WSPP comments by reference. 70 FTC Staff Comments at 6–8. 71 EEI Comments at 10–11. 72 Southern California Edison Comments at 1–2; and TAPS Comments at 9–10. PO 00000 68 Powerex 69 WSPP Frm 00010 Fmt 4701 Sfmt 4700 Commission Determination 54. Upon consideration of the comments to the NOPR, and as discussed more fully below, the Commission will allow third-party sellers passing existing market power screens to sell Operating ReserveSpinning and Operating ReserveSupplemental services at market-based rates to a public utility transmission provider within the same balancing authority area, or to a public utility transmission provider in a different balancing authority area, if those areas have implemented intra-hour scheduling for transmission service that supports the delivery of operating reserve resources from one balancing authority area to another. Commenters have persuaded us that to the extent there are technical requirements and limitations associated with operating reserves, they do not materially distinguish resources capable of providing energy and capacity from those capable of providing operating reserves. As with the imbalance services, however, the Commission finds that the delivery of operating reserves from one balancing authority area to another may be limited by hourly scheduling practices in place within certain regions, which could impact the assumption in the existing market power screens that first-tier resources are able to compete with home balancing authority area resources. Therefore, the Commission will allow third-party sellers passing existing market power screens to sell these services to public utility transmission providers to the extent within-hour transmission service scheduling practices, including intrahour transmission scheduling mandated by Order No. 764, support the delivery of operating reserves from one balancing authority area to another. 55. In contrast, the Commission affirms the preliminary finding in the NOPR that the set of resources capable of providing Regulation and Frequency Response service and Reactive Supply and Voltage Control service would differ significantly from the broader set of resources capable of supplying energy and capacity. Accordingly, the Avista restrictions will remain in place for sales of those services to public utility transmission providers at market-based rates. As noted below, the Commission will establish a new proceeding to further explore the technical, economic and market issues concerning the provision of Reactive Supply and Voltage Control service and Regulation and Frequency Response service. E:\FR\FM\30JYR3.SGM 30JYR3 emcdonald on DSK67QTVN1PROD with RULES3 Federal Register / Vol. 78, No. 146 / Tuesday, July 30, 2013 / Rules and Regulations Operating Reserve Services 56. Operating Reserve-Spinning and Operating Reserve-Supplemental are products designed to serve load temporarily in the event of contingencies. As such, sellers must ensure the availability of capacity sufficient to address a contingency event and, if the contingency occurs, energy must be supplied from that capacity. While the NOPR preliminarily found that the operating reserve products appeared to require the availability of resources with relatively fast ramping capabilities, and in the case of off-line resources used for operating reserve-supplemental, relatively fast start-up capabilities as well,73 comments to the NOPR argue otherwise. 57. Many comments to the NOPR make the case that the flexibility and response time requirements associated with operating reserve services are not so significant that the universe of resources that can provide these services is meaningfully different than the universe of resources used to assess energy and capacity market power. While traditional generation scheduling practices only require the resources that provide energy and capacity to be able to change output levels once an hour, the record in this proceeding indicates that most resources can change output levels on shorter time scales. In other words, most conventional resources can change output in response to contingency events on a time scale shorter than the typical hourly scheduling window, even if in the past they have only been selling hourly block energy and capacity. Therefore, the Commission will allow third-party sellers passing existing market power screens for energy and capacity for a given market to also sell Operating Reserves-Spinning and Operating Reserves-Supplemental services at market-based rates to a public utility transmission provider within the same balancing authority area, or to a public utility transmission provider in a different balancing authority area, if within-hour transmission scheduling practices in those areas support the delivery of operating reserves from one balancing authority area to another.74 58. We note that our approach for market-based sales of operating reserves differs slightly from the reforms adopted 73 See NOPR, FERC Stats. & Regs. ¶ 32,690 at P 22. 74 As with Energy Imbalance and Generator Imbalance services, we clarify that the authorization to undertake sales at market-based rates may include both the capacity and the energy associated with providing Operating Reserve-Spinning and Operating Reserve-Supplemental services. VerDate Mar<15>2010 17:15 Jul 29, 2013 Jkt 229001 above for sales of imbalance services. We have found above that the existence of 15-minute scheduling in a region renders the set of resources capable of supplying imbalance services substantially similar to the set of resources capable of providing energy and capacity so that the same market power screens can be applied to both sets of services. This may not be the case in all circumstances for potential sellers of operating reserves and, therefore, we require such entities to explain in their market-based rate applications for such authority how the scheduling practices in their regions support the use of operating reserves. For example, while 15-minute scheduling might be sufficient for Operating Reserve-Supplemental because this service only requires designated resources to be available within a short period of time,75 15minute scheduling by itself may not be sufficient for Operating ReserveSpinning, which requires designated resources to be available immediately.76 The Commission recognizes that unlike the imbalance services, operating reserve services are targeted only at addressing contingency events, and some regions such as WECC may have already developed within-hour capacity tagging and scheduling practices intended to support the use of operating reserves across multiple balancing authority areas.77 These are the types of region-specific practices that sellers seeking authority to sell operating reserves to public utility transmission providers should describe in their market-based rate applications. Thus, as of the effective date of this Final Rule, both sellers that have a market-based rate tariff on file as of that date and applicants seeking new market-based rate authority must satisfactorily make the above showing and receive Commission authorization before making sales of Operating ReserveSpinning and Operating Reserve75 See pro forma OATT, Schedule 6 ‘‘Supplemental Reserve Service is needed to serve load in the event of a system contingency; however, it is not available immediately to serve load but rather within a short period of time.’’ 76 Id. Schedule 5 ‘‘Spinning Reserve Service is needed to serve load immediately in the event of a system contingency.’’ 77 See, e.g., WECC Regional Business Practice INT–018–WECC–RBP–0, Tagging Protocols, at WR5.1 and WR5.2, defining capacity e-tags for, respectively, spinning reserves and non-spinning reserves as ‘‘product(s) that can be activated through the adjustment of a capacity e-tag.’’ Available at https://www.wecc.biz/library/ Documentation%20Categorization%20Files/Forms/ AllItems.aspx?RootFolder=%2flibrary%2f Documentation%20Categorization%20Files%2f Regional%20Business%20Practices&FolderCTID= 0x01200015E7900DB2E794468FDE06D520B95C07. PO 00000 Frm 00011 Fmt 4701 Sfmt 4700 46187 Supplemental to a public utility that is purchasing Operating Reserve-Spinning and Operating Reserve-Supplemental to satisfy its own open access transmission tariff requirements to offer ancillary services to its own customers. Regulation and Reactive Power Services 59. The Commission affirms the preliminary finding in the NOPR that the more stringent technical and geographic considerations associated with the regulation and reactive power ancillary services suggest that they are not simple combinations of basic energy and capacity products. Most commenters addressing this issue agree that the set of resources considered by the existing market power screens would differ too significantly from the set of resources that would be considered by market power analyses designed specifically for Reactive Supply and Voltage Control service. 60. While some commenters do argue that the existing market power screens are adequate for Regulation and Frequency Response service, we are not persuaded by their arguments on the record here. We continue to believe that significant technical requirements, such as the need for AGC equipment, limit the set of resources capable of supplying this ancillary service. While we agree in principle with FTC Staff’s comments that potential competitors could be viewed as existing competitors for purposes of market power analysis if it is known that they can install needed equipment rapidly and profitably in response to appropriate price signals, the record does not conclusively support the notion that such equipment upgrades (e.g., to install AGC equipment in an existing generator) can be accomplished in such a manner. Although Powerex asserts that AGC or equivalent power electronic controls could be added by most market participants if the markets provide correct price signals, and WSPP asserts that the addition of AGC is an economic decision, we are not persuaded based on the limited information in the record before us. Also, the record indicates that third-party sellers of Regulation and Frequency Response service might need to enter into or facilitate special arrangements between neighboring balancing authorities, such as dynamic scheduling or pseudo-tie arrangements, in order to make sales outside of their home balancing authority area. 61. Accordingly, because the record before us does not support a modification at this time, the Avista restrictions will remain in place for sales of Regulation and Frequency Response and Reactive Supply and E:\FR\FM\30JYR3.SGM 30JYR3 46188 Federal Register / Vol. 78, No. 146 / Tuesday, July 30, 2013 / Rules and Regulations Voltage Control services to a public utility transmission provider that is purchasing these ancillary services to satisfy its own OATT requirements to offer ancillary services to its own customers. However, the Commission intends to gather more information regarding this issue in a separate, new proceeding that will further explore the technical, economic and market issues concerning the provision of Reactive Supply and Voltage Control service and Regulation and Frequency Response service. Such proceeding will consider, among other things, the ease and costeffectiveness of relevant equipment upgrades, the need for and availability of appropriate special arrangements such as dynamic scheduling or pseudotie arrangements, and other technical requirements for provision of Regulation and Frequency Response and Reactive Supply and Voltage Control services. emcdonald on DSK67QTVN1PROD with RULES3 b. Optional Market Power Screen Commission Proposal 62. In the NOPR, the Commission proposed a new optional market power screen solely applicable to ancillary services, together with a limited new reporting requirement that would provide potential sellers of ancillary services with the information needed to develop market power analyses using that optional market power screen.78 Specifically, the optional market power screen for an ancillary service would compare the amount of capacity in MWs (or, as applicable, MVARs) that a potential seller can dedicate to providing the ancillary service in the relevant geographic market with the buyer’s aggregate requirement for that ancillary service, taking into account any historical locational requirements (e.g., locational requirements due to such things as binding transmission constraints or the geographic limitations of Reactive Supply). Using this optional market power screen, sellers whose available capacity is no more than 20 percent of the relevant aggregate requirement for an ancillary service would receive a rebuttable presumption that they lack horizontal market power for the ancillary service in question. 63. In order to provide sellers with information as to the buyer’s aggregate requirement for an ancillary service, the Commission proposed to require each public utility transmission provider to publicly post on its OASIS the aggregate amount (MW or MVAR, as applicable) of each ancillary service that it has historically required, including any geographic limitations it may face in 78 NOPR, meeting such ancillary service requirements. For example, a transmission provider may report that it has historically maintained 100 MW of Regulation and Frequency Response reserves for its balancing authority area and 100 MVAR of Reactive Supply and Voltage Control in each of two submarkets within its balancing authority area. Comments 64. Some commenters support the optional market power screen on the basis that it provides a practical alternative to performing a traditional market power analysis, given the data constraints associated with the latter. WSPP, for example, states that the optional market power screen is a constructive response to the disconnection between regulatory market power study requirements and the incapability of market participants to perform those studies due to lack of data.79 WSPP states that it strongly supports the Commission’s proposal that public utility transmission providers be required to post the information needed for sellers to prepare the optional market power screen if the rebuttable presumption applicable to the imbalance ancillary service is not extended to all ancillary services.80 65. Public Interest Organizations argue that the optional screen is similar in intent to a de minimis capacity threshold and, as such, can remove the barrier of a burdensome market power analysis for smaller entities.81 The Solar Energy Association asserts that the optional market power screen likely will broaden the number of participants in the markets for certain ancillary services.82 Electricity Consumers similarly argues that the optional market power screen should reduce barriers to ancillary service providers and increase the supply of ancillary services in a timely and cost-effective manner.83 66. However, there was no consensus among the commenters supporting the proposed optional market power screen regarding the necessary granularity of the associated reporting requirement. Some commenters, such as WSPP and Shell Energy, argue that postings should reflect a transmission provider’s annual peak requirements for ancillary services, rather than annual averages. WSPP argues that posting an annual average would tend to understate requirements FERC Stats. & Regs. ¶ 32,690 at PP 25– 30. VerDate Mar<15>2010 17:15 Jul 29, 2013 Jkt 229001 PO 00000 79 WSPP Comments at 12. at 10. 81 Public Interest Organizations Comments at 6. 82 Solar Energy Association Comments at 5. 83 Electricity Consumers Comments at 3. 80 Id. Frm 00012 Fmt 4701 Sfmt 4700 for higher periods, thereby skewing screen results in the direction of violations.84 Similarly, Shell Energy states that relying on annual peaks is preferable to annual averages because it better reflects the amounts that transmission providers need to procure. Shell Energy further argues that postings of annual peak values are preferable to postings of seasonal or quarterly values, which Shell Energy claims would be burdensome for transmission providers and suppliers.85 67. Conversely, the ESA, Beacon, and California Storage Alliance recommend that public utilities provide seasonal and time-of-day requirements (if any) for each ancillary service versus a single average annual amount and note that this is consistent with the type of data provided by RTOs/ISOs in the open wholesale markets.86 68. Some commenters oppose the optional market power screen, arguing that it would yield too many false positives because it does not measure a seller’s ability to supply relative to the total potential supply of the overall market. EPSA, for example, argues that the optional screen would routinely result in false-positive indications of market power.87 EPSA states that if the Commission decides to use a threshold test, it should compare the subject generator to total product capability, not merely the quantity demanded.88 EEI similarly argues that the optional screen likely will result in many suppliers failing the 20 percent threshold.89 EEI contends that there are alternatives that would refine the test to be more applicable and useful in promoting robust participation in competitive ancillary services markets in bilateral regions. EEI offers as an example requiring transmission providers to report on its OASIS in the aggregate its historical demand and its historical ability to supply the relevant ancillary services. EEI offers that if the Commission decides to pursue optional screen it should have a technical conference.90 69. Powerex claims that the optional market power screen does not appear workable in certain respects and is likely to result in too many false positives.91 Powerex argues that establishing a test that is overly restrictive, and that a majority of sellers 84 WSPP Comments at 11. Energy Comments at 8. 86 ESA Comments at 7; Beacon Comments at 6; and California Storage Alliance Comments at 4. 87 EPSA Comments at 6. 88 Id. at 7. 89 EEI Comments at 16. 90 EEI Comments at 15. 91 Powerex Comments at 16. 85 Shell E:\FR\FM\30JYR3.SGM 30JYR3 Federal Register / Vol. 78, No. 146 / Tuesday, July 30, 2013 / Rules and Regulations emcdonald on DSK67QTVN1PROD with RULES3 will not be able to satisfy, will create a significant administrative burden that will continue to pose an obstacle to the development of competitive markets for ancillary services.92 Powerex asserts that when using market shares as a metric of market power, the proper measurement is a seller’s ability to supply relative to the total potential supply of the overall market.93 70. Morgan Stanley argues that the optional market power screen does not provide a complete picture of an entity’s market power and that it is more relevant to compare the amount of supply a seller controls to the total supply available and the total market demand, than it is to compare it to a single buyer’s requirements.94 Morgan Stanley claims that a seller actually could have greater market power even if it only can serve a small portion of the buyer’s aggregate requirements if the buyer has no other viable options for procuring the remaining portion of its ancillary service needs.95 71. Other commenters oppose the optional market power screen on the basis that its need and usefulness is unclear. For example, TAPS argues that the usefulness of the optional screen is uncertain, particularly given the acknowledged data limitations. TAPS further argues that one cannot be confident that the proxy would provide a meaningful screen for market power.96 72. The California PUC states that is sees no need for alternative methodologies and further argues that a 20 percent threshold is too high for ancillary services.97 The Hydro Association also states that it does not see a need at this time for the Commission to develop alternative market screens.98 Commission Determination 73. The Commission will not adopt the optional market power screen for ancillary services as proposed in the NOPR. As suggested by EEI, ESPA and others, the fact that the proposed optional screen would not consider the full amount of competing supply available to a buyer likely means that the screen may result in so many false positive indications of potential market power that it would provide little benefit to the effort to foster competition in ancillary service markets. 74. The comments also indicate that establishing the reporting requirements 92 Id. at 17. at 19. 94 Morgan Stanley Comments at 6. 95 Id. at 7. 96 TAPS Comments at 14. 97 California PUC Comments at 5–6. 98 Hydro Association Comments at 8. 93 Id. VerDate Mar<15>2010 17:15 Jul 29, 2013 Jkt 229001 associated with the optional market power screen would not be a trivial task, particularly given the lack of consensus regarding the granularity of information needed. The Commission believes that the costs of developing and imposing this new reporting requirement on transmission providers might not be justified, particularly in light of the other actions taken in this Final Rule. The need for the proposed optional screen, and its associated reporting requirement, is significantly reduced because this Final Rule, as explained above, will permit sellers to apply the existing market power screens to imbalance and operating reserve ancillary services. As such, the Commission has determined not to adopt the optional market power screen and its associated reporting requirement. Alternative Mitigation 75. In the NOPR, the Commission proposed to permit sellers unable or unwilling to perform the market power study for ancillary services to propose price caps at or below which sales of Regulation and Frequency Response, Reactive Supply and Voltage Control, Operating Reserve-Spinning, or Operating Reserve-Supplemental service would be allowed where the purchasing entity is a public utility transmission provider purchasing ancillary services to satisfy its OATT requirements to offer ancillary services to its own customers.99 Such a price cap would have been based on one of the two possible OATT ancillary service rate caps discussed below and, as in Avista, the Commission proposed that sales under these price caps would only be permitted in geographic markets where the seller has been granted market-based rate authority for sales of energy and capacity. In addition, a seller unable to perform a market power study for ancillary services could rely on competitive solicitations meeting certain minimum requirements in order to make sales in geographic markets where the seller has been granted market-based rate authority for sales of energy and capacity. Use of Price Caps Commission Proposal 76. In the NOPR, the Commission proposed two cost-based mitigation measures as alternatives to the prohibition adopted in Avista with regard to sales to a public utility transmission provider that is purchasing ancillary services to meet its OATT 99 NOPR, FERC Stats. & Regs. ¶ 32,690 at PP 33– 40. PO 00000 Frm 00013 Fmt 4701 Sfmt 4700 46189 requirements to offer ancillary services to its own customers. Sales of ancillary services at or below either alternative would be permitted. Under the first, third parties would be permitted to sell to a public utility transmission provider at rates not to exceed the buying public utility transmission provider’s existing OATT rate for the same ancillary service. Under the second option, third parties could propose to sell a given ancillary service to a public utility transmission provider at rates not to exceed the highest public utility transmission provider OATT rate within the relevant geographic market for physical trading of the ancillary service in question. The Commission proposed that the seller (or group of sellers) would file with the Commission a proposal that defines the scope of a contiguous geographic region that both encompasses the service territory(ies) of the public utility transmission provider whose OATT ancillary service rate will form the basis for the price cap, and within which trading of the ancillary service in question is physically possible. Single OATT Rate Cap Option Comments 77. There was a range of support for the establishment of a rate cap at the buyer’s OATT rate for the same ancillary service. TAPS and Southern California Edison support this proposal outright as an option to enable ancillary service sales.100 EEI states that while the Commission should primarily rely on existing market power analyses and screens to allow third-parties to sell certain ancillary services at marketbased rates, cost-based mitigation measures are also appropriate in certain seller-specific circumstances. EEI states that these two alternative options should be included in any Final Rule. EEI contends that this flexibility should encourage an increased number of participating sellers in bilateral markets, provide options for transmission providers to meet obligations, create market efficiencies, and potentially lower prices.101 78. WSPP states that it supports inclusion of this option to enhance flexibility in the sale of ancillary services, but with reservations. WSPP’s reservations essentially concern whether existing OATT ancillary services rates provide appropriate price signals. WSPP contends that because reserve sales are from the same units as energy sales, mitigation price caps that 100 TAPS Comments at 15–18 and Southern California Edison Comments at 6. 101 EEI Comments at 18–19. E:\FR\FM\30JYR3.SGM 30JYR3 46190 Federal Register / Vol. 78, No. 146 / Tuesday, July 30, 2013 / Rules and Regulations fail to take opportunity costs into account during peak periods are unduly low.102 Separately, WSPP asks the Commission to clarify that for the single OATT rate cap there is no filing with the Commission as a prerequisite to the sale.103 AWEA and Solar Energy Association either support the proposal or do not state opposition to it.104 Iberdrola supports WSPP’s and AWEA’s comments by reference.105 Electricity Consumers state that they do not object to the proposed alternatives provided that they are in fact promulgated as alternatives to the proposed revisions to the market power analysis.106 79. Although ESA, Beacon, and California Storage Alliance all support this proposal, they each argue that for this mitigation measure to be successful in fostering robust competitive markets, the Commission must ensure that costbased schedules for ancillary services, in particular Regulation and Frequency Response, are compared on an ‘‘applesto-apples’’ basis taking into account resource performance.107 80. Some commenters oppose this price cap proposal unless the cap can be raised in some way. For example, Shell Energy argues that a cap based on the buyer’s OATT rate would not produce prices high enough to entice competitive supply. Instead, Shell Energy suggests establishment of a price cap set at 200 percent of the buyer’s OATT rate for the ancillary service in question.108 Similarly, EPSA asserts that cost-based price caps systematically fail to represent the true value of capacity products and will fail to allow a full range of economic tradeoffs in the bilateral markets. EPSA states support for the use of price caps as a last resort, and only if they reflect the seller’s lost opportunity costs as represented by energy transactions during a recent historical period.109 Powerex makes similar arguments, favoring the use of energy price indices to represent lost opportunity costs. Failing that, Powerex argues that a component for transmission costs for remote suppliers should be added to any OATT-based price cap.110 81. ENBALA argues that a cost-based cap limited to the buying utility’s OATT 102 WSPP Comments at 15. at 14. 104 AWEA Comments at 3 and Solar Energy Association Comments at 6. 105 Iberdrola Comments at 3. 106 Electricity Consumers Comments at 4. 107 ESA Comments at 8–10; Beacon Comments at 7–9; and California Storage Alliance Comments at 5–6. 108 Shell Energy Comments at 8–9. 109 EPSA Comments at 9–10. 110 Powerex Comments at 25–29. emcdonald on DSK67QTVN1PROD with RULES3 103 Id. VerDate Mar<15>2010 17:15 Jul 29, 2013 Jkt 229001 rate might be too restrictive and lead the Commission to scrutinize more agreements than necessary, but ENBALA states that ‘‘Reactive Supply and Voltage Control service should be excluded from the regional price cap, being priced by the buying utility’s OATT rate to reflect the geographic limitations of the ancillary service.’’ 111 Commission Determination 82. As one option available to sellers, the Commission will permit marketbased sales of Regulation and Frequency Response service and Reactive Supply and Voltage Control service to public utility transmission providers at rates not to exceed the buying public utility transmission provider’s OATT rate for the same service.112 We find that a price cap based on the buying public utility transmission provider’s OATT rate for the same ancillary service would produce a just and reasonable rate, and do so in a manner that is administratively simple. As discussed in the NOPR,113 because the buying public utility transmission provider’s OATT ancillary service rates have already been found to be just and reasonable, it is reasonable to find that any third-party sales of the same ancillary service to that buyer at or below that buyer’s own approved rates for that service would also be just and reasonable. Accordingly, we will not require sellers to make a separate showing as to the justness and reasonableness of such rates and will allow sellers to make third-party sales of such services at rates as discussed here as of the effective date of this Final Rule. 83. Allowing the sale of ancillary services below the purchasing public utility transmission provider’s OATT rate is a reasonable extension of the mitigation measure relied upon by the Avista policy itself. As discussed earlier,114 the Avista policy sought to protect buyers of third-party ancillary services from potential exercise of market power by ensuring that they would continue to have access to costbased ancillary services from transmission providers, in effect limiting the price at which customers are willing to buy ancillary services from third-parties. The result of the Avista mitigation measure is an implicit soft cap on the price at which thirdComments at 2–4. do not apply this mitigation option to the other OATT ancillary services because this Final Rule allows sales of those services at market-based rates for any seller that has market-based rate authority for energy and capacity. 113 NOPR, FERC Stats. & Regs. ¶ 32,690 at P 34. 114 See supra P 7. PO 00000 111 ENBALA party ancillary services could be offered to non-transmission provider customers. The price cap proposal adopted here extends this concept to transmission providers by creating an explicit price cap at the same level. 84. While a few commenters opine that a cap based on the buyer’s OATT rate would not produce prices high enough to entice competitive supply, the Commission finds that, given the reforms adopted elsewhere in this Final Rule, it is appropriate to take the more conservative step of adopting a price cap based on the buyer’s OATT rate for sales of Regulation and Frequency Response service and Reactive Supply and Voltage Control service to public utility transmission providers. This measure can be implemented quickly and easily with few administrative burdens on either the Commission or the industry. Alternative proposals by commenters would require more complicated design, analysis, and oversight to ensure that they achieve just and reasonable rates. 85. With respect to the arguments of ESA, Beacon, and California Storage Alliance that for this mitigation measure to be successful, the Commission must ensure that cost-based schedules for ancillary services are compared on an ‘‘apples-to-apples’’ basis taking into account resource performance, the Commission addresses this issue below in sub-section B of this Final Rule. Regional OATT Rate Cap Option Comments 86. Some commenters, such as ESA, Beacon, and the California Storage Alliance, support the regional OATT rate cap option on the basis that it is a reasonable approximation of the cost of entry.115 ENBALA also expresses support for a regional cost-based rate cap, arguing that it provides an adequate alternative to the current formal market power requirement.116 EEI and Electricity Consumers also express support for a regional OATT rate cap but offer no specific recommendations.117 87. Southern California Edison states that it supports a cap based on the highest OATT rate within the geographic market as long as it is capped at the lesser of (a) the highest OATT rate in the market or (b) three times the median OATT rate in the relevant geographic market. Southern 112 We Frm 00014 Fmt 4701 Sfmt 4700 115 ESA Comments at 10; California Storage Alliance Comments at 7; and Beacon Comments at 9. 116 ENBALA Comments at 2. 117 EEI Comments at 18–19; and Electricity Consumers Comments at 4. E:\FR\FM\30JYR3.SGM 30JYR3 emcdonald on DSK67QTVN1PROD with RULES3 Federal Register / Vol. 78, No. 146 / Tuesday, July 30, 2013 / Rules and Regulations California Edison explains that it proposes this modification to protect against having a small balancing authority area with an extremely high outlier rate setting the cap.118 88. Other commenters criticize the highest OATT rate cap proposal. Some parties, such as WSPP, EPSA, and Powerex, argue that setting caps based on cost-based rates would not allow sellers to recover foregone opportunity costs associated with energy sales and thus would fail to create any incentives for sellers to enter ancillary service markets. They argue that this is particularly true for short-term ancillary service sales, given that opportunity costs vary materially for hourly, daily, monthly, and seasonal periods, but these variations are not reflected in OATT rates and therefore would not be reflected in the cap. 89. For example, Powerex contends that any alternative price cap must be high enough to create economic incentives for potential sellers to forego other opportunities, namely, energy sales.119 Powerex argues that setting price caps based on transmission providers’ cost-based rates in many instances will not allow sellers to recover the foregone opportunity costs associated with energy sales and that this is particularly true for short-term ancillary service sales.120 Powerex states that short-term energy prices in the CAISO and other Western markets are frequently several-fold higher than Northwest transmission providers’ OATT rates for ancillary services.121 90. Similarly, EPSA argues that a price cap should include a seller’s lost opportunity costs, represented by energy transactions during a recent historical period. EPSA states that it is critically important to include lost opportunity costs, in order to allow a generator to rationally choose between producing energy and not producing energy.122 91. WSPP asserts that the Commission’s observation that the OATT rate could be indicative of the cost of new entry appears speculative. WSPP contends that a cost-based rate may reflect a fully or substantially depreciated unit, rather than the cost of new construction.123 WSPP also argues that because reserve sales are made from the same resources as energy sales, mitigation price caps that fail to take opportunity costs into account during peak periods are unduly low.124 92. Other commenters raise concerns about setting the geographic boundaries for a regional OATT rate cap. Shell Energy asserts that identifying the region in which an ancillary service can be physically traded can be difficult and recommends that the Commission, rather than sellers, identify the relevant trading regions and post that information on the Commission’s Web site.125 TAPS argues that a regional price cap would invite gerrymandering and provide no assurance that the resulting cap is a more reasonable approximation of the cost of new entry.126 TAPS argues that significant physical constraints limit the provision of ancillary services over a geographic area.127 TAPS contends that the regional OATT rate cap proposal is not defensible as either a cost-based or market-based rate and is at odds with the physical limitations on the provision of ancillary services in nonRTO regions.128 TAPS contends that another regional transmission provider’s higher rate (i.e., the highest regional rate) does not bear any relationship to either a third-party supplier’s or the purchasing transmission provider’s cost of supply.129 Commission Determination 93. The Commission will not adopt the NOPR proposal that would allow sellers to propose a price cap equal to the highest OATT rate within a specified region. Based on the comments received, the Commission concludes that use of a regional OATT rate cap would be inadequate to ensure that third-party sellers’ rates remain just and reasonable. In the NOPR, the Commission suggested that this mitigation proposal might be justified on a cost basis in that the highest regional rate may be a reasonable approximation of the cost of new entry into the region in question.130 However, the record developed in this proceeding does not support such a conclusion at this time. 94. We also share commenters’ concerns associated with defining appropriate regions for purposes of setting regional price caps. The Commission is concerned that sellers would have an incentive to ‘‘gerrymander’’ or ‘‘cherry-pick’’ 124 Id. 118 Southern 119 Powerex California Edison Comments at 6–7. Comments at 26. 120 Id. 121 Id. at 27. Comments at 9–10. 123 WSPP Comments at 15. 122 EPSA VerDate Mar<15>2010 17:15 Jul 29, 2013 Jkt 229001 PO 00000 at 15. 125 Shell Energy Comments at 9. 126 TAPS Comments at 22. 127 Id. at 20. 128 Id. at 2. 129 Id. at 19. 130 NOPR, FERC Stats. & Regs. ¶ 32,690 at P 36. Frm 00015 Fmt 4701 Sfmt 4700 46191 regional definitions to ensure inclusion of a high-cost ancillary service provider. In light of the other actions taken in this Final Rule, the Commission believes it would not be productive to undertake the analyses necessary to establish seller-specific regions for various ancillary services. Competitive Solicitations Commission Proposal 95. The NOPR proposed to allow applicants to engage in sales to a public utility that is purchasing ancillary services to satisfy its OATT requirements to offer ancillary services to its own customers where the sale is made pursuant to a competitive solicitation that meets the following guidelines: (1) Transparency—the competitive solicitation process should be open and fair; (2) definition—the product or products sought through the competitive solicitation should be precisely defined; (3) evaluation— evaluation criteria should be standardized and applied equally to all bids and bidders; (4) oversight—an independent third-party should design the solicitation, administer bidding, and evaluate bids prior to the company’s selection;131 and (5) competitiveness— adequate seller interest to ensure competitiveness. Comments 96. Commenters generally support the proposal to permit competitive solicitations as an alternative to performing a market power study.132 EEI, for example, expresses support for competitive procurement as an option for long-term resource planning.133 EPSA states that the Commission’s proposed guidelines for competitive solicitations conform to general principles that EPSA has advocated for such processes.134 97. Some commenters object to certain aspects of the Commission’s proposal. Most criticism is directed at the proposed requirement for independent third-party oversight of competitive solicitations. WSPP, for example, expresses support for competitive solicitations as a means of mitigating potential market power concerns but opposes the proposed oversight by an independent third party. WSPP argues that such oversight is unnecessary, and that the required filing 131 See, e.g., Allegheny Energy Supply Co. LLC, 108 FERC ¶ 61,082 (2004). 132 EPSA Comments at 8–9; EEI Comments at 19– 20; ESA Comments at 10–11; Beacon Comments at 9–11; California Storage Alliance Comments at 7; and ENBALA Comments at 4. 133 EEI Comments at 19–20. 134 EPSA Comments at 8–9. E:\FR\FM\30JYR3.SGM 30JYR3 46192 Federal Register / Vol. 78, No. 146 / Tuesday, July 30, 2013 / Rules and Regulations emcdonald on DSK67QTVN1PROD with RULES3 is ample to demonstrate whether or not the solicitation yielded sufficient competition.135 Shell Energy agrees that third-party oversight of competitive solicitations is unnecessary, arguing that this requirement would hinder shortterm procurement of ancillary services and make the solicitation process unfeasible except for long-term transactions.136 98. However, Morgan Stanley contends that it is not clear that the Commission’s competitive solicitation proposal would protect against market power. Morgan Stanley contends that a competitive solicitation only demonstrates lack of market power if it is robust enough to attract offers that, in aggregate, are significantly in excess of the quantity sought. Morgan Stanley states that it is not clear how a competitive solicitation could help buyers looking to purchase such services on a short-term basis, although it might for the long-term provision of ancillary services.137 Commission Determination 99. The Commission adopts the NOPR proposal to allow applicants to engage in market-based sales of ancillary services to a public utility that is purchasing ancillary services to satisfy its OATT requirements where the sale is made pursuant to a competitive solicitation that meets the requirements specified in the NOPR as numerated above, except as modified below. The Commission has relied on the use of competitive solicitations to mitigate affiliate abuse concerns when affiliates seek to enter into transactions pursuant to market-based rate authority.138 In that context, the Commission has adopted guidelines for independent, third-party review of competitive solicitations. The requirements proposed for sales of ancillary services to public utility transmission providers are based on these guidelines, which the Commission concludes are reasonable to adopt here with one exception. Upon review of comments, we have decided to partially eliminate the requirement that an independent third-party design and administer the solicitation and evaluate bids prior to the company’s selection. 100. As proposed, the independent third-party review requirement would apply to all competitive solicitations. However, the record does not support imposing a requirement for independent third-party review when none of the 135 WSPP Comments at 17–18. Energy Comments at 10. 137 Morgan Stanley Comments at 8–9. 138 See Boston Edison Co. Re: Edgar Electric Energy Co., 55 FERC ¶ 61,382 (1991); Allegheny, 108 FERC ¶ 61,082. 136 Shell VerDate Mar<15>2010 17:15 Jul 29, 2013 Jkt 229001 parties participating in a competitive solicitation is affiliated with the buying public utility transmission provider. If no affiliate of the buyer participates in the solicitation, there is no concern regarding preferential treatment and, therefore, no need for review by an independent third party. As commenters suggest, requiring an independent third-party reviewer could discourage the use of competitive solicitations as it would add to the cost and time needed to procure ancillary services. Some public utility buyers may have a short-term, unexpected need for ancillary services and therefore need to act quickly to fill this need. In such cases, the buyer itself will have to conduct the solicitation, with very limited time for independent review. The Commission therefore revises the NOPR proposal to require independent third-party review of competitive solicitations only when the buyer solicits offers from one or more of its affiliates. 101. However, the Commission emphasizes that any buyer seeking to procure ancillary services from unaffiliated sellers through a competitive solicitation will need to demonstrate compliance with the four other requirements: transparency, definition, evaluation, and competitiveness. In this regard, we reject Morgan Stanley’s assertion that the competitiveness requirement can only be met where a solicitation attracts offers that, in aggregate, are significantly in excess of the quantity sought. We believe there may be multiple methods of demonstrating adequate competitiveness, and we will review such proposals on a case-by-case basis. This will help ensure that any ancillary services procured in this manner are purchased at a competitive market price. At the same time, these requirements will not hinder buyers’ flexibility to design solicitations to meet their specific needs. This demonstration must be made through a filing under section 205 of the Federal Power Act, submitted by the seller to the Commission prior to commencement of service under the third-party ancillary service sales agreement that results from the competitive solicitation. To be specific, the third-party seller will need to submit both the actual sales agreement and a narrative description of how the buyer’s competitive solicitation meets the requirements of this Final Rule. This narrative description will help demonstrate that exercise of market power was not a factor in the negotiation of the sales agreement, and PO 00000 Frm 00016 Fmt 4701 Sfmt 4700 therefore that the resulting rate is just and reasonable. Resource Speed and Accuracy in Determination of Regulation and Frequency Response Reserve Requirements Commission Proposal 102. The Commission proposed in the NOPR to require that each public utility transmission provider submit provisions for inclusion in its OATT that take into account the speed and accuracy of regulation resources in determining its Regulation and Frequency Response reserve requirements. Among other things, this would allow customers choosing to self-supply this service with faster responding or more accurate resources to self-supply with a lower volume of regulation capacity, or vice versa. The Commission stated that it expects to evaluate each proposed determination of regulation reserve requirements on a case-by-case basis. It also stated that each description of how the public utility will adjust its regulation capacity requirement must provide enough detail that an entity wishing to self-supply may compare the resources it is considering using with the resources that the public utility is using. The Commission sought comment on how speed and accuracy should be taken into account.139 Comments 103. A majority of commenters140 generally support the NOPR proposal to require each public utility transmission provider to submit provisions for inclusion in its OATT that take into account the speed and accuracy of regulation resources in determining its Regulation and Frequency Response reserve requirements. Electricity Consumers, Hydro Association, Morgan Stanley, California PUC, and EPSA highlight the benefits of increased transparency, to which EPSA adds that lack of transparency is an impediment to competitive compensation outside of ISOs/RTOs and contributes to a lack of a discernible market value for speed and accuracy. Other commenters, including Public Interest Organizations, Iberdrola, Morgan Stanley, and FTC Staff cite avoidance of undue discrimination, comparable treatment, and the potential that the NOPR proposal will encourage innovation and new entry, as reasons for 139 NOPR, FERC Stats. & Regs. ¶ 32,690 at PP 47– 54. 140 These commenters include Beacon, California Storage Alliance, ESA, Hydro Association, Solar Energy Association, Public Interest Organizations, California PUC, AWEA, Morgan Stanley, EPSA, TAPS, FTC Staff, Electricity Consumers, and Iberdrola. E:\FR\FM\30JYR3.SGM 30JYR3 Federal Register / Vol. 78, No. 146 / Tuesday, July 30, 2013 / Rules and Regulations supporting the proposal. Solar Energy Association supports taking into account the speed and accuracy of regulation resources when establishing the rates that may be charged for those services, with faster and more accurate resources priced accordingly.141 104. Hydro Association supports the idea of ‘‘pay for performance’’ standards that recognize the difference between accurate fast-responding resources versus resources that ramp more slowly and respond less nimbly, and agrees with the Commission that a case-by-case evaluation of each proposed determination is more appropriate than imposing a mandatory methodology. Similarly, California PUC states that transparency should act as a deterrent against discrimination, but cautions that the Commission should avoid an overly prescriptive methodology that may dictate the amount of regulation resources that are needed. 105. Several other commenters, including Beacon, ESA, California Storage Alliance, and Morgan Stanley, encourage the Commission to require transmission providers to provide an explanation of how they set their regulation reserve requirements. ESA, Beacon, and California Storage Alliance propose five elements of an explanation that each transmission provider should be required to provide about how it sets its regulation reserve requirement,142 as well as a list of specific information that each transmission provider should make available.143 Morgan Stanley also urges the Commission to require public utility transmission providers to provide demonstrations of equivalent treatment for their own or their affiliate’s requirements to ensure that there is no undue discrimination, and to establish a process for market participants to challenge and resolve the speed and accuracy assumptions and requirements that public utility transmission providers publish.144 Beacon and ESA also state that ideally the Commission would require each utility to develop a conversion formula or chart that specifies how much capacity a 141 Solar Industry Association Comments at 3. five elements are: (1) A description of the calculation; (2) the metric which is used to set the requirement; (3) the average performance of the existing Regulation assets; (4) the speed and accuracy of the units currently in place (including ramp-rate and accuracy); and (5) sufficient data for a third party to reproduce the results, including posting ACE data on its OASIS reporting. ESA Comments at 12–13; Beacon Comments at 12; and California Storage Alliance Comments at 6. 143 Each entity proposes a bulleted list of nine items including generation capacity available to provide regulation, rates, costs, accuracy and CPS scores, and representative ACE data. ESA Comments at 13; and Beacon Comments at 12–13. 144 Morgan Stanley Comments at 10. emcdonald on DSK67QTVN1PROD with RULES3 142 The VerDate Mar<15>2010 17:15 Jul 29, 2013 Jkt 229001 transmission customer must self-supply given a certain ramp-rate and accuracy. 106. ESA, Beacon, Public Interest Organizations, California Storage Alliance, and AWEA advocate extending the requirement of accounting for speed and accuracy in regulation service to public utilities meeting their own needs, including via third-party suppliers, not simply to transmission customers choosing to self-supply.145 AWEA argues that holding more reserves than needed may result in rates that are not just and reasonable.146 ESA, Beacon, Public Interest Organizations, and California Storage Alliance state that third party sales to a public utility that is purchasing ancillary services to satisfy its own OATT requirements to offer ancillary services to its own customers represents the most significant potential market for sales of ancillary services in non-RTO/ISO regions. Public Interest Organizations agree, arguing that neither the current rules nor the NOPR encourage transmission providers to improve the speed and accuracy of their owned or contracted frequency regulation resources, and that allowing generators to be displaced from providing frequency regulation will enable them to operate at a more stable output, which also can lower energy market prices. Public Interest Organizations contend that the existing OATT Schedule 3 rate treatment is no longer adequate to incorporate emerging technologies, and encourage the Commission to require that OATT Schedule 3 rates incorporate Order No. 755’s framework of an objective accuracy and performance determination, and that the amount of frequency regulation transmission customers are required to procure or self-supply takes into account the speed and accuracy capability of the ancillary service provider’s technology.147 107. Parties that support extending the proposal to public utility transmission providers meeting their own needs also recommend that the Commission consider performancebased rate treatment for public utility investments and contracts with thirdparty ancillary service providers that allow the public utility to reduce the total capacity and cost of providing regulation service while maintaining the same level of reliability.148 They argue that the potential benefits to ratepayers could justify allowing a performance145 Beacon and Public Interest Organizations support ESA’s comments regarding third party sales of regulation. 146 AWEA Comments at 4. 147 Public Interest Organizations Comments at 8. 148 See comments of ESA, Beacon, Public Interest Organizations, and California Storage Alliance. PO 00000 Frm 00017 Fmt 4701 Sfmt 4700 46193 based incentive rate adder that public utility transmission providers could recover through rates, and that if the public utility can demonstrate that it will be able to reduce the total capacity and cost of providing regulation service and maintain the same degree of reliability, such treatment should result in public utilities improving the performance of their regulation fleet and in turn reducing expenses for frequency regulation, ultimately resulting in lower costs. 108. TAPS asks the Commission to state explicitly that the NOPR’s proposal to account for the speed and accuracy of customer self-supplied regulating resources includes demand resources and to state that such a finding would be consistent with OATT Schedule 3 and Order No. 755.149 109. EEI opposes the NOPR proposal. It contends that it is premature to require each transmission provider to include provisions in its OATT explaining how it will determine Regulation and Frequency Response requirements, and requests that the Commission defer this proposal pending experience with secondary frequency control (i.e., regulation) in the ISOs and RTOs following the issuance of Order No. 755.150 EEI requests that the Commission recognize the material differences between primary and secondary frequency control resources in the final rule. It argues that it is also premature to adopt requirements regarding primary frequency control, and recommends that the Commission encourage each balancing authority to continue investigating the role of various types of resources, and allow the industry to maintain its efforts to understand the relationship and interdependencies between primary and secondary frequency response. 110. EEI contends that the assumption that faster responding technologies are necessarily more efficient than traditional methods of frequency regulation has not been substantiated. EEI explains that industry is still exploring frequency response, including current and historical primary and secondary control response performance, and that for system reliability it is important to maintain a balanced portfolio of resources including inertial response, governor response, and secondary frequency control (or regulation response). It further explains that, although OATT Schedule 3 groups primary and secondary frequency control into a single service, the nature of these 149 TAPS 150 EEI E:\FR\FM\30JYR3.SGM Comments at 27. Comments at 22–26. 30JYR3 46194 Federal Register / Vol. 78, No. 146 / Tuesday, July 30, 2013 / Rules and Regulations emcdonald on DSK67QTVN1PROD with RULES3 services are distinct. With regard to secondary frequency control (regulation), EEI claims that the benefits from resources that ramp more quickly for purposes of secondary frequency control may be offset by a lack of capability to sustain that response, or to provide automatic primary frequency control. Commission Determination 111. The Commission will adopt the NOPR proposal with modification. Rather than requiring OATT Schedule 3 to include a description of how resource speed and accuracy will be taken into account in determining Regulation and Frequency Response reserve requirements, we will require each public utility transmission provider to add to its OATT Schedule 3 a statement that it will take into account the speed and accuracy of regulation resources in its determination of reserve requirements for Regulation and Frequency Response service, including as it reviews whether a self-supplying customer has made ‘‘alternative comparable arrangements’’ as required by the Schedule. This statement will also acknowledge that, upon request by the self-supplying customer, the public utility transmission provider will share with the customer its reasoning and any related data used to make the determination of whether the customer has made ‘‘alternative comparable arrangements.’’ 151 To aid the transmission customer’s ability to make an ‘‘apples-to-apples’’ comparison of regulation resources, the Commission will also amend Part 35 of its Regulations by adding a new section (k) to § 37.6,152 to require each public utility transmission provider to post certain Area Control Error (ACE) data described further below. We find that these reforms are necessary to address the potential for undue discrimination in the provision of Regulation and Frequency Response, including in instances when a customer self-supplies this service using its own resources or purchases from a third-party. Acknowledging the speed and accuracy of the resources used to provide this service will help to ensure that an appropriate quantity of resources is utilized for self-supply, whether those resources are faster and more accurate or slower and less accurate than those 151 See Appendix B for the revised Schedule 3 of the pro forma OATT provisions consistent with this Final Rule. 152 This regulation will replace the like-numbered proposed regulation related to historical ancillary service requirements data posting from the NOPR that we decline to adopt in section II.A.1.b. of this Final Rule. VerDate Mar<15>2010 17:15 Jul 29, 2013 Jkt 229001 used by the public utility transmission provider. The weight of comments support reform in this area, including arguments that such a reform will help foster innovation and the entry of newer resources into the market. 112. Under the current pro forma OATT, transmission customers considering using their own or thirdparty resources to self-supply regulation service are required to demonstrate to the public utility transmission provider that they have made ‘‘alternative comparable arrangements.’’ However, the pro forma OATT provides no further information as to how the determination of ‘‘alternative comparable arrangements’’ would be made. Moreover, the OATT contains no express obligation on the part of the transmission provider to consider the relative speed and accuracy of resources a customer might desire to use in selfsupplying Regulation and Frequency Response service. A public utility transmission provider could require a customer seeking to self-supply regulation services to provide a volume of regulation reserves based on the characteristics of the resources used by the public utility transmission provider to provide regulation service, which may not be reflective of the characteristics of the customer’s resources. This could under- or overstate regulation reserve requirements depending on the relative characteristics of the resources at issue. It also could impair the customer’s ability to self-supply regulation requirements at the lowest possible cost.153 The Commission finds that this lack of clarity as to the role of resource speed and accuracy in the determination of ‘‘alternative comparable arrangements’’ for regulation reserve requirements for selfsupplying transmission customers must be addressed in order to limit opportunities for potential discrimination in the provision of regulation service by public utility transmission providers. 113. While the Commission initially proposed that each public utility transmission provider should amend its OATT to include a description of how regulation reserve requirement determinations would take into account speed and accuracy of resources, we 153 For example, a self-supplying customer could save money either by relying on a smaller amount of high quality regulation resources at a slightly higher per-unit price or by relying on a larger amount of lower quality regulation resources at a much lower per-unit price. Provided that reliability is maintained, the transmission customer should have the ability to self-supply consistent with its preferences. PO 00000 Frm 00018 Fmt 4701 Sfmt 4700 believe the better course of action at this time is to place the obligation on the public utility transmission provider to take into account speed and accuracy without requiring it to develop detailed tariff language describing the specific process to be used. This will provide the public utility transmission provider with flexibility while also providing the customer with information. While a number of commenters suggested elements for what the public utility transmission provider should be required to provide, the clearest proposal in the comments related to this issue request that public utility transmission providers be required to provide current monthly and 12-month rolling average Control Performance Standard 1 (CPS1), Control Performance Standard 2 (CPS2) and Balancing Authority ACE Limit (BAAL) scores for Frequency Regulation.154 However, by itself availability of such information would do nothing to explain how the public utility transmission provider determines regulation reserve amounts. Furthermore, while ACE information might help to characterize the speed and accuracy of the public utility transmission provider’s own regulation resources, the Commission believes that using the relatively long duration of monthly and 12-month rolling ACE averages implicit in these scores may not provide information useful for measuring performance over a fraction of an hour, which is the relevant time frame for Regulation and Frequency Response service. 114. Accordingly, the Commission declines to impose a ‘‘one size fits all’’ approach to calculating regulation reserve requirements, consistent with the comments of Hydro Association and California PUC, and declines to require the inclusion of this process in Schedule 3. Rather, we require that Schedule 3 be amended to include a statement that the public utility transmission provider will take into account the speed and accuracy of regulation resources in determining reserve requirements for Regulation and Frequency Response service, including when reviewing whether a selfsupplying customer has made ‘‘alternative comparable arrangements.’’ Self-supplying customers and their public utility transmission providers will then have a basis to study and negotiate appropriate arrangements case-by-case, very similar to how such 154 CPS1 and CPS2 are described in NERC Reliability Standard BAL–001–0.1a—Real Power Balancing Control Performance. The BAAL criterion is expected to replace CPS2 in that Reliability Standard when it becomes effective, pending final approval by NERC and the Commission. E:\FR\FM\30JYR3.SGM 30JYR3 emcdonald on DSK67QTVN1PROD with RULES3 Federal Register / Vol. 78, No. 146 / Tuesday, July 30, 2013 / Rules and Regulations interactions take place under other processes such as the interconnection process. 115. That said, we agree with the comments of ESA, Beacon, and California Storage Alliance that transmission customers considering whether or not there would be any economic advantage to self-supply of Regulation and Frequency Response service requirements would need to be able to make an ‘‘apples-to-apples’’ comparison of their resources to those of their public utility transmission provider.155 Doing so would require the transmission customer to know both the potential avoided cost of purchasing from its public utility transmission provider, and some measure of the speed and accuracy of the public utility transmission provider’s Regulation resources. The first requirement is met through the rate filed in the public utility transmission provider’s OATT Schedule 3. We believe the second requirement can only be met through a new OASIS posting requirement. 116. As noted earlier, the public utility transmission provider’s CPS1, CPS2, and BAAL scores might address this need in concept, except that they currently reflect long-term averages that do not match the relevant time frame for Regulation and Frequency Response service. We believe the one-minute and ten-minute average ACE data collected by public utility transmission providers to produce the CPS1, CPS2, and BAAL scores would be more useful for this purpose because it does match the relevant time frame. Accordingly, in order to ensure a level of transparency adequate to support self-supply decision-making by transmission customers, we will require public utility transmission providers to post historical one-minute and ten-minute ACE data on OASIS. For this purpose, we find that historical data for the most recent calendar year, updated once per year, should meet the need. This information is already collected and provided to NERC, through balancing area operators and reliability coordinators, so there should be minimal incremental burden associated with posting it on OASIS. 117. The Commission’s standard filing requirements, including opportunity for intervention and comment, address Morgan Stanley’s request to establish a process for market participants to challenge and resolve speed and accuracy assumptions. For example, as is the case in interconnection agreement proceedings, 155 ESA Comments at 8–10; Beacon Comments at 7–9; and California Storage Alliance Comments at 5–6. VerDate Mar<15>2010 17:15 Jul 29, 2013 Jkt 229001 the transmission service agreement that reflects an individually negotiated selfsupply arrangement for Regulation and Frequency Response service can be filed by the public utility transmission provider unexecuted. This will leave the transmission customer free to protest relevant aspects of the public utility transmission provider’s determination of whether the customer has made ‘‘alternative comparable arrangements,’’ including as those arrangements relate to the speed and accuracy of the customer’s proposed Regulation resources. 118. With respect to Morgan Stanley’s request that public utilities demonstrate equivalent treatment for their own or their affiliate’s regulation requirements, we find that the increased transparency required by this Final Rule will accomplish this goal. The requirements adopted above apply to the public utility transmission provider’s own regulation resources, in the sense that it must apply the same procedures for determining regulation reserve requirements to itself as it does to selfsupplying customers. 119. With respect to the request of TAPS that the Commission state explicitly that the NOPR’s proposal to account for the speed and accuracy of customer self-supplied regulating resources includes demand resources, we note that OATT Schedule 3, as amended by Order No. 890 makes clear that Regulation and Frequency Response service may be provided from non-generation resources capable of providing the service. Accordingly, a transmission provider’s determination of regulation reserve requirements should take into account the speed and accuracy characteristics of the resources in question, whether they are generation-based or otherwise. 120. Turning to the various requests that the Commission step beyond the NOPR proposals, the Commission declines to require two-part pricing for regulation capacity and performance set forth in Order No. 755. We conclude that the requirements adopted above will allow customers and the Commission to ensure that the speed and accuracy of resources used for regulation reserves are properly taken into account in reserve level determinations within the context of the bilateral markets within which nonRTO/ISO public utility transmission providers operate. The Commission also declines commenter requests to provide incentive rate treatment for purchases of Regulation and Frequency Response service by public utility transmission providers to meet their OATT requirements. Commenters are not clear PO 00000 Frm 00019 Fmt 4701 Sfmt 4700 46195 as to what mechanism they believe the Commission should use to require such treatment, and the Commission sees no reason to implement an incentives program in the context of ancillary services rate design. 121. With respect to EEI’s comments regarding differences between primary frequency response and secondary frequency regulation, the Commission acknowledges these distinctions. Improving the transparency regarding the resources used to provide Regulation and Frequency Response service under OATT Schedule 3 does not alter the ability of any balancing authority to maintain adequate reserves to meet reliability requirements. The Commission thus sees no need to wait for the industry to better understand the relationship and interdependencies between primary and secondary frequency response prior to adopting the requirements of this final rule. The Commission will evaluate a public utility transmission provider’s compliance proposal as part of the caseby-case review discussed above, which will provide the public utility transmission provider the opportunity to demonstrate how it establishes its regulation reserve requirements. Accounting and Reporting for Energy Storage Operations 122. In the NOPR, the Commission proposed to revise certain accounting and reporting requirements under its USofA and its forms, statements, and reports contained in Form Nos. 1, 1–F, and 3–Q. The Commission stated that the revisions were needed so that entities subject to the Commission’s accounting and reporting requirements could better account for and report transactions associated with energy storage devices used in public utility operations. Moreover, the Commission noted that this information is important in developing and monitoring rates, making policy decisions, compliance and enforcement initiatives, and informing the Commission and the public about the activities of entities subject to the accounting and reporting requirements. 123. The Commission proposed that new electric plant and associated O&M expense accounts be created to provide for the recording of investment and O&M costs of energy storage assets. The Commission also proposed to create a new purchased power account to provide for recording the cost of power purchased for use in storage operations. In addition, the Commission proposed that new Form Nos. 1 and 1–F schedules be created and existing schedules in the forms and Form No. 3– E:\FR\FM\30JYR3.SGM 30JYR3 46196 Federal Register / Vol. 78, No. 146 / Tuesday, July 30, 2013 / Rules and Regulations Q be amended to report operational and statistical data on storage assets. Finally, the Commission inquired about whether entities seeking to recover costs of energy storage assets and operations simultaneously under cost-based and market-based rates should be required to forego previously granted accounting and reporting waivers associated with market-based rates, and if so, should the requirement to forego the waivers be subject to some percentage threshold based on a ratio of cost-based cost recovery to total cost to be recovered. 124. While most commenters support the Commission’s proposal to revise the accounting and reporting requirements, there were several recommendations to make adjustments to the proposals and also requests for clarification of certain proposals. Only Solar Energy Association opposed the proposal, stating, without elaboration, that it believes it is premature to establish reporting requirements for energy storage.156 In the NOPR, the Commission responded to similar arguments regarding maturity of the energy storage industry as it relates to the use of energy storage assets to provide public utility services, and found those arguments unconvincing.157 The Commission explained that there is a need for certainty in the accounting and reporting treatment for energy storage assets and operations, especially in instances where utilities seek to recover costs of energy storage operations in cost-based rates. Solar Energy Association has not provided new information that we could consider on this issue, therefore we find Solar Energy Association’s argument unconvincing. 1. Electric Plant Accounts emcdonald on DSK67QTVN1PROD with RULES3 Commission Proposal 125. In the NOPR, the Commission stated that the existing primary plant accounts do not explicitly provide for recording the cost of energy storage assets. The Commission concluded that this could lead to inconsistent accounting and reporting for these assets by utilities subject to the accounting and reporting requirements, making it difficult for the Commission and others to determine costs related to energy storage assets for cost-of-service rate purposes. The Commission also noted that the lack of transparency affects interested parties’, including the Commission’s, ability to monitor these utilities’ operations to prevent and discourage cross-subsidization between 156 Solar Energy Association Comments at 7. FERC Stats. & Regs. ¶ 32,690 at P 71. 157 NOPR, VerDate Mar<15>2010 17:15 Jul 29, 2013 Jkt 229001 cost-based and market-based activities. To address these issues, the Commission proposed to create electric plant accounts in the existing functional classifications—production, transmission, and distribution—for new energy storage assets.158 126. The Commission proposed that the installed costs of energy storage assets be recorded in the accounts based on the function or purpose the asset serves. On this basis, an asset that performs a single function will have its cost recorded in a single plant account. In instances where an energy storage asset is used to perform more than one function or purpose, the Commission proposed that the cost of the asset be allocated among the relevant energy storage plant accounts based on the functions performed by the asset and the allocation of the asset’s costs through cost-based rates that are approved by a relevant regulatory agency, whether federal or state.159 Comments 127. In general, the commenters applaud the Commission’s efforts to improve transparency and prevent double-recovery of energy storagerelated costs. The proposal to require utilities to record the costs of singlefunction energy storage assets in a single plant account garnered widespread support. However, the proposal to require utilities to allocate the costs of multi-function energy storage assets to the relevant energy storage plant accounts based on the functions performed and approved rate recovery, received comments supporting and opposing the proposal. Commenters that agree with the proposal generally indicate that the accounting would provide necessary transparency of a utility’s operations,160 while commenters that oppose the proposal generally indicate that the accounting would place an undue administrative burden on utilities and is inconsistent with the Commission’s existing accounting rules.161 128. Public Interest Organizations state that they support the development of requirements that can reveal the 158 Account 348, Energy Storage EquipmentProduction; Account 351, Energy Storage Equipment—Transmission; and Account 363, Energy Storage Equipment—Distribution, respectively. 159 NOPR, FERC Stats. & Regs. ¶ 32,690 at P 81. 160 Public Interest Organizations Comments at 9– 10; California PUC Comments at 9; NU Companies Comments at 4; APPA Comments at 5; ESA Comments at 18–19; TAPS Comments at 28–29; and California Storage Association Comments at 11–12. 161 Southern California Edison Comments at 8; SDG&E Comments at 2–3; and EEI Comments at 29– 30. PO 00000 Frm 00020 Fmt 4701 Sfmt 4700 activities and costs of energy storage operations thorough greater transparency and detail. California PUC similarly states that in the event an energy storage developer intends to use a facility to perform multiple functions, the proposed accounting and reporting should provide transparency. NU Companies state that they support flexible rate treatment for energy storage assets and believe the proposed accounting will provide transparency required to guard against inappropriate cross subsidization of various services and double recovery cost. 129. In opposition to the proposal, SDG&E contends that while it generally agrees with the Commission’s allocation ‘‘concept’’ to account for energy storage assets by functional category, i.e., production, transmission, and distribution, it is concerned that generally applicable financial tools may not be able to efficiently track or monitor up to three functional categories for one asset without increased and ongoing manual intervention.162 SDG&E argues that it agrees that the initial allocation concept would capture expenses by each function as the Commission intends; however, if the utility subsequently changes its initial allocation in the future the proposed accounting would create an unnecessary administrative burden that if a mistake is made could result in costs of the asset being stranded. SDG&E contends that to ensure the asset is accounted for properly so that asset costs are not stranded, a utility would be required to continuously monitor the asset to make sure its initial allocation is consistent with the asset’s actual usage. SDG&E acknowledges that the NOPR addresses this concern; 163 however, SDG&E asserts that there is a more straightforward approach that can be used to allocate the costs of a multifunction energy storage asset. SDG&E advocates, instead of using multiple plant accounts, that the cost of an energy storage asset be recorded in a single plant account and its cost allocated to the various functions it performs using current ratemaking methods. 130. Similar to SDG&E, Southern California Edison and EEI also complain of an increased administrative burden resulting from allocating an energy 162 SDG&E Comments at 2–3. cites to the NOPR proposal that a utility transfer reallocated cost of an energy storage asset in accordance with the instructions of Electric Plant Instruction No. 12, Transfers of Property, 18 CFR Part 101 (2012). See SDG&E Comments at 3– 4 (citing to NOPR, FERC Stats. & Regs. ¶ 32,690 at P 82). 163 SDG&E E:\FR\FM\30JYR3.SGM 30JYR3 emcdonald on DSK67QTVN1PROD with RULES3 Federal Register / Vol. 78, No. 146 / Tuesday, July 30, 2013 / Rules and Regulations storage asset’s cost across multiple plant accounts as proposed in the NOPR. Southern California Edison and EEI contend that it would be necessary to create multiple unique property records for an energy storage asset to allocate its costs across multiple functions. Southern California Edison and EEI argue that having multiple records for each asset would require significant manual intervention while providing little practical value.164 Additionally, Southern California Edison and EEI assert, without providing any detail, that the NOPR proposal is inconsistent with the general principle that each asset should have a single record within an accounting system.165 Southern California Edison and EEI contend that there is neither a precedent for creating multiple property records for a single asset, nor a precedent for creating a record for a partial asset. Further, EEI argues that to the extent the different functions the cost of an energy storage asset could be spread across are subject to different depreciation rates, a single asset with a unique, individual economic life would be depreciated over multiple periods. 131. EEI indicates that while it generally opposes the NOPR’s proposed accounting, it believes that in some circumstances the proposal may be a practical alternative for companies desiring to use it.166 Therefore, EEI advocates that utilities be afforded two options to account for energy storage assets that are used to perform multiple functions. EEI proposes that utilities be allowed to either: (1) Record the costs of multi-function storage asset costs as proposed in the NOPR or (2) record the costs of the assets in a single plant account based on the primary function of the asset and to allocate costs to specific functions performed through the ratemaking process. Moreover, EEI recommends that the Form Nos. 1, 1–F, and 3–Q be amended to provide for reporting the option each company uses. EEI contends that allowing both options will afford companies the ability to maintain accounting and reporting records in the most efficient manner while providing transparency via reporting and uniformity in the ratemaking process. 132. Southern California Edison supports EEI’s option (2). Southern California Edison and EEI contend that the option (2) approach is consistent 164 Southern California Edison Comments at 8; and EEI Comments at 30. 165 Southern California Edison Comments at 8 and n 8 citing Definition No. 8 Paragraph (A)(5), Continuing Plant Inventory Record, 18 CFR Part 101 (2012); and EEI Comments at 30. 166 EEI Comments at 29–31. VerDate Mar<15>2010 17:15 Jul 29, 2013 Jkt 229001 with the approach used for certain assets that provide both statejurisdictional and FERC-jurisdictional functions.167 Southern California Edison and EEI explain that the ratemaking process may include a formula or special study in order to appropriately allocate the costs across functions. Commission Determination 133. SDG&E’s, Southern California Edison’s, and EEI’s arguments that requiring utilities to allocate the costs of energy storage assets that perform multiple functions across the relevant energy storage plant accounts places an undue administrative burden on utilities are unpersuasive. These commenters generally argue that this perceived undue administrative burden results from a requirement that utilities maintain records that track the usage of energy storage assets and costs associated with such use. However, utilities would be required to maintain records with this information whether accounting for the costs of an asset in multiple accounts as proposed in the NOPR or accounting for the costs in a single account as proposed by SDG&E, Southern California Edison and EEI. For example, information on the allocation of the cost of an energy storage asset to a particular function will have to be maintained by utilities operating multifunction, multi-cost recovery energy storage assets, regardless of whether the information is required to be reported in the reporting forms as proposed in the NOPR or if the information is not reported in the forms yet is used in ratemaking determinations as proposed by SDG&E, EEI, and Southern California Edison. Because utilities with energy storage operations that recover any portion of costs on a cost-of-service basis will be required to maintain use and cost allocation information on the assets, requiring these utilities to implement the NOPR’s accounting proposal does not result in an additional burden on utilities that could be considered unduly burdensome. 134. Moreover, SDG&E’s argument that costs could possibly be stranded if a utility does not appropriately account for energy storage operations is also unconvincing. This possibility exists throughout the utility industry and is not uniquely attributable to utilities with energy storage operations. Administrative errors, such as errors in accounting, that lead to costs being stranded due to inadequate or insufficient internal controls over policies, practices, and procedures used 167 Southern California Edison Comments at 8; and EEI Comments at 31–32. PO 00000 Frm 00021 Fmt 4701 Sfmt 4700 46197 to track costs associated with assets represent a risk for all utilities whether or not the utilities own energy storage assets. Risks of this nature are inherent to all utilities’ operations. Utilities must maintain adequate, sufficient, and reliable internal controls to reduce the probability of this risk affecting operations. 135. As support for their argument that the NOPR’s proposed accounting causes an undue administrative burden and that their advocated accounting avoids the burden, Southern California Edison and EEI contend that their proposal to record the costs of an energy storage asset in a single plant account could require utilities to implement a formula or special study to appropriately allocate the costs of the asset across multiple functions. However, this contention does not support their argument. A formula or special study would require utilities to maintain the same information on the functions performed by an energy storage asset and costs associated with such performance, as would be required by the NOPR’s proposed accounting. Thus, a formula or special study would not avoid the administrative burden associated with accounting for energy storage assets and operations. Furthermore, Southern California Edison and EEI have not provided information to support a determination that the burden would be decreased by implementing their proposed accounting. Their proposal would result in less transparent reporting of information on energy storage operations as compared to the NOPR’s proposed accounting. 136. While the commenters argue that the accounting proposal might require increased manual intervention to account for and report storage assets, it is not clear that such intervention, if any, results in an undue administrative burden. As the Commission observed in the NOPR, uniform, transparent, and consistent reporting of information on energy storage operations by utilities is essential, especially by those seeking to recover costs of energy storage services in cost-based rates.168 We believe that adopting the NOPR’s proposed accounting and reporting revisions will improve transparency.169 The revisions will enhance the Commission’s and other form users’ ability to make a meaningful assessment of a utility’s cost-of-service rates, and will provide for better monitoring for crosssubsidization. In instances where an energy storage asset performs multiple 168 NOPR, 169 Id. E:\FR\FM\30JYR3.SGM FERC Stats. & Regs. ¶ 32,690 at P 71. P 72. 30JYR3 emcdonald on DSK67QTVN1PROD with RULES3 46198 Federal Register / Vol. 78, No. 146 / Tuesday, July 30, 2013 / Rules and Regulations functions, it is imperative that costs associated with each function be transparent and allocable to the function performed so that cross-subsidization of costs can be prevented. SDG&E, EEI, and Southern California Edison have not provided information that would refute the Commission’s determination in the NOPR that the accounting proposal is not overly burdensome. 137. EEI’s recommendation that utilities be afforded two options to account for and report storage assets that provide multiple services and recover associated costs simultaneously under cost-based and market-based rate methods is not consistent with the intent of the NOPR’s proposed accounting and reporting revisions. The NOPR proposed one method to account for energy storage assets performing multiple functions under multiple cost recovery mechanisms to ensure that utilities account for the assets on a uniform and consistent basis. EEI’s proposal for two methods of accounting could result in similarly-situated utilities with energy storage assets reporting the same type of transaction differently. This would not provide the uniformity sought by the accounting and reporting proposals and could disrupt consistency, which would make it difficult to compare utilities with energy storage operations across the industry. In addition, adopting EEI’s proposal to record the costs of the assets in a single account would reduce the transparency of information reported in the forms. This information is critical to the clarity and transparency needed to support a reasonable analysis of a utility’s cost. Consequently, we will not adopt EEI’s proposal. 138. Southern California Edison’s assertion that the NOPR requirement adopted here is not consistent with Definition No. 8, Continuing Plant Inventory Record, is incorrect.170 While the definition pre-dates the NOPR’s accounting and reporting requirements, the definition is broad enough such that its premise is as relevant for energy storage assets as it is for conventional electric plant assets. The accounting and reporting proposals require utilities to maintain a detailed record of the descriptive operational and cost information associated with energy storage assets consistent with the provisions of Definition No. 8. 139. Further, Southern California Edison’s and EEI’s contentions that there is no precedent for creating multiple property records for a single or partial asset misconstrues the proposed accounting and reporting requirements. 170 18 CFR Part 101 (2012). VerDate Mar<15>2010 17:15 Jul 29, 2013 Jkt 229001 The accounting and reporting proposals we adopt here do not require utilities to maintain multiple records for a single or partial asset as Southern California Edison and EEI contend. Rather, the reforms maintain the existing requirement of Definition No. 8 that utilities maintain descriptive operational and cost information on each asset. Moreover, we do not consider allocating the cost of a single asset to multiple property accounts to be the same as creating multiple property records as though there were multiple assets. A utility can maintain information on a single energy storage asset with costs allocated to multiple plant accounts in a single record that provides descriptive operational and cost information on the asset. Additionally, in accordance with General Instruction No. 12, Records for Each Plant, utilities are required to maintain a record, by electric plant accounts, on the book costs of each plant owned.171 The requirement to record the cost of a multi-function, multi-cost recovery energy storage asset to more than one plant account is consistent with this instruction. 140. EEI argues that if different depreciation rates are applied to a single energy storage asset in accordance with each function the asset performs the various allocated costs of the asset would be depreciated over multiple periods. EEI is correct that there is a possibility of this occurring if costs of a single asset were subjected to multiple differing depreciation rates. However, this has neither been the experience of this Commission nor do we expect that a utility’s primary rate regulator would subject a single asset to multiple depreciation rates. Although the costs of an energy storage asset may be allocated across multiple plant accounts, we agree with EEI that the asset is a single unique asset with a single economic life. Thus, there should be a single depreciation rate applied to the asset that allocates in a systematic and rational manner the service value of the asset over its service life. To the extent possible, a utility should apply a single depreciation rate to an energy storage asset. 141. The reforms adopted here are designed to provide needed transparency, but also to reflect a fair balance between the need for information and the additional burden on the utility. We believe these accounting reforms for energy storage reflect this balance. Accordingly, 171 The instructions indicate that the term ‘‘plant’’ means each generating station and each transmission line or appropriate group of transmission lines. This term is also applicable to energy storage facilities. 18 CFR Part 101 (2012). PO 00000 Frm 00022 Fmt 4701 Sfmt 4700 Account 348, Energy Storage Equipment—Production, Account 351, Energy Storage Equipment— Transmission, and Account 363, Energy Storage Equipment—Distribution, as proposed in the NOPR are adopted in this Final Rule. 2. Power Purchased Account Commission Proposal 142. In the NOPR, the Commission noted that to provide some electrical services, energy storage devices may need to maintain a particular state of charge, or as in the case of compressed air facilities, may need to maintain some minimum pressure, and that some companies may be required to purchase power to maintain a desired state of charge or pressure. Further, the Commission determined that the benefits of enhanced transparency, in this instance, resulting from having the cost of power purchased for energy storage operations reported separately from other power purchases, outweighs the associated burden of requiring the accounting. Therefore, the Commission proposed a new Account 555.1, Power Purchased for Storage Operations, to report the cost of: (1) Power purchased and stored for resale; (2) power purchased that will not be resold but instead consumed in operations during the provisioning of services; (3) power purchased to sustain a state of charge; and (4) power purchased to initially attain a state of charge, with item 4 being capitalized as a component cost of initially constructing the asset. Comments 143. Most commenters support the proposed accounting. For example, ESA and others state that the new account will enhance the transparency of reporting the operations of storage resources.172 Hydro Association indicates that similar accounting should be established for the cost of power purchased for pumped storage operations to account for initial unit testing and commissioning.173 144. Hydro Association states, in particular, for closed-loop pumped storage projects, the first unit testing entails pumping or charging the upper reservoir. Hydro Association explains that at an early stage of development of a pumped storage project, the generating station is months away from being declared ‘‘commercial’’ and testing the station requires energy from the grid to initially attain a fully charged state (i.e., a full upper reservoir). Hydro Association argues that these initial 172 ESA Comments at 21–22. Association Comments at 12–13. 173 Hydro E:\FR\FM\30JYR3.SGM 30JYR3 Federal Register / Vol. 78, No. 146 / Tuesday, July 30, 2013 / Rules and Regulations charging costs should be capitalized. Further, Hydro Association contends that costs incurred to test the generating station should likewise be capitalized into the cost of the project. In contrast to Hydro Association’s assertion that the existing accounting requirements for pumped storage operations are not sufficient, EEI argues that the existing requirements appropriately and transparently provide for pumped storage plants.174 emcdonald on DSK67QTVN1PROD with RULES3 Commission Determination 145. We will adopt the new Account 555.1, Power Purchased for Storage Operations, as proposed in the NOPR. The accounting reforms here requiring initial charging and testing costs to be capitalized seek to apply existing requirements for conventional electric plant, such as pumped storage plant, to new energy storage assets. The requirements do not seek to differentiate the accounting for new energy storage assets from pumped storage plant in this instance. 146. We disagree with Hydro Association’s assertion that the existing accounting requirements for pumped storage operations are not sufficient. Contrary to Hydro Association’s assertion, pumped storage is not prohibited, for accounting purposes, by the existing accounting rules and regulations from capitalizing costs incurred to initially bring a pumped storage facility into operation nor is it prohibited from capitalizing costs incurred to test pump storage facilities prior to commercial operation. Electric Plant Instruction No. 3, Components of Construction Cost, provides that expenses incidental to the construction of plant such as cost to initially attain a fully charged state to bring the plant into operation may be capitalized as a component cost of the plant.175 Further, Electric Plant Instruction No. 9, Equipment, provides that the costs of plant shall include necessary costs of testing or running plant or parts thereof during the test period prior to the plant becoming ready for or being placed in service.176 Consequently, we agree with EEI’s statement that the existing accounting requirements for pumped storage are sufficient. The NOPR proposals for Account 555.1 are adopted in this Final Rule as proposed. 175 18 Commission Proposal 147. In the NOPR, the Commission observed that there are O&M expenses related to the use of energy storage assets to provide utility services, and there are no existing O&M expense accounts in the USofA specifically dedicated to accounting for the cost of energy storage operations. Therefore, the Commission proposed new O&M expense accounts for energy storagerelated O&M expenses that are not specifically provided for in the existing O&M expense accounts in the USofA and revision of certain existing O&M expense accounts. Specifically, the Commission proposed that energy storage expenses be recorded in Account 548.1, Operation of Energy Storage Equipment, and Account 553.1, Maintenance of Energy Storage Equipment, for energy storage plant classified as production; Account 562.1, Operation of Energy Storage Equipment, and Account 570.1, Maintenance of Energy Storage Equipment, for energy storage plant classified as transmission; and Account 582.1, Operation of Energy Storage Equipment, and Account 592.2, Maintenance of Energy Storage Equipment, for energy storage plant classified as distribution, to the extent that the existing O&M expense accounts do not adequately support recording of the cost.177 ‘‘and account 363, Storage Battery Equipment.’’ Comments 148. The commenters support the proposed O&M expense accounts. Most commenters state that the proposed accounts will provide sufficient transparency of energy storage-specific O&M expenses.178 Commission Determination 149. This Final Rule adopts the NOPR proposals for the O&M expense accounts with the exception that the account number for Account 582.1 will be changed to Account 584.1. The name and text of the account will remain as proposed in the NOPR. 150. In addition, the NOPR proposed that the text of Account 592, Maintenance of Station Equipment (Major only), and Account 592.1, Maintenance of Structures and Equipment (Nonmajor only), be revised such that the accounts do not provide for O&M expenses related to energy storage operations and also to remove the reference to Account 363. 178 See, 176 Id. 17:15 Jul 29, 2013 Accordingly, the following text is struck from Accounts 592 and 592.1: FERC Stats. & Regs. ¶ 32,690 at P 96. e.g., ESA Comments at 22; Beacon Power Comments at 21–22; and California Storage Alliance Comments at 17. Comments at 27. CFR Part 101 (2012). VerDate Mar<15>2010 3. Operation and Maintenance Expense Accounts 177 NOPR, 174 EEI Jkt 229001 46199 PO 00000 Frm 00023 Fmt 4701 Sfmt 4700 4. New and Amended Form Nos. 1, 1– F, and 3–Q Schedules Commission Proposal 151. In the NOPR, the Commission acknowledged that the existing schedules in the Form Nos. 1, 1–F, and 3–Q do not provide for reporting information on new types of energy storage assets such as batteries and flywheels.179 Consequently, the Commission proposed to amend several schedules of the Form Nos. 1, 1–F, and 3–Q to include energy storage plant, purchased power, and O&M expense accounts.180 In addition, the Commission proposed to add new schedule pages 414–416, Energy Storage Operations (Large Plants), and pages 419–420, Energy Storage Operations (Small Plants), to the Form Nos. 1 and 1–F to provide for reporting operational and statistical information on new types of energy storage assets.181 The Commission proposed that filers with energy storage assets having a rated capacity of 10,000 kilowatts (KW) or more record the operations of the assets on schedule pages 414–416, and filers with energy storage assets with less than 10,000 KW of capacity record the operations on schedule pages 419–420. In addition, the Commission sought comment on whether 10,000 KW is an appropriate threshold for requiring utilities to report more detailed plant and cost information for energy storage plant.182 The Commission noted that certain existing schedules in the Form No. 1 have a 10,000 KW threshold.183 However, the Commission opined that this threshold may not be appropriate for new energy storage assets that in 179 NOPR, FERC Stats. & Regs. ¶ 32,690 at P 101. FERC Stats. & Regs. ¶ 32,690 at P 106; and Appendix B Proposed Amendments to Form Nos. 1, 1–F and 3–Q. 181 The text of the NOPR indicated that the schedules pages were 414–417 and 419–421 for the respective Large and Small Plant schedules. However, the proposed schedules included in Appendix B of the NOPR used different page numbers. We clarify that the schedule page numbers are 414–416 and 419–420, for the respective Large and Small Plant schedules, as indicated in this Final Rule. 182 NOPR, FERC Stats. & Regs. ¶ 32,690 at P 103. 183 See Form No. 1, schedule pages 408–409, Generating Plant Statistics (Large Plants) and schedule pages 410–411, Generating Plant Statistics (Small Plants). Schedule pages 408–409 require filers to report more detailed information for generating assets with a rated capacity of 10,000 KW or more than schedule pages 410–411, which require less detailed information for generating assets with a rated capacity of less than 10,000 KW. 180 NOPR, E:\FR\FM\30JYR3.SGM 30JYR3 46200 Federal Register / Vol. 78, No. 146 / Tuesday, July 30, 2013 / Rules and Regulations many instances may be rated below 10,000 KW. emcdonald on DSK67QTVN1PROD with RULES3 Comments 152. Most commenters support the NOPR’s forms proposals, and a few commenters recommend revisions to the forms in addition to those proposed.184 Consistent with its recommendation that the Commission implement two options to account for energy storage assets, EEI proposes that the forms provide for disclosing the specific option a utility is using to account for the assets.185 However, because we are not adopting EEI’s recommendation for two accounting options, its disclosure proposal is unnecessary as utilities will have one uniform method for accounting for energy storage assets. 153. Hydro Association contends that there are shortcomings in the way the Form No. 1 treats existing pumped storage plants, as they are now used, and it suggests modifications that it believes will improve reporting of information on the assets. Hydro Association recommends that the heading of Line 6 ‘‘Plant Hours Connect to Load While Generating’’ of schedule pages 408–409, Pumped Storage Generating Plant Statistics (Large Plants), in the Form No. 1 be changed to read ‘‘Plant Hours Connect to Load.’’ 186 Hydro Association reasons that the total hours a facility is synchronized and connected to the grid are important to identify. Hydro Association explains that a facility’s effectiveness is based on its total utilization factor, which Hydro Association describes as the sum of hours generating, pumping, and condensing. Hydro Association asserts that this sum should be reported on Line 6 under its proposed heading. Alternatively, Hydro Association proffers that if further detail is needed, the heading of Line 6 can remain as is and two new line items can be added to the schedule to report pumping and condensing hours. 154. Further, Hydro Association also contends that Line 38, ‘‘Expenses for KWh (line 37/9)’’ incorrectly calculates the cost per kilowatt hour (KWh) of pumped storage operations.187 Hydro Association asserts that the calculation should include energy generated and energy used for pumping operations. Hydro Association proposes that Line 184 See, e.g., APPA Comments at 5; Beacon Comments at 22–23; California Storage Alliance Comments at 19; and ESA Comments at 23. 185 EEI Comments at 5. 186 Hydro Association Comments at 11. 187 Id. VerDate Mar<15>2010 17:15 Jul 29, 2013 Jkt 229001 38 be revised to read as ‘‘Expenses for KWh (line 37/9+10).’’ 155. TAPS recommends revisions to new schedule pages 414–416, Energy Storage Operations (Large Plants).188 TAPS observes that the instruction for column heading (l) refers to ‘‘revenues from energy storage operations’’ while the name of the column is ‘‘Revenues from the Sale of Stored Energy.’’ TAPS asserts that because revenues from energy storage operations can be garnered by means other than from energy sales, the name of the column should be revised to be consistent with the instructions of the column or additional columns should be created, with corresponding instructions, to report other types of revenues. 156. In regard to the 10,000 KW threshold, California Storage Alliance states that it believes 10,000 KW is an appropriate threshold for requiring a difference in the reporting requirements for the assets.189 In contrast, Beacon and ESA recommend a higher threshold of 20,000 KW.190 Beacon and ESA assert that this threshold would align with the Small Generator Interconnection threshold and the capacity value for many existing and planned energy storage assets. Commission Determination 157. We generally agree with the premise of Hydro Association’s contention that Line 6 of schedule pages 408–409 could benefit from additional detail. However, the cost of additional detail must be weighed against any associated benefit that could result. To this end, we strive to achieve a balance such that the cost of implementing new reporting requirements does not excessively exceed the benefits of implementation. A particularly important benefit to the Commission of additional detail is that it provides data necessary for the regulation and review of companies’ operations. Hydro Association has neither explained how information on pumping and condensing hours is needed for the regulation and review of pumped storage operations nor has it explained how the information would be beneficial for other uses. Hydro Association indicates that this information will provide for a measure of a facility’s effectiveness, however, it is not clear that the cost of requiring this information is on par with any perceived benefits or that the requirement would not be overly 188 TAPS Comments at 28–29. Storage Alliance Comments at 19. 190 Beacon Comments at 22; and ESA Comments at 22–23. 189 California PO 00000 Frm 00024 Fmt 4701 Sfmt 4700 burdensome. Consequently, we will not adopt Hydro Association’s proposal to include the sum of generating, condensing and pumping on Line 6, nor will we adopt its alternate proposal to add two new line items to the schedule. 158. With regard to Hydro Association’s contention that Line 38 of schedule pages 408–409 incorrectly calculates the cost per KWh of pumped storage operations, this line is not intended to report this cost, rather it is intended to report the cost per KWh of energy generated and transmitted to the grid. Line 38 of the schedule includes a formula that requires filers to divide total production expenses reported on Line 37 by energy generated and transmitted to the grid reported on Line 9. Nevertheless, we recognize Hydro Association’s underlying concern that, as a conforming change given the other accounting requirements in this Final Rule, the schedule should report this information, including the energy generated and energy used in pumping, as illustrated in the formula example submitted by Hydro Association—Line 37/9+10. 159. We agree that reporting this information on schedule pages 408–409 will help create a more accurate database for benchmarking and O&M cost studies, and this information also will assist interested parties’, including the Commission’s, review of the operations of pumped storage facilities across the industry. We note that the data inputs needed to perform the calculation are currently required to be reported on Lines 9, 10 and 37 of schedule pages 408–409, so this requirement is not wholly new and the burden on utilities to calculate and report the information specifically on schedule pages 408–409 is minimal. Accordingly, the item on Line 38 of schedule pages 408–409 is revised to read ‘‘Expenses per KWh of Generation (line 37/line 9)’’ and a new Line 39 is added which reads ‘‘Expenses per KWh of Generation and Pumping (line 37/ (line 9 + line 10)).’’ 160. TAPS asserts that revenues from energy storage operations can originate from activities other than energy sales, thus it recommends that proposed schedule pages 414–416 be revised to provide for other types of revenues. We agree that there are potentially other activities that energy storage operators can engage in to generate revenue. For example, as TAPS noted, an energy storage operator can conceivably earn revenues from the sale of storage capacity. While we are not aware of any instances where these types of storage capacity transactions have occurred, to ensure that the schedule provides E:\FR\FM\30JYR3.SGM 30JYR3 Federal Register / Vol. 78, No. 146 / Tuesday, July 30, 2013 / Rules and Regulations emcdonald on DSK67QTVN1PROD with RULES3 adequate flexibility to allow for the reporting of all revenues from energy storage operations we will revise the name of the column to read ‘‘Revenues from Energy Storage Operations.’’ We will not create additional columns to report the various types of revenue because the instructions to the schedule already require filers to disclose this information in a footnote. 161. Beacon and ESA recommend that the Commission align the threshold for detailed reporting in the new schedules with the existing 20,000 KW threshold established in Order No. 2006 for the interconnection of small generators.191 To this end, Beacon and ESA propose a 20,000 KW threshold as opposed to the 10,000 KW proposed in the NOPR. However, the 20,000 KW threshold in Order No. 2006 was established notwithstanding the requirement that small generators having 10,000 KW or more but less than 20,000 KW that are subjected to the Commission’s accounting and reporting requirements would be subjected to a higher reporting burden than companies with generators of less than 10,000 KW. In this instance, the Commission determined that while there is a need to further remove barriers to participation in energy markets by establishing terms and conditions under which public utilities must provide interconnection service, there is also a parallel need for detailed information on the activities and operations of companies using these assets in the provisioning of utility services. Thus, the Commission maintained its existing 10,000 KW threshold for these small generators. 162. Beacon and ESA have not provided information that supports a decreased reporting burden for energy storage assets over 10,000 KW as compared to the reporting burden of conventional assets that are currently subject to the 10,000 KW threshold. Nor has Beacon or ESA provided information that would support increasing the existing 10,000 KW threshold for conventional assets to maintain parity between those assets and energy storage assets. Their proposal may result in an unduly discriminatory reporting requirement for energy storage assets compared to conventional assets, therefore we will 191 Standardization of Small Generator Interconnection Agreements and Procedures, Order No. 2006, FERC Stats. & Regs. ¶ 31,180, order on reh ’g, Order No. 2006–A, FERC Stats. & Regs. ¶ 31,196 (2005), order on clarification, Order No. 2006–B, FERC Stats. & Regs. ¶ 31,221 (2006). This order originally set forth the terms and conditions under which public utilities must provide interconnection service to Small Generating Facilities of no more than 20,000 KW. VerDate Mar<15>2010 17:15 Jul 29, 2013 Jkt 229001 not adopt the recommended 20,000 KW reporting threshold. 163. We will adopt the NOPR’s proposed 10,000 KW threshold as this amount is neither unduly conservative nor is it overly burdensome. As we indicated in the NOPR, information that would be reported for energy storage assets and operations differs little from other data public utilities maintain under the USofA.192 If a utility owns and operates these energy storage assets, reporting information on them in the proposed accounts and FERC form schedules should not be burdensome. 164. Finally, we will amend schedule pages 2–4, 204–207, 320–323, 324a– 324b, 326–327, 397, and 401a of the Form Nos. 1, 1–F, and 3–Q as proposed in the NOPR.193 We note that these amendments include revising schedule page 401a, Electric Energy Account, of the Form No. 1 to change the title of line item 10 to ‘‘Purchases (other than for Energy Storage)’’ and add a new line item 11 ‘‘Purchases for Energy Storage’’ to provide for reporting power purchased for energy storage operations. These changes require an additional line item on Form No. 1 schedule page 401a to provide for reporting stored energy because total net sources of energy must equal total disposition of energy as instructed by the requirement on Line 30 of the schedule. Utilities with energy storage operations that have stored energy as of the reporting date of the form must report the amount by megawatt hour in the schedule so that total net sources of energy is equal to total disposition of energy reported. Accordingly, as a conforming change, a new line item titled ‘‘Total Energy Stored’’ will be added to schedule page 401a under the heading ‘‘Disposition of Energy.’’ 5. Other Accounting and Reporting Issues a. Existing Waivers of Accounting and Reporting Requirements Commission Proposal 165. In the NOPR, the Commission proposed that public utilities currently providing jurisdictional services and recovering costs of the services under market-based rates that have been granted waiver of the accounting and reporting requirements and that seek recovery of a portion of service costs under cost-based rates, be required to forego the previously issued waivers and account for and report all cost and operational information to the FERC Stats. & Regs. ¶ 32,690 at P 73. FERC Stats. & Regs. ¶ 32,690 at Appendix B Proposed Amendments to Form Nos. 1, 1–F, and 3–Q. PO 00000 192 NOPR, 193 NOPR, Frm 00025 Fmt 4701 Sfmt 4700 46201 Commission in accordance with its accounting and reporting requirements.194 In addition, the Commission also inquired whether there should be a percentage of cost recovery threshold or other determining factor that triggers the accounting and reporting obligations in this situation, or should any instance of multiple cost recovery, regardless of the percentage of a utility’s total costs, trigger the accounting and reporting obligations. Comments 166. Most commenters agree with the proposal to rescind previously issued waivers and many of these commenters argue that there should not be a percentage threshold that triggers the requirement. California Storage Alliance states that rescinding the waivers will enhance transparency and facilitate development and monitoring of the cost-based portion of rates.195 Further, California Storage Alliance states that there should not be a percentage threshold that triggers accounting and reporting requirements. California Storage Alliance, and others,196 also recommend that in instances where a competitive solicitation process is used to determine recovery of the cost-based portion of rates, a public utility should not be required to forego any reporting and accounting waivers. In further describing their position, these commenters suggest that a particular ‘‘storage asset may be capable of simultaneously providing two distinct functions, one traditionally cost-based use, and another generally marketbased.’’ They then posit the possibility of a public utility issuing a competitive solicitation solely for the ‘‘cost-based use.’’ Their comments then assert that the winning bidder would be obligated to provide the ‘‘cost-based service’’ and would be paid through a ‘‘rate-based mechanism.’’ 197 We also received requests to clarify that the waivers will only be rescinded if energy storage is involved.198 Commission Determination 167. We will adopt the NOPR proposal requiring public utilities to forego previously issued accounting and reporting waivers in instances where the utility seeks to recover costs associated with operation of an energy storage asset simultaneously under market-based and 194 Id. P 75. 195 California Storage Alliance Comments at 10. Storage Alliance Comments at 10– 11; ESA Comments at 18; and Beacon Comments at 18. 197 Id. 198 Indicated Suppliers Comments at 6–11; EPSA Comments at 13; and EEI Comments at 33–34. 196 California E:\FR\FM\30JYR3.SGM 30JYR3 emcdonald on DSK67QTVN1PROD with RULES3 46202 Federal Register / Vol. 78, No. 146 / Tuesday, July 30, 2013 / Rules and Regulations cost-based rate recovery mechanisms. We will not impose a percentage recovery threshold, therefore any costbased recovery of the cost will trigger rescission of previously granted accounting and reporting waivers. 168. Regarding the comments of California Storage Alliance, ESA, and Beacon, the Commission clarifies that sellers under a competitive solicitation that meets the requirements of this Final Rule 199 will not be required to forego any prior accounting and reporting waivers. However, we feel it necessary to explain that the reason for this outcome differs from what these commenters seem to propose. 169. Their comments seem to indicate a belief that there are some products that are inherently cost-based and others that are inherently market-based, and that if a competitive solicitation were held for a cost-based product, the resulting rates would still be cost-based. We are not persuaded by these commenters’ arguments that products should be classified as inherently costbased or market-based. Some potential sellers of these products will qualify to sell them at market-based rates because they either lack market power in the relevant product market, or it has been adequately mitigated. Other sellers who do not qualify to make market-based sales, because they either have market power or cannot prove they lack it, will be limited to charging cost-based rates. 170. Under the competitive solicitation proposal at bar, proof that the competitive solicitation meets the requirements of this Final Rule will demonstrate that a seller qualifies to make market-based sales at the rates resulting from the solicitation, and thus can avoid having to justify those rates on a cost-of-service basis. Because such sellers will still only be making marketbased sales, there is no reason to rescind the prior accounting and reporting waivers that were granted because they would only be making market-based rate sales. Cost-based sales of ancillary services have always been an option for third party sellers, and remain an option for them after issuance of this Final Rule. However, all of the requirements of cost-of-service regulation, such as the very accounting and reporting requirements at issue here, would apply to such sales. We also clarify that the requirement for a company to forego previously issued accounting and reporting waivers, in this instance, is only applicable when energy storage is involved. There may be other occasions when previously issued waivers may be rescinded however those occasions are outside the scope of this rulemaking. b. Definition of Energy Storage Asset or Technology 171. EEI asks that the Commission clarify the definition of energy storage assets or technologies that are subject to these accounting and reporting requirements.200 EEI proposes that the Commission define energy storage assets as ‘‘commercially available technology that is capable of absorbing energy, storing energy, and subsequently releasing the energy to the electric system.’’ 201 Further, EEI states that certain other energy storage assets should be exempted from the Final Rule, and thus the new accounts, if the function of the asset is so clearly related to activities properly reflected in existing accounts such that the asset is not designed to be used as an ‘‘energy storage asset’’ under the definition articulated in this Final Rule. EEI states, for example, that the following assets or technologies should be exempted: Batteries used primarily in connection with the control and switching of electric energy produced and the protection of electric circuits and equipment that are recorded in the following existing FERC accounts: Account 315, Accessory Electric Equipment Account 324, Accessory Electric Equipment (Major Only) Account 345, Accessory Electric Equipment Batteries used in connection with controlling station equipment or for general station purposes that are recorded in the following existing FERC accounts: Account 353, Station Equipment Batteries used in connection with controlling station equipment or for general station purposes that are recorded in the following existing FERC accounts: Account 362, Station Equipment Compressed air systems used for pneumatic or air tools that are recorded in the following existing FERC accounts: Account 316, Miscellaneous Power Plant Equipment Account 325, Miscellaneous Power Plant Equipment (Major Only) Account 346, Miscellaneous Power Plant Equipment Commission Determination 172. We agree with EEI that there are certain assets that are excluded from the scope of this Final Rule, however, we will not adopt EEI’s proposed definition for an energy storage asset or technology. The definition is too broad and could be interpreted to include storage-type technologies that are outside the scope of this Final Rule. As EEI indicated, the assets listed above are 200 EEI 199 See supra PP 87–90. VerDate Mar<15>2010 17:15 Jul 29, 2013 Comments at 26–28. 201 Id. Jkt 229001 PO 00000 Frm 00026 Fmt 4701 Sfmt 4700 the type of assets that should be excluded. This list is not exhaustive; rather it is an example of the type of assets and activities served by those assets that are a baseline indicator of assets that are outside the scope of the accounting and reporting requirements adopted in this Final Rule. For the purposes of this Final Rule, an energy storage asset shall be defined as property that is interconnected to the electrical grid and is designed to receive electrical energy, to store such electrical energy as another energy form,202 and to convert such energy back to electricity and deliver such electricity for sale, or to use such energy to provide reliability or economic benefits to the grid. The term may include hydroelectric pumped storage and compressed air energy storage, regenerative fuel cells, batteries, superconducting magnetic energy storage, flywheels, thermal energy storage systems, and hydrogen storage, or combination thereof, or any other technologies as the Commission may determine.203 c. Incorporating Energy Storage Plant Accounts Into Existing Formula Rates 173. EEI requests that the Commission pre-authorize inclusion of the new energy storage plant and O&M expense accounts in existing formula rates without the need for separate, companyspecific section 205 proceedings.204 EEI contends that many jurisdictional utilities that own and operate energy storage technologies account for the assets in existing accounts that are incorporated in formula rates. EEI states that to the extent the new accounts require a revision to existing filed rates, the Commission should allow such changes to be filed in a compliance filing in this proceeding. Commission Determination 174. We agree with EEI that utilities currently owning and operating these assets are using existing accounts and reporting schedules. Moreover, in many instances these accounts are incorporated in the companies’ formula rate templates and costs reported in the accounts are through operation of the formula rate included in rate 202 Electrical energy may be converted to and stored as several different forms of energy such as chemical, mechanical, and thermal energies. 203 Although hydroelectric pumped storage is an energy storage technology in accordance with our definition, the accounting and reporting requirements of this rulemaking do not apply to the assets, notwithstanding the revisions to schedule pages 408–409. As we indicated previously, our existing accounting and reporting requirements for pumped storage sufficiently accommodate pumped storage assets and operations. 204 EEI Comments at 32–33. E:\FR\FM\30JYR3.SGM 30JYR3 Federal Register / Vol. 78, No. 146 / Tuesday, July 30, 2013 / Rules and Regulations emcdonald on DSK67QTVN1PROD with RULES3 determinations. For some of these companies, transferring amounts from an existing plant account under a particular functional classification to a new energy storage plant account under the same functional classification may involve a relatively straight-forward transfer of cost. In this type of situation, a compliance filing will provide adequate transparency to allow interested parties, including the Commission, to review amounts being transferred from one account to another and also to establish the incorporation of the new energy storage plant and O&M expense accounts in the formula rate tariff. However, a compliance filing may not be suitable for all situations. 175. For example, in instances where a company intends on recording the costs of an energy storage asset to multiple plant accounts in accordance with a plan to support multiple functions using the asset, a compliance filing may not provide for an adequate review of the many variables involved that can impact the determination of the appropriate allocation of the cost and rates charged based on the allocation. Moreover, if a company intends on recovering capital and O&M costs of the asset simultaneously under cost-based and market-based rate recovery mechanisms, a compliance filing would not provide sufficient notice or review of the cost to be recovered under the two rate mechanisms. Consequently, because a compliance filing is not appropriate for all situations, we will limit approval of its use to companies that are transferring amounts from an existing plant account under a particular functional classification to a new energy storage plant account under the same functional classification. Transfers of the costs to other plant accounts after this initial compliance filing shall be subject to the requirements of Electric Plant Instruction No.12, Transfers of Property,205 as proposed in the NOPR,206 and the provisions of utilities’ formula rate tariffs, as applicable. Utilities that do not qualify to use the compliance filing process must first receive approval from a relevant rate regulator to revise their existing formula rate tariffs to incorporate the new energy storage accounts. d. Depreciation Rates for Energy Storage Assets assets be charged to depreciation expense using the depreciation rates developed for each function.207 Comments 177. Commenters generally support this proposal. For example, Beacon and ESA acknowledge support for the proposal.208 EEI recommends that instead of requiring depreciation rates to be based on a utility’s existing rate for a particular function, the Commission allow utilities to set initial depreciation rates for new energy storage battery equipment based on the manufacturer’s estimated useful life, prior to the utilities receiving approval of new depreciation rates through a rate proceeding where new approved rates are ordered for these accounts.209 EEI explains that the current life of storage batteries is expected to be approximately 10 to 15 years and it contends that this expected life can be substantially less than the life used to calculate the depreciation rate for the function the asset may be classified under. Commission Determination 178. For accounting purposes, utilities are required to use percentage rates of depreciation that are based on a method of depreciation that allocates in a systematic and rational manner the service value of depreciable property over the service life of the property.210 Where composite depreciation rates are used, the rate should be based on the weighted average estimated useful lives of depreciable property comprising the composite group. Furthermore, estimated service lives of depreciable property must be supported by engineering, economic, or other depreciation studies.211 To the extent that an energy storage asset, such as a battery, has an estimated useful service life that is supported by engineering, economic, or other studies of the manufacturer or utility, the depreciation rate derived from such study must result in a systematic and rational allocation of the asset’s costs over the estimated service life. Therefore, for accounting purposes, utilities may set initial rates for new energy storage assets based on manufacturer or utility estimated service lives that are supported by engineering, economic or other studies. In addition, as we indicated above, utilities should use a single depreciation Commission Proposal 207 Id. 176. In the NOPR, the Commission proposed that the cost of energy storage 205 18 CFR Part 101 (2012). FERC Stats. & Regs. ¶ 32,690 at P 82. 206 NOPR, VerDate Mar<15>2010 17:15 Jul 29, 2013 Jkt 229001 208 Beacon Comments at 19; and ESA Comments at 19. 209 EEI Comments at 32. 210 General Instruction No. 22, Depreciation Accounting, 18 CFR Part 101 (2012). 211 Id. PO 00000 Frm 00027 Fmt 4701 Sfmt 4700 46203 rate for an energy storage asset regardless the number of functions to which the costs of the asset are allocated.212 e. Jurisdictional Authority 179. The California PUC warns that the Commission’s authority over the accounting and reporting for energy storage assets should not limit or infringe upon States’ jurisdictional authority over the assets as the majority of the assets are likely to be financed pursuant to state jurisdictional procurement authority.213 Commission Determination 180. The accounting and reporting requirements of this rulemaking are not intended to limit or infringe upon States’ jurisdictional authority. Pursuant to section 301(a) of the Federal Power Act (FPA), the Commission has authority to prescribe a system of accounts and rules and regulations that are applicable in principle to all licensees and public utilities subject to the Commission’s accounting and reporting requirements.214 The Commission may determine the accounts in which particular outlays and receipts will be entered, charged or credited. The amendments to the accounting and reporting requirements are in accordance with the authority bestowed upon the Commission under the FPA and as such do not preempt or affect any jurisdiction a State commission or other State authority may have under applicable State and Federal law or limit the authority of a State commission in accordance with State and Federal law. f. Implementation Date 181. EEI requests clarification of the implementation date of the proposed accounting and reporting requirements. EEI states that it believes assets and related amounts recorded in other accounts under the existing accounting requirements should be reclassified to the new energy storage accounts provided the asset meets the definition of an energy storage asset.215 However, EEI argues that it would not be beneficial or cost effective to require utilities to retroactively amend prior year reports to implement the requirements. Therefore, EEI recommends that the accounting and reporting requirements be effective prospectively only. 212 See supra P 128. PUC Comments at 8. 214 16 U.S.C. 825(a). 215 EEI Comments at 28–29. 213 California E:\FR\FM\30JYR3.SGM 30JYR3 emcdonald on DSK67QTVN1PROD with RULES3 46204 Federal Register / Vol. 78, No. 146 / Tuesday, July 30, 2013 / Rules and Regulations Commission Determination 182. While we agree with EEI that it may not be cost effective to require utilities with energy storage assets to retroactively amend prior year reports to implement the accounting and reporting requirements of this Final Rule; we disagree with EEI’s contention that it would not be beneficial to interested parties desiring more transparent reporting of the costs associated with energy storage operations. In these instances, the Commission must weigh the perceived cost of implementing a requirement against the expected benefits of implementation. Although requiring utilities with energy storage assets to retroactively implement the requirements would provide a more transparent historical record of these utilities energy storage operations, this information would not be necessary to provide oversight of these utilities energy storage operations going forward. Moreover, it is not clear that the benefits of retroactive implementation are sufficient to justify the cost. Consequently, we will not require utilities to retroactively implement the accounting and reporting requirements. 183. Utilities subject to the Commission’s accounting and reporting requirements must implement the requirements as of January 1, 2013. Utilities are not required to adjust prior year, comparative information reported in 2013 Form Nos. 1 and 1–F that must be filed by April 18, 2014, nor are they required to adjust prior year, comparative information reported in 2013 Form No. 3–Q reports. However, a footnote disclosure must be provided describing any amounts transferred from an existing account to a new energy storage account. 184. Due to outdated software, discussed in more detail below, the adopted new and revised schedules of Form Nos. 1, 1–F and 3–Q will not be available for use as of the effective date of this Final Rule. Consequently, utilities with energy storage assets and those that acquire the assets at a later date must continue or begin, as appropriate, using the existing form schedules to report energy storage assets pending availability of the new and revised schedules. Furthermore, we direct the Chief Accountant to issue interim accounting and reporting guidance for utilities to report to the Commission the costs of energy storage operations contemplated in this Final Rule until the new and revised schedules are available. 185. Regarding the reporting software issues, the Commission’s forms software applications are built with Visual VerDate Mar<15>2010 17:15 Jul 29, 2013 Jkt 229001 FoxPro development tools and must be installed on a Windows-based computer. Microsoft, the Visual FoxPro vendor, announced in 2007 that it would no longer sell or issue new versions of Visual FoxPro and would provide support for it only through 2015. Also, over time, the Commission has found that it is difficult to update tables in the software to accommodate revisions to existing schedules and add new schedules to the forms because Visual FoxPro does not allow data tables to exceed two gigabytes. These data size limitations will soon restrict the Commission’s ability to add data fields in the forms. These limitations make the forms software application outmoded, ineffective, and unsustainable. 186. Pursuant to Sections 141.1, 141.400, and 385.2011 of the Commission’s Regulations,216 Form Nos. 1 and 3–Q must be submitted using electronic media.217 Due to technology changes that will render the current forms filing process outmoded, ineffective, and unsustainable, the Commission will discontinue the use of Commission-distributed software to file forms. Moreover, because of the software limitations, the new and revised form schedules will not be available to utilities with energy storage assets and those that acquire the assets later as of the effective date of this Final Rule. Consequently, due to the time lag between implementation of the accounting and reporting requirements adopted here and the availability of a filing platform that accommodates the Commission’s reporting forms, utilities should submit their 2013 Form No. 1 and 2014 Form No. 3–Qs using the existing forms filing process until an updated filing platform is made available by the Commission. Commission staff will issue appropriate notices and hold technical conferences if necessary concerning changes to the filing process.218 D. Other Issues 187. Some commenters raised issues beyond the scope of the NOPR. WSPP argues that public utility participation 216 18 CFR 141.1, 141.400, and 385.2011 (2012), respectively. 217 Form No. 1–F filers may also submit the reports electronically; however, the Commission’s regulations do not explicitly require these filers to submit the reports electronically. See 18 CFR 141.2 (2012). 218 Filers with energy storage assets and operations may be required to amend and refile their 2013 Form Nos. 1 and 1–F and 2014 Form No. 3–Q to report energy storage operation information in the schedules adopted in this final rule as a result of the anticipated new filing platform. However, these filers will not be required to amend and refile previously submitted 2013 Form No. 3– Qs. PO 00000 Frm 00028 Fmt 4701 Sfmt 4700 in a competitive market for ancillary services is hindered by certain OATT requirements applicable to network transmission customers. Specifically, WSPP refers to the requirement that network resources be undesignated as such, and thus lose their firm network transmission service, when they are committed to third-party sales instead of network load obligations. WSPP points to timing mismatches between the operational needs of ancillary service use and the undesignation requirements of the OATT as the main source of this issue. It argues that the Commission previously acknowledged these issues in connection with contingency reserves under the Southwest Reserve Sharing Group.219 WSPP argues that this undesignation requirement hinders robust participation from network transmission customers, including the transmission providers themselves, in ancillary service markets. 188. EEI makes similar arguments with respect to the network resource undesignation requirements, and asks that the Commission remain receptive to utility-specific requests for flexibility.220 189. Hydro Association and Public Interest Organizations argue that the Commission should develop policies that facilitate long-term contracts with energy storage owners. Hydro Association asserts that the Commission should solicit further input on policies that would allow RTO, ISO, and standalone transmission providers to enter into long-term contracts with energy storage owners.221 Public Interest Organizations make similar arguments.222 190. Shell Energy suggests that the current distinction between Energy Imbalance and Generator Imbalance is unnecessary, and that the two services should be combined into a single product. Shell Energy cites similar definitions in the EQR Data Dictionary, and states that treating the two services as different products provides little benefit, creates unnecessary complexity and may result in confusion and regulatory uncertainty.223 191. Shell Energy also urges the Commission to recognize ‘‘Balancing Reserves’’ as a separate energy and capacity product used to firm variable energy resources. Shell Energy argues that such a product would be differentiated from ancillary services because, unlike ancillary services, it would not be limited to addressing 219 WSPP Comments at 19–21. Comments 21–22. 221 Hydro Association Comments at 4–6. 222 Public Interest Organizations Comments at 11. 223 Shell Energy Comments at 3–4. 220 EEI E:\FR\FM\30JYR3.SGM 30JYR3 emcdonald on DSK67QTVN1PROD with RULES3 Federal Register / Vol. 78, No. 146 / Tuesday, July 30, 2013 / Rules and Regulations contingencies. Shell Energy seeks clarification that such a product would not be considered an ancillary service, and thus would not be subject to the Avista restrictions. Rather it would be subject to a seller’s existing authorization to sell energy and capacity at market-based rates.224 EPSA makes similar arguments regarding the need for a new, non-contingency-related balancing reserves product.225 While WSPP’s comments do not specifically seek to identify a new product based on whether or not it can be used for issues other than contingencies, as do Shell Energy and EPSA, WSPP nevertheless makes certain similar arguments in part of its comments. WSPP asserts that sellers may not always wish to sell specific ancillary services, but rather may wish to sell ‘‘flexible capacity’’ products capable generally of fulfilling multiple OATT schedules. While its comments are not entirely clear on this point, WSPP could be interpreted to argue that the Commission should recognize flexible capacity as a product different from ancillary services.226 192. AWEA requests that the Commission explore the role that dynamic transfer capability, or lack thereof, plays in protecting against exertion of market power. AWEA argues that lack of dynamic transfer capability severely constrains competitive ancillary service markets in many parts of the country. AWEA suggests that the Commission could require transmission providers to analyze, inventory, and market dynamic scheduling capability on a non-discriminatory basis.227 193. Powerex argues that there may be certain locations where there is sufficient market liquidity such that a seller should be able to make ancillary service sales without performing a separate market power analysis. Powerex believes that these locations might be defined by some measure of market liquidity, or by a specific minimum number of potential sellers, and gives as examples the trading hubs of Mid-Columbia, California-Oregon Border, Palo Verde, Four Corners, and Mead. Powerex does not suggest specific liquidity metrics, but does have suggestions regarding the appropriate minimum number of potential suppliers. It suggests that third-party sales to a transmission provider could be deemed competitive any time there are: (1) At least three potential suppliers, each capable of providing 100 percent of the buyer’s needs for the ancillary service in question; or (2) at 224 Shell 225 EPSA least five potential suppliers, each capable of meeting a significant portion (e.g., at least 25 percent) of the buyer’s need for the ancillary service in question. Commission Determination 194. With respect to WSPP’s request for more flexibility on the requirements for network resource undesignation, the Commission declines to consider such changes on a generic basis at this time. This undesignation requirement is intended to ensure that network transmission customers cannot inappropriately withhold firm transmission capacity from potential competitors. While WSPP is correct that the Commission has permitted limited deviations from this requirement in connection with established reserve sharing groups, we are not persuaded that a more general relaxation is justified. WSPP indicates in its comments that a public utility is unable to undesignate the network resource providing the energy associated with the provision of ancillary services because the unit providing the energy may differ from the unit providing the capacity. This suggests that the public utility will be using transmission service from a unit that is different from the unit for which transmission service has been reserved. Thus, WSPP is essentially asking the Commission to permit a public utility transmission provider to implicitly use firm point-to-point transmission service without reserving it or paying for it. The Commission has previously expressly prohibited this practice and nothing in the comments suggests that the Commission’s concerns are no longer valid.228 Further, participating in a reserve sharing group differs from making third-party market sales of ancillary services. A reserve sharing group essentially expands a public utility transmission provider’s native load obligations to serving other load serving entities’ native load in the event of a contingency with like protection in return. Permitting a public utility transmission provider to deliver energy associated with its reserve sharing group obligations without undesignating the resource providing the energy is an appropriate recognition of the network service elements of reserve sharing arrangements. On the other hand, market sales of ancillary services must be delivered using pointto-point transmission service. 195. With respect to the requests of Hydro Association and Public Interest Energy Comments at 5–6. Comments at 10–11. VerDate Mar<15>2010 17:15 Jul 29, 2013 Jkt 229001 226 WSPP Comments at 7. Comments at 3. 227 AWEA PO 00000 Frm 00029 Fmt 4701 Sfmt 4700 46205 Organizations to facilitate long-term contracting with energy storage owners, we see no basis for any additional action at this time. In bilateral markets, assuming that parties are able to avoid the Avista restrictions through use of one of the options provided in this rule, potential buyers including transmission owners and sellers are free to transact through contracts of whatever length they find mutually agreeable. 196. Shell Energy’s suggestion that Energy Imbalance and Generator Imbalance services be combined into a single product is beyond the scope of this rulemaking, and Shell Energy’s arguments in support of this idea do not rise to a level concrete enough to justify such an expansion at this time. 197. With respect to Shell Energy and EPSA’s comments regarding recognition of non-contingency-related balancing reserves as separate from ancillary services, and WSPP’s similar discussion of ‘‘flexible capacity,’’ we clarify that sales of energy and capacity at marketbased rates are permissible, provided the buyer may not use the purchases to meet its OATT obligations to provide Regulation and Frequency Response or Reactive Supply and Voltage Control ancillary services. 198. AWEA’s comments regarding dynamic transfer capability raise issues beyond the scope of this rulemaking, which have not been fully explored in this proceeding, and whose resolution is not necessary to the completion of this rulemaking. Accordingly, the Commission will not direct changes with respect to dynamic scheduling or dynamic transfer capability at this time. 199. Regarding Powerex’s argument for development of a new market liquidity screen for ancillary service market power, we decline to attempt such development at this time. The record does not currently support either development of a generic market liquidity metric, or the particular minimum participant number thresholds proposed by Powerex. We remain open to a more detailed discussion of these ideas in the future if needed, but at this time will move forward with the rule changes contained elsewhere in this Final Rule, which we hope will reduce the need to develop alternative market power analyses. III. Summary of Compliance and Implementation BILLING CODE 6717–01–P 228 Order No. 890, FERC Stats. & Regs. ¶ 31,241 at P 834. E:\FR\FM\30JYR3.SGM 30JYR3 46206 200. Federal Register / Vol. 78, No. 146 / Tuesday, July 30, 2013 / Rules and Regulations With respect to this Final Rule's reforms to the Avista policy governing sales of certain ancillary services to a public utility purchasing the ancillary service to satisfy its own OATT requirements to offer ancillary services to its own customers, sellers that have a market-based rate tariff on file should revise the provision concerning third-party sales of ancillary services, to the extent they have this provision in their tariffs, as follows: Third-party ancillary services: Seller offers [include all of the following that the seller is offering: Regulation and Frequency Response Service, Reactive Supply and Voltage Control Service, Energy and Generator Imbalance Service, Operating Reserve-Spinning Resef¥es, and Operating Reserve-Supplemental Resef¥es]. Sales will not include the following: (1) Sales to an RTO or an ISO, i.e., where that entity has no ability to selfsupply ancillary services but instead depends on third parties; and (2) sales to a traditional, franchised public utility affiliated with the third-party supplier, or sales where the underlying transmission service is on the system of the public utility affiliated with the third-party supplier; and (3) sales to a publie utility that is pUTehasing aneillaT)' serviees to satisfy its own open aeeess transmission tariff requirements to offer aneillaT)' serviees to its OVID eustomers. Sales of Operating Reserve-Spinning and Operating Reserve-Supplemental will not include sales to a public utility that is purchasing ancillary services to satisfy its own open access transmission tariff requirements to offer ancillary services to its own customers, except where the Commission has granted authorization. Control Service will not include sales to a public utility that is purchasing ancillary VerDate Mar<15>2010 17:15 Jul 29, 2013 Jkt 229001 PO 00000 Frm 00030 Fmt 4701 Sfmt 4725 E:\FR\FM\30JYR3.SGM 30JYR3 ER30JY13.004</GPH> emcdonald on DSK67QTVN1PROD with RULES3 Sales of Regulation and Frequency Response Service and Reactive Supply and Voltage 46207 Federal Register / Vol. 78, No. 146 / Tuesday, July 30, 2013 / Rules and Regulations 201. While the authorization is effective as of the date specified in this Final Rule, sellers should file this tariff revision the next time they make a market-based rate filing with the Commission. To the extent sellers do not currently have this provision in their tariff but wish to make third-party sales of ancillary services, they should include this revised provision in their tariff the next time they make a marketbased rate filing with the Commission. 202. With regard to sales of Operating Reserves, as discussed above, both sellers that have a market-based rate tariff on file and applicants seeking new market-based rate authority must satisfactorily make the required showing and receive Commission authorization before making sales of Operating Reserve-Spinning and Operating Reserve-Supplemental to a public utility that is purchasing Operating ReserveSpinning and Operating ReserveSupplemental to satisfy its own open access transmission tariff requirements to offer ancillary services to its own customers. 203. With respect to the Final Rule’s reforms to provide greater transparency with regard to reserve requirements for Regulation and Frequency Response, within 30 days from the effective date of this Final Rule, we require each public utility transmission provider to revise its OATT Schedule 3 consistent with the revised Schedule 3 in accordance with Appendix B to this Final Rule. 204. With respect to Final Rule’s reforms to our accounting and reporting regulations, utilities subject to these requirements must implement the requirements as of January 1, 2013. Utilities are not required to adjust prior year, comparative information reported in 2013 Form Nos. 1 and 1–F that must be filed by April 18, 2014, nor are they required to adjust prior year, comparative information reported in 2013 Form No. 3–Q reports. However, a footnote disclosure must be provided describing any amounts transferred from an existing account to a new energy storage account. 205. Due to outdated software, discussed in more detail in the body of this Final Rule, the adopted new and revised schedules of Form Nos. 1, 1–F and 3–Q will not be available for use as of the effective date of this Final Rule. Form No. 1 ................................ 210 .................. Form No. 1–F ............................ emcdonald on DSK67QTVN1PROD with RULES3 Number of respondents (a) 5 ...................... Form No. 3–Q ........................... FERC–917 [includes one-time filing of Pro forma open-access transmission tariff (OATT) & data sharing] 233. FERC–516 ................................ 213 .................. 132 .................. 230 5 no change ....... 44 U.S.C. 3507(d). CFR 1320.11 (2012). VerDate Mar<15>2010 18:30 Jul 29, 2013 206. The following collections of information contained in this Final Rule have been submitted to the Office of Management and Budget (OMB) for review under Section 3507(d) of the Paperwork Reduction Act of 1995.229 OMB’s regulations require approval of certain information collection requirements imposed by agency rule.230 Upon approval of a collection of information, OMB will assign an OMB control number and an expiration date. Respondents subject to the filing requirements of a rule will not be penalized for failing to respond to these collections of information if the collections of information do not display a valid OMB control number. Burden Estimate: The additional estimated public reporting burdens and costs for the reporting requirements in this Final Rule are as follows.231 Filings per respondent per year (c) Change in the total annual hours for this collection (averaging implementation over Yrs. 1–3) (aXbXc=d) (hrs.) 7 [3 hrs. (one-time implementation in Year 1), plus 6 hrs. annually]. 7 [3 hrs. (one-time implementation in Year 1), plus 6 hrs. annually]. 1 ................................................ 17.33 averaged over Years 1–3 [4 hrs. one-time in Yr. 1, plus an average recurring burden in Years 1–3 of 16 hrs.]. no change ................................. 1 ...................... 1,470 ..................... 176,400 1 ...................... 35 .......................... 4,200 3 ...................... 1 ...................... 639 ........................ 2,288 averaged over Years 1–3. 76,680 274,560 averaged over Years 1–3 no change ....... no change ............. no change 231 In the NOPR, the Commission proposed changes to FERC–919 (related to the ‘20 percent screen’). The FERC–919 is not affected by the Final Jkt 229001 IV. Information Collection Statement Change in the number of hours per filing (averaging implementation over Yrs. 1–3) 232 (b) (hrs.) Data collection 229 See Consequently, utilities with energy storage assets and those that acquire the assets at a later date must continue or begin, as appropriate, using the existing form schedules to report energy storage assets pending availability of the new and revised schedules. PO 00000 Frm 00031 Fmt 4701 Sfmt 4700 Estimated annual cost (averaging implementation over Yrs. 1–3) (at $120/hr.) (dX$120/hr.) ($) Rule. In addition, changes to FERC–516, which were not contained in the NOPR, are included in the Final Rule. E:\FR\FM\30JYR3.SGM 30JYR3 ER30JY13.005</GPH> BILLING CODE 6717–01–C 46208 Federal Register / Vol. 78, No. 146 / Tuesday, July 30, 2013 / Rules and Regulations Number of respondents (a) Data collection FERC–717 (OASIS posting under 18 CFR 37.6k). Total ................................... Change in the number of hours per filing (averaging implementation over Yrs. 1–3) 232 (b) (hrs.) Filings per respondent per year (c) Change in the total annual hours for this collection (averaging implementation over Yrs. 1–3) (aXbXc=d) (hrs.) 176 .................. 1 ................................................ 1 ...................... 176 ........................ 9,889 234 ......................... ................................................... ......................... 4,608 (averaged over Years 1–3). $541,729 (averaged over Years 1–3) emcdonald on DSK67QTVN1PROD with RULES3 In paragraph 96, the Commission is requiring that any third-party seller seeking to sell ancillary services to a public utility transmission provider through a competitive solicitation will need to demonstrate compliance with the competitive solicitation requirements of this rule, through a filing under section 205 of the Federal Power Act. This requirement for submittal in a section 205 filing would be made under FERC–516 (OMB Control No. 1902–0096). The filing would be submitted by the seller to the Commission prior to commencement of service under the third-party ancillary service sales agreement that results from the competitive solicitation. The filing will include both the actual sales agreement and a narrative description of how the buyer’s competitive solicitation meets the requirements of this Final Rule. Meeting those requirements demonstrates the justness and reasonableness of the resulting rate. If the seller did not have this option to sell under the competitive solicitation, the 232 For the Forms 1 and 1–F, the one-time implementation burden in Year 1 is estimated to be 3 hours per respondent. However, for the burden and cost estimates, we are averaging those additional 3 hours over Years 1–3, giving an average annual one-time implementation burden of 1 hour. That 1 hour is in addition to the normal annual filing burden of 6 hours each, giving an average annual estimate of 7 hours for Forms 1 and 1–F, for Years 1–3. 233 This includes the one-time refiling of OATT Schedule 3 (estimated average of 4 hours per utility respondent), and if requested, the utility’s sharing data and a narrative description with its selfsupplying customer(s) (estimated average of 4 customer requests per utility respondent per year, taking 4 hours per request). The estimated annual burden per utility is • Year 1: 4 hrs. (for one-time refiling) + (4 requests * 4 hrs.), giving an estimate of 20 hrs. per utility • Years 2 and 3, each: 4 requests * 4 hrs., giving 16 hrs. per utility per year. When the one-time implementation burden (of 4 hours) is averaged over Years 1–3, the annual additional burden per utility is 17.33 hours. 234 Based on the 2012 data from the Bureau of Labor Statistics at https://bls.gov/oes/current/ naics2_22.htm, the hourly cost of salary plus benefits would be $56.19. VerDate Mar<15>2010 18:30 Jul 29, 2013 Jkt 229001 seller could not use market-based rates and would have to either submit an application for cost-based rates under FERC–516 or an application seeking waiver of the Avista restrictions on a case-by-case basis.235 The Commission believes that the burden associated with the new requirements is far less burden than a full cost-of-service rate filing and approximately the same burden as the burden associated with an Avista waiver filing. In addition, the numbers of respondents and filings are not expected to change significantly. Therefore, no changes are proposed to the burden or number of responses for FERC–516. Title: FERC Form No. 1, ‘‘Annual Report of Major Electric Utilities, Licensees, and Others;’’ FERC Form No. 1–F, ‘‘Annual Report for Nonmajor Public Utilities and Licensees;’’ FERC Form No. 3–Q, ‘‘Quarterly Financial Report of Electric Utilities, Licensees and Natural Gas Companies;’’ FERC– 917, ‘‘Non-discriminatory Open Access Transmission Tariff;’’ FERC–516, ’’ Electric Rate Schedules and Tariff Filings,’’ and FERC–717, ‘‘Open Access Same-Time Information System and Standards for Business Practices & Communication Protocols.’’ Action: Proposed revisions to information collections. OMB Control Nos.: 1902–0021 (FERC Form No. 1); 1902–0029 (FERC Form No. 1–F); 1902–0205 (FERC Form No. 3– Q); 1902–0233 (FERC–917), 1902–0096 (FERC–516), and 1902–0173 (FERC– 717). Respondents: Businesses or other for profit and/or not-for-profit institutions. Frequency of responses: Annually (FERC Form Nos. 1 and 1–F, and FERC– 717); quarterly (FERC Form No. 3–Q); and as needed (FERC–917 and FERC– 516). Necessity of the Information: The final rule amends the Commission’s regulations to reflect changes that are occurring in the electric industry due to the availability of new energy storage technologies that are being used in the PO 00000 235 See, e.g., Powerex, 125 FERC ¶ 61,179 (2008). Frm 00032 Fmt 4701 Sfmt 4700 Estimated annual cost (averaging implementation over Yrs. 1–3) (at $120/hr.) (dX$120/hr.) ($) provision of large-scale utility operations. These technologies are providing services that were typically provided by traditional single-purpose production, transmission and distribution resources. The addition of these new plant accounts and new and amended reporting forms are intended to enhance transparency and provide detailed information on transactions and events affecting public utilities and licensees that file reports with the Commission. The accounting regulations currently found in the USofA and related reporting requirements capture financial and operational information along traditional primary business functions but do not provide sufficient detailed information concerning energy storage operations, and in particular, the costs incurred by organizations using these resources to simultaneously provide multiple utility services with a single asset. The addition of these accounts is intended to improve the transparency, completeness and consistency of accounting practices for the cost of assets, the expenses incurred in providing services, along with revenues collected. Without specific instructions and accounts for recording and reporting the above transactions and events, inconsistent and incomplete accounting and reporting will result. Internal Review: The Commission has reviewed the requirements pertaining to the USofA and to the reports it prescribes and determined that the proposed amendments are necessary because the Commission needs to establish uniform accounting and reporting requirements for the costs of utility assets and the expenses incurred for providing services as part of its operations. These requirements conform to the Commission’s need for efficient information collection, communication, and management within the energy industry. The Commission has assured itself, by means of internal review, that there is specific, objective support for E:\FR\FM\30JYR3.SGM 30JYR3 Federal Register / Vol. 78, No. 146 / Tuesday, July 30, 2013 / Rules and Regulations the burden estimates associated with the information collection requirements. Interested persons may obtain information on the reporting requirements by contacting the following: Federal Energy Regulatory Commission, 888 First Street NE., Washington, DC 20426 [Attention: Ellen Brown, Office of the Executive Director], email: DataClearance@ferc.gov, Phone (202) 502–8663, fax: (202) 273–0873. Comments on the collection of information and the associated burden estimates in the rule should be sent to the Commission in this docket and may also be sent to the Office of Information and Regulatory Affairs, Office of Management and Budget, Washington, DC 20503 [Attention: Desk Officer for the Federal Energy Regulatory Commission]. For security reasons, comments to OMB should be submitted by email to: oira_submission@omb.eop.gov. Please refer to OMB Control Nos. 1902–0021 (FERC Form No. 1), 1902–0029 (FERC Form No. 1–F), 1902–0205 (FERC Form No. 3–Q), and 1902–0233 (FERC–917), 1902–0096 (FERC–516), and 1902–0173 (FERC–717) and Docket Number RM11– 24. emcdonald on DSK67QTVN1PROD with RULES3 Environmental Analysis 207. The Commission is required to prepare an Environmental Assessment or an Environmental Impact Statement for any action that may have a significant adverse effect on the human environment.236 The Commission concludes that neither an Environmental Assessment nor an Environmental Impact Statement is required for this Final Rule under section 380.4(a)(15) of the Commission’s regulations, which provides a categorical exemption for approval of actions under sections 205 and 206 of the FPA relating to the filing of schedules containing all rates and charges for the transmission or sale subject to the Commission’s jurisdiction, plus the classification, practices, contracts, and regulations that affect rates, charges, classifications, and services.237 VI. Regulatory Flexibility Act 208. The Regulatory Flexibility Act of 1980 (RFA) 238 generally requires a description and analysis of rules that will have significant economic impact on a substantial number of small entities. The RFA mandates 236 Regulations Implementing the National Environmental Policy Act, Order No. 486, 52 FR 47897 (Dec. 17, 1987), FERC Stats. & Regs. Regulations Preambles 1986–1990 ¶ 30,783 (1987). 237 18 CFR 380.4(a)(15) (2012). 238 5 U.S.C. 601–612. VerDate Mar<15>2010 17:15 Jul 29, 2013 Jkt 229001 consideration of regulatory alternatives that accomplish the stated objectives of a proposed rule and that minimize any significant economic impact on a substantial number of small entities. The Small Business Administration’s (SBA) Office of Size Standards develops the numerical definition of a small business.239 The SBA has established a size standard for electric utilities, stating that a firm is small if, including its affiliates, it is primarily engaged in the transmission, generation and/or distribution of electric energy for sale and its total electric output for the preceding twelve months did not exceed four million megawatt hours.240 The rule applies exclusively to public utilities that own, control, or operate facilities for transmitting electric energy in interstate commerce and not electric utilities per se. Based on the filers of the 2011 annual FERC Form No. 1 and Form No. 1–F, as well as the number of companies that have obtained waivers, we estimate that 44 entities (20 percent of the filers) affected by this proposed rule are ‘‘small.’’ For each of the 44 ‘‘small’’ entities, the Commission estimates an additional annual burden of only ten hours (seven hours for the annual Form 1 or Form 1–F (averaging implementation over years 1–3), plus one hour per quarter for the Form 3–Q). The Commission believes this rule will not have a significant economic impact on a substantial number of small entities, and therefore no regulatory flexibility analysis is required. VII. Document Availability 209. In addition to publishing the full text of this document in the Federal Register, the Commission provides all interested persons an opportunity to view and/or print the contents of this document via the Internet through the Commission’s Home Page (https:// www.ferc.gov) and in the Commission’s Public Reference Room during normal business hours (8:30 a.m. to 5:00 p.m. Eastern time) at 888 First Street NE., Room 2A, Washington, DC 20426. 210. From the Commission’s Home Page on the Internet, this information is available on eLibrary. The full text of this document is available on eLibrary in PDF and Microsoft Word format for viewing, printing, and/or downloading. To access this document in eLibrary, type the docket number, excluding the last three digits of this document in the docket number field. 211. User assistance is available for eLibrary and the Commission’s Web site during normal business hours from the PO 00000 239 13 240 13 CFR 121.101 (2011). CFR 121.201, Sector 22, Utilities. Frm 00033 Fmt 4701 Sfmt 4700 46209 Commission’s Online Support at 202– 502–6652 (toll free at 1–866–208–3676) or email at ferconlinesupport@ferc.gov, or the Public Reference Room at (202) 502–8371, TTY (202)502–8659. Email the Public Reference Room at public.referenceroom@ferc.gov. Effective Date and Congressional Notification. These regulations are effective November 27, 2013. The Commission has determined, with the concurrence of the Administrator of the Office of Information and Regulatory Affairs of OMB, that this rule is not a ‘‘major rule’’ as defined in section 351 of the Small Business Regulatory Enforcement Fairness Act of 1996. List of Subjects 18 CFR Part 35 Electric power rates, Electric utilities, Reporting and recordkeeping requirements 18 CFR Part 101 Electric power, Electric utilities, Uniform System of Accounts. By direction of the Commission. Nathaniel J. Davis, Sr., Deputy Secretary. In consideration of the foregoing, the Commission amends Parts 35 and 101, Chapter I, Title 18, Code of Federal Regulations, as follows. PART 35—FILING OF RATE SCHEDULES AND TARIFFS 1. The authority citation for part 35 continues to read as follows: ■ Authority: 16 U.S.C. 791a–825r, 2601– 2645; 31 U.S.C. 9701; 42 U.S.C. 7101–7352. 2. Amend § 35.37 by revising paragraph (c)(1) to read as follows: ■ § 35.37 Market power analysis required. * * * * * (c)(1) There will be a rebuttable presumption that a Seller lacks horizontal market power with respect to sales of energy, capacity, energy imbalance, and generator imbalance services if it passes two indicative market power screens: A pivotal supplier analysis based on annual peak demand of the relevant market, and a market share analysis applied on a seasonal basis. There will be a rebuttable presumption that a Seller lacks horizontal market power with respect to sales of operating reservespinning and operating reservesupplemental services if the Seller passes these two indicative market power screens and demonstrates in its market-based rate application how the scheduling practices in its region E:\FR\FM\30JYR3.SGM 30JYR3 46210 Federal Register / Vol. 78, No. 146 / Tuesday, July 30, 2013 / Rules and Regulations support the delivery of operating reserve resources from one balancing authority area to another. There will be a rebuttable presumption that a seller possesses horizontal market power with respect to sales of energy, capacity, energy imbalance, generator imbalance, operating reserve-spinning, and operating reserve-supplemental services if it fails either screen. * * * * * 5. The authority citation for part 101 continues to read as follows: ■ Authority: 16 U.S.C. 791a–825r, 2601– 2645; 31 U.S.C. 9701; 42 U.S.C. 7101–7352, 7651–7651o. 6. In Part 101: a. Under Electric Plant Chart of Accounts, Account 348 is added to the list; ■ b. Under Electric Plant Accounts, Account 351, the name of the account is revised and instructions are added; ■ c. Under Electric Plant Accounts, Account 363, the name of the account and the instructions are revised; ■ d. Under Electric Plant Accounts, primary plant account 348 is added; ■ e. Under Operation and Maintenance Expense Chart of Accounts, Accounts 548.1, 553.1, 555.1, 562.1, 570.1, 584.1, and 592.2 are added to the list; ■ f. Under Operation and Maintenance Expense Accounts, operation expense account 548.1 is added; ■ g. Under Operation and Maintenance Expense Accounts, maintenance expense account 553.1 is added; ■ h. Under Operation and Maintenance Expense Accounts, power supply expense account 555.1 is added; ■ i. Under Operation and Maintenance Expense Accounts, operation expense account 562.1 is added; ■ j. Under Operation and Maintenance Expense Accounts, maintenance expense account 570.1 is added; ■ k. Under Operation and Maintenance Expense Accounts, operation expense account 584.1 is added; ■ l. Under Operation and Maintenance Expense Accounts, maintenance expense account 592.2 is revised; and ■ m. Under Operation and Maintenance Expense Accounts, maintenance expense account 592.1 is revised; The revisions and additions read as follows: ■ ■ 3. Amend § 35.38 as follows: ■ a. Paragraph (a) is revised. ■ b. Paragraph (b) introductory text is revised. ■ c. Paragraph (c) is added. The revisions and addition read as follows: ■ § 35.38 PART 101—UNIFORM SYSTEM OF ACCOUNTS PRESCRIBED FOR PUBLIC UTILITIES AND LICENSES SUBJECT TO THE PROVISIONS OF THE FEDERAL POWER ACT Mitigation. * * * * * (a) A Seller that has been found to have market power in generation or ancillary services, or that is presumed to have horizontal market power in generation or ancillary services by virtue of failing or foregoing the relevant market power screens, as described in 35.37(c), may adopt the default mitigation detailed in paragraph (b) of this section for sales of energy or capacity or paragraph (c) of this section for sales of ancillary services or may propose mitigation tailored to its own particular circumstances to eliminate its ability to exercise market power. Mitigation will apply only to the market(s) in which the Seller is found, or presumed, to have market power. (b) Default mitigation for sales of energy or capacity consists of three distinct products: * * * * * (c) Default mitigation for sales of ancillary services consist of: (1) A cap based on the relevant OATT ancillary service rate of the purchasing transmission operator; or (2) the results of a competitive solicitation that meets the Commission’s requirements for transparency, definition, evaluation, and competitiveness. ■ PART 101—UNIFORM SYSTEM OF ACCOUNTS PRESCRIBED FOR PUBLIC UTILITIES AND LICENSES SUBJECT TO THE PROVISIONS OF THE FEDERAL POWER ACT § 37.6 Information to be posted on the OASIS. * * Electric Plant Chart of Accounts emcdonald on DSK67QTVN1PROD with RULES3 4. Amend § 37.6 by adding paragraph (k) to read as follows: * * * * (k) Posting of historical area control error data. The Transmission Provider must post on OASIS historical oneminute and ten-minute area control error data for the most recent calendar year, and update this posting once per year. VerDate Mar<15>2010 17:15 Jul 29, 2013 Jkt 229001 * * * * * * * * * 2. Production Plant * * * * * D. Other Production * PO 00000 * Frm 00034 * * Fmt 4701 * Sfmt 4700 348 Energy Storage Equipment— Production * * * * * Electric Plant Accounts * * * * * 351 Energy Storage Equipment— Transmission A. This account shall include the cost installed of energy storage equipment used to store energy for load managing purposes. Where energy storage equipment can perform more than one function or purposes, the cost of the equipment shall be allocated among production, transmission, and distribution plant based on the services provided by the asset and the allocation of the asset’s cost through rates approved by a relevant regulatory agency. Reallocation of the cost of equipment recorded in this account shall be in accordance with Electric Plant Instruction No. 12, Transfers of Property. B. Labor costs and power purchased to energize the equipment are includible on the first installation only. The cost of removing, relocating and resetting energy storage equipment shall not be charged to this account but to Account 562.1, Operation of Energy Storage Equipment, and Account, 570.1, Maintenance of Energy Storage Equipment, as appropriate. C. The records supporting this account shall show, by months, the function(s) each energy storage asset supports or performs. Items 1. Batteries/Chemical 2. Compressed Air 3. Flywheels 4. Superconducting Magnetic Storage 5. Thermal * * * * * 363 Energy Storage Equipment— Distribution A. This account shall include the cost installed of energy storage equipment used to store energy for load managing purposes. Where energy storage equipment can perform more than one function or purpose, the cost of the equipment shall be allocated among production, transmission, and distribution plant based on the services provided by the asset and the allocation of the asset’s cost through rates approved by a relevant regulatory agency. Reallocation of the cost of equipment recorded in this account shall be in accordance with Electric Plant Instruction No. 12, Transfers of Property. B. Labor costs and power purchased to energize the equipment are includible E:\FR\FM\30JYR3.SGM 30JYR3 Federal Register / Vol. 78, No. 146 / Tuesday, July 30, 2013 / Rules and Regulations on the first installation only. The cost of removing, relocating and resetting energy storage equipment shall not be charged to this account but to Account 582.1, Operation of Energy Storage Equipment, and Account, 592.1, Maintenance of Energy Storage Equipment, as appropriate. C. The records supporting this account shall show, by months, the function(s) each energy storage asset supports or performs. Items 1. Batteries/Chemical 2. Compressed Air 3. Flywheels 4. Superconducting Magnetic Storage 5. Thermal * * * * * 348 Energy Storage Equipment— Production emcdonald on DSK67QTVN1PROD with RULES3 Items 1. Batteries/Chemical 2. Compressed Air 3. Flywheels 4. Superconducting Magnetic Storage 5. Thermal Note: The cost of pumped storage hydroelectric plant shall be charged to hydraulic production plant. These are examples of items includible in this account. This list is not exhaustive. * * * * * 17:15 Jul 29, 2013 Jkt 229001 * * * * * 1. Power Production Expenses * * * * * D. Other Power Generation * * * * * * * * Operation * * 548.1 Operation of Energy Storage Equipment * * * * * Maintenance 553.1 Maintenance of Energy Storage Equipment * A. This account shall include the cost installed of energy storage equipment used to store energy for load managing purposes. Where energy storage equipment can perform more than one function or purpose, the cost of the equipment shall be allocated among production, transmission, and distribution plant based on the services provided by the asset and the allocation of the asset’s cost through rates approved by a relevant regulatory agency. Reallocation of the cost of equipment recorded in this account shall be in accordance with Electric Plant Instruction No. 12, Transfers of Property. B. Labor costs and power purchased to energize the equipment are includible on the first installation only. The cost of removing, relocating and resetting energy storage equipment shall not be charged to this account but to accounts Account 548.1, Operation of Energy Storage Equipment, and Account 553.1, Maintenance of Energy Storage Equipment., as appropriate. C. The records supporting this account shall show, by months, the function(s) each energy storage asset supports or performs. VerDate Mar<15>2010 Operation and Maintenance Expense Chart of Accounts * * * * E. Other Power Supply Expenses * * * * * 555.1 Power Purchased for Storage Operations * * * * * 2. Transmission Expenses * * * * * * * * Operation * * 562.1 Operation of Energy Storage Equipment * * * * * * * Maintenance * * * 570.1 Maintenance of Energy Storage Equipment * * * * * 4. Distribution Expenses * * * * * * * * Operation * * 584.1 Operation of Energy Storage Equipment * * * * * * * Maintenance * * * 592.2 Maintenance of Energy Storage Equipment * * * * * Operation and Maintenance Expense Accounts * PO 00000 * Frm 00035 * * Fmt 4701 * Sfmt 4700 46211 548.1 Operation of Energy Storage Equipment This account shall include the cost of labor, materials used and expenses incurred in the operation of energy storage equipment includible in Account 348, Energy Storage Equipment—Production, which are not specifically provided for or are readily assignable to other production operation expense accounts. * * * * * 553.1 Maintenance of Energy Storage Equipment This account shall include the cost of labor, materials used and expenses incurred in the maintenance of energy storage equipment includible in Account 348, Energy Storage Equipment—Production, which are not specifically provided for or are readily assignable to other production maintenance expense accounts. * * * * * 555.1 Power Purchased for Storage Operations A. This account shall include the cost at point of receipt by the utility of electricity purchased for use in storage operations, including power purchased and consumed or lost in energy storage operations during the provision of services, including but not limited to energy purchased and stored for resale. It shall also include but not be limited to net settlements for exchange of electricity or power, such as economy energy, off-peak energy for on-peak energy, and spinning reserve capacity. In addition, the account shall include the net settlements for transactions under pooling or interconnection agreements wherein there is a balancing of debits and credits for energy, capacity, and possibly other factors. Distinct purchases and sales shall not be recorded as exchanges and net amounts only recorded merely because debit and credit amounts are combined in the voucher settlement. B. The records supporting this account shall show, by months, the kilowatt hours and prices thereof under each purchase contract and the charges and credits under each exchange or power pooling contract. * * * * * 562.1 Operation of Energy Storage Equipment This account shall include the cost of labor, materials used and expenses incurred in the operation of energy storage equipment includible in Account 351, Energy Storage Equipment—Transmission, which are E:\FR\FM\30JYR3.SGM 30JYR3 46212 Federal Register / Vol. 78, No. 146 / Tuesday, July 30, 2013 / Rules and Regulations not specifically provided for or are readily assignable to other transmission operation expense accounts. * * * * * 570.1 Maintenance of Energy Storage Equipment This account shall include the cost of labor, materials used and expenses incurred in the maintenance of energy storage equipment includible in Account 351, Energy Storage Equipment—Transmission, which are not specifically provided for or are readily assignable to other transmission maintenance expense accounts. * * * * * 584.1 Operation of Energy Storage Equipment This account shall include the cost of labor, materials used and expenses incurred in the operation of energy storage equipment includible in Account 363, Energy Storage Equipment—Distribution, which are not specifically provided for or are readily assignable to other distribution operation expense accounts. * * * * * account 362, Station Equipment. (See operating expense instruction 2.) * * * * * 592.2 Maintenance of Energy Storage Equipment This account shall include the cost of labor, materials used and expenses incurred in maintenance of structures, the book cost of which is includible in account 361, Structures and Improvements, and account 362, Station Equipment. (See operating expense instruction 2.) This account shall include the cost of labor, materials used and expenses incurred in the maintenance of energy storage equipment includible in Account 363, Energy Storage Equipment—Distribution, which are not specifically provided for or are readily assignable to other distribution maintenance expense accounts. * * * * * 592 Maintenance of Station Equipment (Major Only) This account shall include the cost of labor, materials used and expenses incurred in maintenance of plant, the book cost of which is includible in 592.1 Maintenance of Structures and Equipment (Nonmajor Only) Note: The following appendix will not appear in the Code of Federal Regulations. Appendix A: List of Short Names of Commenters on the Federal Energy Regulatory Commission’s Notice of Proposed Rulemaking on Third-Party Provision of Ancillary Services; Accounting and Financial Reporting for New Electric Storage Technologies— Docket No. RM11–24–000, June 2012 Short name or acronym Commenter APPA .................................... AWEA ................................... Beacon ................................. California PUC ..................... California Storage Alliance ... EEI ........................................ Electricity Consumers .......... ENBALA ............................... EPSA .................................... ESA ...................................... FTC Staff .............................. Hydro Association ................ Iberdrola ............................... Indicated Suppliers ............... Midwest ISO ......................... Morgan Stanley .................... NAATBatt ............................. New York ISO ...................... NU Companies ..................... American Public Power Association American Wind Energy Association Beacon Power Corporation California Public Utilities Commission California Energy Storage Alliance Edison Electric Institute Electricity Consumers Resource Council ENBALA Power Networks Electric Power Supply Association Electricity Storage Association Staff of the Federal Trade Commission National Hydropower Association Iberdrola Renewables, LLC Calpine Corporation, Dynegy Inc., Exelon Corporation, GenOn Energy, Inc., and Tenaska Energy, Inc. Midwest Independent Transmission System Operator Inc. Morgan Stanley Capital Group Inc. National Alliance for Advanced Technology Batteries New York Independent System Operator, Inc. Northeast Utilities Service Company on behalf of Connecticut Light and Power Company, Western Massachusetts Electric Company, Public Service Company of New Hampshire, and NSTAR Electric Company Powerex Corporation Center for Rural Affairs, Clean Wisconsin, Climate + Energy Project, Conservation Law Foundation, Environment Northeast, Fresh Energy, Land Trust Alliance, Natural Resources Defense Council, Pace Energy and Climate Center, Project for Sustainable FERC Energy Policy, Sierra Club and Union of Concerned Scientists Public Power Council San Diego Gas & Electric Company Shell Energy North America (US), L.P. Solar Energy Industries Association Southern California Edison Company Transmission Access Policy Study Group and Transmission Dependent Utility Systems Arizona Public Service, Avista Corporation, Bonneville Power Administration, Idaho Power Company, PacifiCorp, Portland General Electric, Xcel Energy Services, Puget Sound Energy, Inc., Seattle City Light, and Takoma Power WSPP, Inc. Powerex ............................... Public Interest Organizations Public Power Council ........... SDG&E ................................. Shell Energy ......................... Solar Energy Association ..... Southern California Edison .. TAPS .................................... Western Group ..................... emcdonald on DSK67QTVN1PROD with RULES3 WSPP ................................... Note: The following Appendix will not appear in the Code of Federal Regulations. Appendix B: Pro Forma Open Access Transmission Tariff The Commission amends Schedule 3, Regulation and Frequency Response Service of the pro forma OATT: VerDate Mar<15>2010 17:15 Jul 29, 2013 Jkt 229001 PO 00000 Frm 00036 Fmt 4701 Sfmt 4700 Schedule 3 Regulation and Frequency Response Service Regulation and Frequency Response Service is necessary to provide for the continuous balancing of resources E:\FR\FM\30JYR3.SGM 30JYR3 Federal Register / Vol. 78, No. 146 / Tuesday, July 30, 2013 / Rules and Regulations emcdonald on DSK67QTVN1PROD with RULES3 (generation and interchange) with load and for maintaining scheduled Interconnection frequency at sixty cycles per second (60 Hz). Regulation and Frequency Response Service is accomplished by committing on-line generation whose output is raised or lowered (predominantly through the use of automatic generating control equipment) and by other non-generation resources capable of providing this service as necessary to follow the moment-by-moment changes in load. The obligation to maintain this balance between resources and load lies with the Transmission Provider (or the Control Area operator that performs this function for the Transmission Provider). The Transmission Provider must offer VerDate Mar<15>2010 17:15 Jul 29, 2013 Jkt 229001 this service when the transmission service is used to serve load within its Control Area. The Transmission Customer must either purchase this service from the Transmission Provider or make alternative comparable arrangements to satisfy its Regulation and Frequency Response Service obligation. The Transmission Provider will take into account the speed and accuracy of regulation resources in its determination of Regulation and Frequency Response reserve requirements, including as it reviews whether a self-supplying Transmission Customer has made alternative comparable arrangements. Upon request by the self-supplying Transmission Customer, the Transmission Provider PO 00000 Frm 00037 Fmt 4701 Sfmt 4700 46213 will share with the Transmission Customer its reasoning and any related data used to make the determination of whether the Transmission Customer has made alternative comparable arrangements. The amount of and charges for Regulation and Frequency Response Service are set forth below. To the extent the Control Area operator performs this service for the Transmission Provider, charges to the Transmission Customer are to reflect only a pass-through of the costs charged to the Transmission Provider by that Control Area operator. Note: The following Appendix will not appear in the Code of Federal Regulations. BILLING CODE 6717–01–P E:\FR\FM\30JYR3.SGM 30JYR3 46214 Federal Register / Vol. 78, No. 146 / Tuesday, July 30, 2013 / Rules and Regulations Appendix C - New and Amended Form 1/lF/3Q Pages. I This Report is: I I Year/Period of Report Date of Report (1) : An Original (Mo, Da, Yr) End of Year/Qtr (2) I A Resubmission / / LIST OF SCHEDULES (Electric Utility) Enter in column (c) the terms "none", "not applicable", or "NA", as appropriate, where no information or amounts have been reported for certain pages. Omit pages where the respondents are "none", "not applicable", or "NA". Line No. 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 Title of Schedule (a) General Information Control Over Respondent Corporations Controlled by Respondent Officers Directors Information on Formula Rates Important Changes During the Year Comparative Balance Sheet Statement of Income for the Year Statement of Retained Earnings for the Year Statement of Cash Flows Notes to Financial Statements Statement of Accum Comp Income, Comp Income, and Hedging Activities Summary of Utility Plant and Accumulated Provisions for Dep, Amort and Dep Nuclear Fuel Materials Electric Plant in Service Electric Plant Leased to Others Electric Plant Held for Future Use Construction Work in Progress-Electric Accumulated Provision for Depreciation of Electric Utility Plant Investment of Subsidiary Companies Materials and Supplies Allowances Extraordinary Property Losses Unrecovered Plant and Regulatory Study Costs Transmission Service and Generation Interconnection Study Costs Other Regulatory Assets Miscellaneous Deferred Debits Accumulated Deferred Income Taxes Capital Stock Other Paid-in Capital Capital Stock Expense Long-Term Debt Reconciliation of Reported Net Income with Taxable Inc for Fed Inc Tax Taxes Accrued, Prepaid and Charged During the Year Accumulated Deferred Investment Tax Credits emcdonald on DSK67QTVN1PROD with RULES3 FERC FORM NO.1 (REV. 12-12) FERC FORM NO. 1-F (REV. 12-12) VerDate Mar<15>2010 17:15 Jul 29, 2013 Jkt 229001 PO 00000 Reference Page No. -(b) 101 102 103 104 105 106(a)(b) 108-109 110-113 114-117 118-119 120-121 122-123 122(a)(b) 200-201 202-203 204-207 213 214 216 219 224-225 227 228-229 230 230 231 232 233 234 250-251 253 254 256-257 261 262-263 266-267 Remarks (c) Page 2 Frm 00038 Fmt 4701 Sfmt 4725 E:\FR\FM\30JYR3.SGM 30JYR3 ER30JY13.006</GPH> Name of Respondent Federal Register / Vol. 78, No. 146 / Tuesday, July 30, 2013 / Rules and Regulations Name of Respondent This Report is: (1) i An Original (2) i A Resubmission Date of Report (Mo, Da, Yr) 46215 Year/Period of Report End of Year/Qtr / Enter in column the terms "none", "not applicable", or "NA", as appropriate, where no certain pages. Omit pages where the respondents are "none", "not applicable", or "NA". or amounts have been reported Remarks Title of Schedule emcdonald on DSK67QTVN1PROD with RULES3 VerDate Mar<15>2010 17:15 Jul 29, 2013 Jkt 229001 PO 00000 Frm 00039 Fmt 4701 Sfmt 4725 E:\FR\FM\30JYR3.SGM 30JYR3 ER30JY13.007</GPH> Page 3 FERC FORM NO.1 (REV. 12·12) FERC FORM NO. 1·F (REV. 12·12) 46216 Federal Register / Vol. 78, No. 146 / Tuesday, July 30, 2013 / Rules and Regulations I This Report is: I I Year/Period of Report Date of Report (1) :An Original (Mo, Da, Yr) End of Year/Qtr (2) I A Resubmission / / LIST OF SCHEDULES (Electric Utility) (Continued) Enter in column (c) the terms "none", "not applicable", or "NA", as appropriate, where no information or amounts have been reported for certain pages. Omit pages where the respondents are "none", "not applicable", or "NA". Lin e No. 68 69 70 71 72 (a) Transmission Line Statistics Pages Substations Transactions with Associated (Affiliated) Companies Footnote Data Stockholder's Reports - Check appropriate box: : Two copies will be submitted. : No annual report to stockholders is prepared. emcdonald on DSK67QTVN1PROD with RULES3 FERC FORM NO.1 (REV. 12-12) FERC FORM NO. I-F (REV. 12-12) VerDate Mar<15>2010 Reference Page No. (b) 426-427 426-427 429 450 Title of Schedule 17:15 Jul 29, 2013 Jkt 229001 PO 00000 Remarks (c) Page 4 Frm 00040 Fmt 4701 Sfmt 4725 E:\FR\FM\30JYR3.SGM 30JYR3 ER30JY13.008</GPH> Name of Respondent Federal Register / Vol. 78, No. 146 / Tuesday, July 30, 2013 / Rules and Regulations 46217 Name of Respondent This Report is: Date of Report Year/Period of Report End of (Mo" Da" Yr.) (1) D An Original (2) D A Resubmission ELECTRIC PLANT IN SERVICE (Account 101, 102, 103 and 106) 1, Report below the original cost of electric plant in service according to the prescribed accounts, 2, In addition to Account 101, Electric Plant in Service (Classified), this page and the next include Account 102, Electric Plant Purchased or Sold; Account 103, Experimental Electric Plant Unclassified; and Account 106, Completed Construction Not Classified-Electric, 3, Include in column (c) or (d), as appropriate, corrections of additions and retirements for the current or preceding year, 4, For revisions to the amount of initial asset retirement costs capitalized, included by primary plant account, increases in column (c) additions and reductions in column (e) adjustments, 5, Enclose in parentheses credit adjustments of plant accounts to indicate the negative effect of such accounts, 6, Classify Account 106 according to prescribed accounts, on an estimated basis if necessary, and include the entries in column (c), Also to be included in column (c) are entries for reversals of tentative distributions of prior year reported in column (b), Likewise, if the respondent has a significant amount of plant retirements which have not been classified to primary accounts at the end of the year, include in column (d) a tentative distribution of such retirements, on an estimated basis, with appropriate contra entry to the account for accumulated depreCiation provision, Include also in column (d) Line Accounts Balance Additions No, (a) Beginning of Year (c) (Il) emcdonald on DSK67QTVN1PROD with RULES3 I 46 1. INTANGIBLE PLANT (301) OrQanization (302) Franchises and Consents (303) Miscellaneous Intangible Plant TOTAL Intangible Plant (Enter Total of lines 2,3, and 4) 2. PRODUCTION PLANT A, Steam Production Plant (310) Land and Land Rights (311) Structures and Improvements 312 Boiler Plant Equipment 313 EnQines and EnQine-Driven Generators 314 TurboQenerator Units 315 Accessory Electric Equipment 316 Misc, Power Plant Equipment (317) Asset Retirement Costs for Steam Production TOTAL Steam Production Plant (Enter Total of lines 8 thru 15) B. Nuclear Production Plant (320) Land and Land Rights 321 Structures and Improvements 322 Reactor Plant Equipment 323 TurboQenerator Units 324 Accessory Electric Equipment 325 Misc, Power Plant Equipment 326 Asset Retirement Costs for Nuclear Production TOTAL Nuclear Production Plant (Enter Total of lines 18 thru 24) C. Hydraulic Production Plant (330) Land and Land Rights (331) Structures and Improvements 332 Reservoirs, Dams, and Waterways 333 Water Wheels, Turbines, and Generators 334 Accessory Electric Equipment 335 Miscellaneous Power Plant Equipment 336 Roads, Railroads, and Bridges (337) Asset Retirement Costs for Hydraulic Production TOTAL Hydraulic Production Plant (Enter Total of lines 27 thru 34) D. Other Production Plant (340) Land and Land Rights 341 Structures and Improvements 342 Fuel Holders, Products, and Accessories 343 Prime Movers 344 Generators 345 Accessory Electric Equipment 346 Misc, Power Plant Equipment (347) Asset Retirement Costs for Other Production I I TOTAL Other Production Plant (Enter Total of lines 37 thru 45) VerDate Mar<15>2010 17:15 Jul 29, 2013 Jkt 229001 PO 00000 Frm 00041 Fmt 4701 Sfmt 4725 E:\FR\FM\30JYR3.SGM I 30JYR3 I ER30JY13.009</GPH> 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 46218 Federal Register / Vol. 78, No. 146 / Tuesday, July 30, 2013 / Rules and Regulations 47 I TOTAL Production Plant (Enter Total of lines 16 25 35 and 46) Page 204 FERC FORM NO.1/1·F (REV. 12·121 Name of Respondent This Report is: Date of Report Year/Period of Report (Mo., Da., Yr.) End of 0 An Original (1) (2) 0 A Resubmission ELECTRIC PLANT IN SERVICE (Account 101,102, 103 and 106) (Continued) Distributions of these tentative classifications in columns (c) and (d), including the reversals of the prior years tentative account distributions of these amounts. Careful observance of the above instructions and the texts of Accounts 101 and 106 will avoid serious omissions of the reported amount of respondent's plant actually in service at end of year. 7. Show in column (f) reclassifications or transfers within utility plant accounts. Include also in column (f) the additions or reductions of primary account classifications arising from distribution of amounts initially recorded in Account 102, include in column (e) the amounts with respect to accumulated provision for depreciation, acquisition adjustments, etc., and show in column (f) only the offset to the debits or credits distributed in column (f) to primary account classifications. 8. For Account 399, state the nature and use of plant included in this account and if substantial in amount submit a supplementary statement showing subaccount classification of such plant conforming to the requirement of these pages. 9. For each amount comprising the reported balance and changes in Account 102, state the property purchased or sold, name of vendor or purchase, and date of transaction. If proposed journal entries have been filed with the Commission as required by the Uniform System of Accounts, give also date. Line Retirements Adjustments Transfers Balance at End of Year (d) (e) (f) (g) No. 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 VerDate Mar<15>2010 17:15 Jul 29, 2013 Jkt 229001 46 47 PO 00000 Frm 00042 Fmt 4701 Sfmt 4725 E:\FR\FM\30JYR3.SGM 30JYR3 I I ER30JY13.010</GPH> emcdonald on DSK67QTVN1PROD with RULES3 I I 46219 Federal Register / Vol. 78, No. 146 / Tuesday, July 30, 2013 / Rules and Regulations Pa~ e 205 This Report is: Date of Report Year/Period of Report (Mo., Da., Yr.) End of 0 An Original (1) (2) 0 A Resubmission ELECTRIC PLANT IN SERVICE (Account 101,102,103 and 106) (Continued) Accounts Balance Beginning of Year (b) (a) 3. TRANSMISSION PLANT (350) Land and Land RiQhts I I (352) Structures and Improvements (353) Station Equipment (354) Towers and Fixtures (355) Poles and Fixtures (356) Overhead Conductors and Devices (357) UnderQround Conduit (358) UnderQround Conductors and Devices (359) Roads and Trails (359.1) Asset Retirement Costs for Transmission Plant TOTAL Transmission Plant (Enter Total of lines 49 thru 59) 4. DISTRIBUTION PLANT (360) Land and Land Rights (361) Structures and Improvements (362) Station Equipment I I I I I I FERC FORM NO. 1/1-F (REV. 12-12) Name of Respondent 51 52 53 54 55 56 57 58 59 60 61 62 63 64 66 67 68 69 70 71 72 73 74 75 76 77 78 79 80 81 82 83 84 emcdonald on DSK67QTVN1PROD with RULES3 85 86 87 88 89 90 91 92 93 94 95 96 97 98 99 100 101 102 103 104 105 106 VerDate Mar<15>2010 Additions (c) (364) Poles, Towers, and Fixtures (365) Overhead Conductors and Devices (366) UnderQround Conduit (367) Underground Conductors and Devices (368) Line Transformers (369) Services (370) Meters (371) Installations on Customer Premises (372) Leased Property on Customer Premises (373) Street Lighting and Signal Systems (374) Asset Retirement Costs for Distribution Plant TOTAL Distribution Plant (Enter Total of lines 62 thru 76) 5. REGIONAL TRANSMISSION AND MARKET OPERATION PLANT (380) Land and Land Rights (381) Structures and Improvements (382) Computer Hardware (383) Computer Software (384) Communication Equipment (385) Miscellaneous ReQional Transmission and Market Operation Plant (386) Asset Retirement Costs for Regional Transmission and Market Operation Plant TOTAL Transmission and Market Operation Plant (Enter Total of lines 79 thru 85) 6. GENERAL PLANT (389) Land and Land RiQhts (390) Structures and Improvements (391) Office Furniture and Equipment (392) Transportation Equipment (393) Stores Equipment (394) Tools, Shop and Garage Equipment (395) Laboratory Equipment (396) Power Operated Equipment (397) Communication Equipment (398) Miscellaneous Equipment SUBTOTAL (Enter Total of Lines 88 thru 97) (399) Other Intangible Property (399.1) Asset Retirement Costs for General Plant TOTAL General Plant (Enter Total of Lines 98, 99 and 100) TOTAL (Accounts 101 and 106) (102) Electric Plant Purchased (See Instruction 8) (Less) (102) Electric Plant Sold (See Instruction 8) (103) Experimental Plant Unclassified TOTAL Electric Plant in Service (Enter Total of lines 102 thru 1051) 17:15 Jul 29, 2013 Jkt 229001 PO 00000 Frm 00043 Fmt 4701 Sfmt 4725 E:\FR\FM\30JYR3.SGM 30JYR3 ER30JY13.011</GPH> Line No. 48 49 46220 Federal Register / Vol. 78, No. 146 / Tuesday, July 30, 2013 / Rules and Regulations FERC FORM NO. 1/1-F (REV. 12-12) Name of Respondent Retirements (d) Page 206 This Report is: Date of Report Year/Period of Report (Mo., Da., Yr.) End of (1 ) D An Original (2) D A Resubmission ELECTRIC PLANT IN SERVICE (Account 101,102,103 and 106) (Continued) Adjustments Transfers Balance at End of Year (f) (g) (e) I I I I I I I I Line No. 48 49 51 52 53 54 55 56 57 58 59 60 61 62 63 64 66 67 68 69 70 71 72 73 74 75 76 VerDate Mar<15>2010 17:15 Jul 29, 2013 Jkt 229001 PO 00000 Frm 00044 Fmt 4701 Sfmt 4725 E:\FR\FM\30JYR3.SGM 30JYR3 ER30JY13.012</GPH> emcdonald on DSK67QTVN1PROD with RULES3 77 78 79 80 81 82 83 84 85 86 87 88 89 90 91 92 93 94 95 96 97 98 99 100 101 102 103 104 105 106 Federal Register / Vol. 78, No. 146 / Tuesday, July 30, 2013 / Rules and Regulations FERC FORM NO. 1/1·F (REV. 12·12) Name of Respondent 46221 Page 207 This Report is: (1) 0 An Original Date of Report (Mo., Da., Yr.) Year/Period of Report End of VerDate Mar<15>2010 17:15 Jul 29, 2013 Jkt 229001 PO 00000 Frm 00045 Fmt 4701 Sfmt 4725 E:\FR\FM\30JYR3.SGM 30JYR3 ER30JY13.013</GPH> emcdonald on DSK67QTVN1PROD with RULES3 Amount for Previous Year (c) 46222 Federal Register / Vol. 78, No. 146 / Tuesday, July 30, 2013 / Rules and Regulations FERC FORM NO.1 (REV. 12-12) Page 320 VerDate Mar<15>2010 17:15 Jul 29, 2013 Jkt 229001 PO 00000 Frm 00046 Fmt 4701 Sfmt 4725 E:\FR\FM\30JYR3.SGM 30JYR3 ER30JY13.014</GPH> emcdonald on DSK67QTVN1PROD with RULES3 D An Original This Report is: (1) (2) D A Resubmission Federal Register / Vol. 78, No. 146 / Tuesday, July 30, 2013 / Rules and Regulations 46223 VerDate Mar<15>2010 17:15 Jul 29, 2013 Jkt 229001 PO 00000 Frm 00047 Fmt 4701 Sfmt 4725 E:\FR\FM\30JYR3.SGM 30JYR3 ER30JY13.015</GPH> emcdonald on DSK67QTVN1PROD with RULES3 End of 46224 Federal Register / Vol. 78, No. 146 / Tuesday, July 30, 2013 / Rules and Regulations Date of Report (Mo., Da., Yr.) This Report is: (1) 0 An Original emcdonald on DSK67QTVN1PROD with RULES3 FERC FORM NO.1 (REV. 12-12) VerDate Mar<15>2010 17:15 Jul 29, 2013 Jkt 229001 Year/Period of Report End of Page 323 PO 00000 Frm 00048 Fmt 4701 Sfmt 4725 E:\FR\FM\30JYR3.SGM 30JYR3 ER30JY13.016</GPH> Name of Respondent Federal Register / Vol. 78, No. 146 / Tuesday, July 30, 2013 / Rules and Regulations 46225 End of VerDate Mar<15>2010 17:15 Jul 29, 2013 Jkt 229001 Page 324a PO 00000 Frm 00049 Fmt 4701 Sfmt 4725 E:\FR\FM\30JYR3.SGM 30JYR3 ER30JY13.017</GPH> emcdonald on DSK67QTVN1PROD with RULES3 FERC FORM 3·Q (REV 12-12) 46226 Federal Register / Vol. 78, No. 146 / Tuesday, July 30, 2013 / Rules and Regulations Name of Respondent This Report is: (1) 0 An Original Date of Report (Mo., Da., Yr.) Year/Period of Report End of o A VerDate Mar<15>2010 17:15 Jul 29, 2013 Jkt 229001 PO 00000 Frm 00050 Fmt 4701 Sfmt 4725 E:\FR\FM\30JYR3.SGM 30JYR3 ER30JY13.018</GPH> emcdonald on DSK67QTVN1PROD with RULES3 reporting 46227 Federal Register / Vol. 78, No. 146 / Tuesday, July 30, 2013 / Rules and Regulations Name of Respondent This Report Is: (1) :An Original (2) : A Resubmission Date of Report (Mo, Da, Yr) / / Year/Period of Report End of Year/Qtr PURCHASED POWER I'"''''-vu, '''s 555 and 555.1) (Including Power 1. Report all powerfJ'"!, .... "",.."" made during the year. Also report "".... """~"" of "'"....,,,....,,y (i.e., """"".... "v,," involving a balancing of debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges. 2. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller. 3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows: RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the supplier includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must be the same as, or second only to, the supplier's service to its own ultimate consumers. LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract defined as the earliest date that either buyer or seller can unilaterally get out of the contract. IF - for intermediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less than five years. SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is one year or less. LU - for long-term service from a deSignated generating unit. "Long-term" means five years or longer. The availability and reliability of service, aside from transmission constraints, must match the availability and reliability of the designated unit. IU - for intermediate-term service from a deSignated generating unit. The same as LU service expect that "intermediate-term" means longer than one year but less than five years. EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc. and any settlements for imbalanced exchanges. OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature of the service in a footnote for each adjustment. Line No. Name of ~v, ",",U"I or Public Authority (Footnote Affiliations) (a) i Classification (b) FERC Rate Schedule or Tariff Number (c) MO~~~~a~~ing Demand (MW) (d) Actual Demand (MW) Average Average Monthly NCP MonthlyCP Demand Demand Total (f) (e) 1 2 3 4 5 MegaWatt Hours ~ 6 7 8 9 10 11 12 13 14 VerDate Mar<15>2010 17:15 Jul 29, 2013 Jkt 229001 PO 00000 Page 326 Frm 00051 Fmt 4701 Sfmt 4725 E:\FR\FM\30JYR3.SGM 30JYR3 ER30JY13.019</GPH> emcdonald on DSK67QTVN1PROD with RULES3 Total FERC FORM NO.1 (REV. 12-12) FERC FORM NO.1-F (REV. 12-12) 46228 Federal Register / Vol. 78, No. 146 / Tuesday, July 30, 2013 / Rules and Regulations Report End of Year/Qtr PURCHASED 1) (Continued) AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting years. Provide an explanation in a footnote for each adjustment. 4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as identified in column (b), is provided. 5. For requirements RQ purchases and any type of service involving demand charges imposed on a monthly (or longer) basis, enter the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average monthly coincident peak (CP) demand in column (t). For all other types of service, enter NA in columns (d), (e) and (t). Monthly NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (t) must be in megawatts. Footnote any demand not stated on a megawatt basis and explain. 6. Report in column (g) the megawatt hours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatt hours of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange. 7. Report demand charges in column (j), energy charges in column (k), and the total of any other types of charges, including out-of-period adjustments, in column (I). Explain in a footnote all components of the amount shown in column (I). Report in column (m) the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (I) include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the agreement, provide an explanatory footnote. 8. The data in column (g) through (n) totals to the last line of the schedule. The total amount in column (g) must be reported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Purchases for Energy Storage on Page 401, line 11. The total amount in column (i) must be reported as Exchange Received on Page 401, line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13. 9. Footnote entries as required and provide explanations following all required data. Line No. 7 8 9 11 12 13 VerDate Mar<15>2010 17:15 Jul 29, 2013 Jkt 229001 PO 00000 Page 327 Frm 00052 Fmt 4701 Sfmt 4725 E:\FR\FM\30JYR3.SGM 30JYR3 ER30JY13.020</GPH> emcdonald on DSK67QTVN1PROD with RULES3 FERC FORM NO.1 (REV. 12-12) FERC FORM NO. I-F (REV. 12-12) Federal Register / Vol. 78, No. 146 / Tuesday, July 30, 2013 / Rules and Regulations Name of Respondent This Report is: (1) 0 An Original Date of Report (Mo., Da., Yr.) 46229 Year/Period of Report End of (2) 0 A Resubmission AMOUNTS INCLUDED IN ISO/RTO SETTLEMENT STATEMENTS 1. The respondent shall report below the details called for conceming amounts it recorded in Account 555, Purchase Power, Account 555.1, Power Purchased for Storage Operations and Account 447, Sales for Resale, for items shown on ISO/RTO Settlement Statements. Description of Item(s) Line No. 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 (a) Energy Net Purchases (Account 555) Balance at End of Quarter 3 (d) I Net Sales (Account 447) Transmission Rights Ancillary Services Other Items (list separately) Balance at End of Year (e) I I I I I I I I I I I Total FERC FORM 1/1-F/3-Q (REV 12-12) emcdonald on DSK67QTVN1PROD with RULES3 Balance at End of Quarter 2 (c) VerDate Mar<15>2010 17:15 Jul 29, 2013 Jkt 229001 PO 00000 Page 397 Frm 00053 Fmt 4701 Sfmt 4725 E:\FR\FM\30JYR3.SGM 30JYR3 ER30JY13.021</GPH> 1 2 Balance at End of Quarter 1 (b) 46230 Federal Register / Vol. 78, No. 146 / Tuesday, July 30, 2013 / Rules and Regulations Name of Respondent Th is Report is: (1) 0 An Original Date of Report (Mo., Da., Yr.) Report below and wheeled Line No. Year/Period of Report End of Item (a) 5 Hydro-Conventional 6 Hydro=Pumped Storage VerDate Mar<15>2010 17:15 Jul 29, 2013 Jkt 229001 PO 00000 Frm 00054 Fmt 4701 Sfmt 4725 E:\FR\FM\30JYR3.SGM 30JYR3 ER30JY13.022</GPH> emcdonald on DSK67QTVN1PROD with RULES3 Page401a Federal Register / Vol. 78, No. 146 / Tuesday, July 30, 2013 / Rules and Regulations Name of Respondent Date of Report (Mo., Da., Yr.) 46231 Year/Period of Report End of 1. Large plants and pumped storage plants of 10,000 KWor more of installed capacity (name plate ratings) 2. If any plant is leased, operating under a license from the Federal Energy Regulatory Commission, or operated as a joint facility, indicate such facts in a footnote. Give project number. 3. If net peak demand for 60 minutes is not available, give that which is available, specifying period. 4. If a group of employees attends more than one generating plant, report on line 8 the approximate average number of employees assignable to each plant. 5. The items under Cost of Plant represent accounts or combinations of accounts prescribed by the Uniform System of Accounts. Production Expenses do not include Purchased Power System Control and Load Dispatching, and Other Expenses classified as "Other Power Supply Item FERC Licensed Project No. Plant Name: emcdonald on DSK67QTVN1PROD with RULES3 FERC FORM NO.1I1-F (REV. 12-12) VerDate Mar<15>2010 17:15 Jul 29, 2013 Jkt 229001 Page 408 PO 00000 Frm 00055 Fmt 4701 Sfmt 4725 E:\FR\FM\30JYR3.SGM 30JYR3 ER30JY13.023</GPH> Line No. 46232 Federal Register / Vol. 78, No. 146 / Tuesday, July 30, 2013 / Rules and Regulations Name of w~t-'v"yv" This Report is: (1 ) 0 An Original Date o~ Re~.o~ (Mo., Da., Yr.) va" v, ivy of Report End of (2) 0 A Resubmission PUMPED STORAGE GENERATING PLANT STATISTICS (Large Plants) (Continued) 6. Pum~ing e~~rg'Y3~L~~: 10) is that energy measured as i.n~ut.to the plant for:~~f.i~h~~rfh~:es. 7. I on Line the cost of energy used in pumping into the storage reservoir. item cannot be accurately computed leave Lines 36, 37 and 38 blank and describe at the bottom of the schedule the company's principal sources of pumping power, the estimated amounts of energy from each station or other source that individually provides more than 10 percent of the total energy used for pumping, and production expenses per net MWH as reported herein for each source described. Group together stations and other resources which individually provide less than 10 percent of total pumping energy. If contracts are made with others to purchase power for pumping, give the supplier contract number and date of contract. FERC Licensed Project No. FERC Licensed Project No. FERC Licensed Project No. Line Plant Name: Plant Name: Plant Name: No. (c) (d) (e) 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 1Z.. VerDate Mar<15>2010 17:15 Jul 29, 2013 Jkt 229001 Page 408 PO 00000 Frm 00056 Fmt 4701 Sfmt 4725 E:\FR\FM\30JYR3.SGM 30JYR3 ER30JY13.024</GPH> emcdonald on DSK67QTVN1PROD with RULES3 FERC FORM NO.1/1-F (REV. 12-12) Federal Register / Vol. 78, No. 146 / Tuesday, July 30, 2013 / Rules and Regulations Name of Respondent This Report is: Date of Report (Mo., Da., Yr.) 0 An Original (1) (2) 0 A Resubmission ENERGY STORAGE OPERATIONS (Large Plants) 46233 Year/Period of Report End of 1. Large Plants are plants of 10,000 KW or more. 2. In columns (a) (b) and (c) report the name of the energy storage project, functional classification (Production, Transmission, Distribution), and location. 3. In column (d), report Megawatt hours (MWH) purchased, generated, or received in exchange transactions for storage. 4. In columns (e), (f) and (g) report MWHs delivered to the grid to support production, transmission and distribution. The amount reported in column (d) should include MWHs delivered/provided to a generator's own load requirements or used for the provision of ancillary services. 5. In columns (h), (i), and 0) report MWHs lost during conversion, storage and discharge of energy. 6. In column (k) report the MWHs sold. 7. In column (I), report revenues from energy storage operations. In a footnote, disclose the revenue accounts and revenue amounts related to the income generating activity. 8. In column (m), report the cost of power purchased for storage operations and reported in Account 555.1, Power Purchased for Storage Operations. If power was purchased from an affiliated seller specify how the cost of the power was determined. In columns (n) and (0), report fuel costs for storage operations associated with self-generated power included in Account 501 and other costs associated with self-generated power. 9. In columns (q), (r) and (s) report the total project plant costs including but not exclusive of land and land rights, structures and improvements, energy storage equipment, turbines, compressors, generators, switching and conversion equipment, lines and equipment whose primary purpose is to integrate or tie energy storage assets into the power grid, and any other costs associated with the energy storage project included in the property accounts listed. Name of the Energy Storage Project (a) Functional Classification (b) emcdonald on DSK67QTVN1PROD with RULES3 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 TOTAL FERC FORM NO. 1/1-F (NEW 12-12) VerDate Mar<15>2010 17:15 Jul 29, 2013 Jkt 229001 Location of the Project (c) MWHs (d) Page 414 PO 00000 Frm 00057 Fmt 4701 Sfmt 4725 E:\FR\FM\30JYR3.SGM 30JYR3 ER30JY13.025</GPH> Line No. 46234 Federal Register / Vol. 78, No. 146 / Tuesday, July 30, 2013 / Rules and Regulations Name of Respondent This Report is: Date of Report (Mo., Da., Yr.) An Original (1) 0 (2) 0 A Resubmission ENERGY STORAGE OPERATIONS (Large Plants) (Continued) MWHs delivered to the grid to support Line No. Production (e) Transmission (f) Distribution (g) Year/Period of Report End of MWHs Lost During Conversion, Storage and Discharge of EnerQY Production Transmission Distribution (h) (i) Gl MWHs Sold (k) Revenues from Energy Storage Operations (I) 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 VerDate Mar<15>2010 17:15 Jul 29, 2013 Jkt 229001 Page 415 PO 00000 Frm 00058 Fmt 4701 Sfmt 4725 E:\FR\FM\30JYR3.SGM 30JYR3 ER30JY13.026</GPH> emcdonald on DSK67QTVN1PROD with RULES3 FERC FORM NO.1I1-F (NEW 12-12) Federal Register / Vol. 78, No. 146 / Tuesday, July 30, 2013 / Rules and Regulations Name of Respondent Line No. This Report is: Date of Report (Mo., Da., Yr.) (1 ) D An Original (2) D A Resubmission ENERGY STORAGE OPERATIONS (Large Plants) (Continued) Power Purchased for Storage Operations (555.1) (Dollars) (m) Fuel Costs from associated fuel accounts for Storage Operations Associated with SelfGenerated Power (Dollars) Other Costs Associated with SelfGenerated Power (Dollars) Project Costs included in (p) 46235 Year/Period of Report End of Production (Dollars) (q) Transmission (Dollars) (r) Distribution (Dollars) (s) (0) (n) 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 Account Account Account Account Other 101 103 106 107 17 VerDate Mar<15>2010 17:15 Jul 29, 2013 Jkt 229001 Total Page 416 PO 00000 Frm 00059 Fmt 4701 Sfmt 4725 E:\FR\FM\30JYR3.SGM 30JYR3 ER30JY13.027</GPH> emcdonald on DSK67QTVN1PROD with RULES3 18 19 20 21 22 23 24 25 26 27 28 29 30 FERC FORM NO.1I1-F (NEW 12-12) 46236 Federal Register / Vol. 78, No. 146 / Tuesday, July 30, 2013 / Rules and Regulations Name of Respondent Date of Report This Report is: (Mo., Da., Yr.) 0 An Original (1) (2) 0 A Resubmission ENERGY STORAGE OPERATIONS (Small Plants) Year/Period of Report End of 1. Small Plants are plants less than 10,000~. 2 In columns (a), (b) and (c) report the name of the energy storage project, functional classification (Production, Transmission, Distribution), and location. 3. In column (d), report project plant cost including but not exclusive of land and land rights, structures and improvements, energy storage equipment and any other costs associated with the energy storage project. 4. In column (e), report operation expenses excluding fuel, (f), maintenance expenses, (g) fuel costs for storage operations and (h) cost of power purchased for storage operations and reported in Account 555.1, Power Purchased for Storage Operations. If power was purchased from an affiliated seller specify how the cost of the power was determined. 5. If any other expenses, report in column·(i) and footnote the nature of the item(s). Name of the Energy Storage Project (a) Functional Classification (b) emcdonald on DSK67QTVN1PROD with RULES3 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 TOTAL FERC FORM NO.1/1-F (NEW 12-12) VerDate Mar<15>2010 17:15 Jul 29, 2013 Jkt 229001 Location of the Project (c) Project Cost (d) Page 419 PO 00000 Frm 00060 Fmt 4701 Sfmt 4725 E:\FR\FM\30JYR3.SGM 30JYR3 ER30JY13.028</GPH> Line No. Federal Register / Vol. 78, No. 146 / Tuesday, July 30, 2013 / Rules and Regulations Name of Respondent This Report is: Date of Report (Mo., Da., Yr.) (1) 0 An Original (2) 0 A Resubmission ENERGY STORAGE OPERATIONS (Small Plants)(Continued) 46237 Year/Period of Report End of Plant Operating Expenses Line No. Operations (Excluding Fuel used in Storage Operations) (e) Cost of fuel used in storage operations (g) Maintenance (f) Account No. 555.1, Power Purchased for Storage Operations (h) Other Expenses (i) 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 FERC FORM NO. 1I1-F (NEW 12-12) Page 420 [FR Doc. 2013–17746 Filed 7–29–13; 8:45 am] VerDate Mar<15>2010 17:15 Jul 29, 2013 Jkt 229001 PO 00000 Frm 00061 Fmt 4701 Sfmt 9990 E:\FR\FM\30JYR3.SGM 30JYR3 ER30JY13.029</GPH> emcdonald on DSK67QTVN1PROD with RULES3 BILLING CODE 6717–01–C

Agencies

[Federal Register Volume 78, Number 146 (Tuesday, July 30, 2013)]
[Rules and Regulations]
[Pages 46177-46237]
From the Federal Register Online via the Government Printing Office [www.gpo.gov]
[FR Doc No: 2013-17746]

[[Page 46177]]

Vol. 78

Tuesday,

No. 146

July 30, 2013

Part V

Department of Energy

-----------------------------------------------------------------------

Federal Energy Regulatory Commission

-----------------------------------------------------------------------

18 CFR Parts 35 and 101

Third-Party Provision of Ancillary Services; Accounting and Financial
Reporting for New Electric Storage Technologies; Rules

Federal Register / Vol. 78, No. 146 / Tuesday, July 30, 2013 / Rules
and Regulations

[[Page 46178]]

-----------------------------------------------------------------------

DEPARTMENT OF ENERGY

Federal Energy Regulatory Commission

18 CFR Parts 35 and 101

[Docket Nos. RM11-24-000 and AD10-13-000; Order No. 784]

Third-Party Provision of Ancillary Services; Accounting and
Financial Reporting for New Electric Storage Technologies

AGENCY: Federal Energy Regulatory Commission, DOE.

ACTION: Final rule.

-----------------------------------------------------------------------

SUMMARY: The Federal Energy Regulatory Commission (Commission) is
revising its regulations to foster competition and transparency in
ancillary services markets. The Commission is revising certain aspects
of its current market-based rate regulations, ancillary services
requirements under the pro forma open-access transmission tariff
(OATT), and accounting and reporting requirements. Specifically, the
Commission is revising its regulations to reflect reforms to its Avista
policy governing the sale of ancillary services at market-based rates
to public utility transmission providers. The Commission is also
requiring each public utility transmission provider to add to its OATT
Schedule 3 a statement that it will take into account the speed and
accuracy of regulation resources in its determination of reserve
requirements for Regulation and Frequency Response service, including
as it reviews whether a self-supplying customer has made ``alternative
comparable arrangements'' as required by the Schedule. The final rule
also requires each public utility transmission provider to post certain
Area Control Error data as described in the final rule. Finally, the
Commission is revising the accounting and reporting requirements under
its Uniform System of Accounts for public utilities and licensees and
its forms, statements, and reports, contained in FERC Form No. 1,
Annual Report of Major Electric Utilities, Licensees and Others, FERC
Form No. 1-F, Annual Report for Nonmajor Public Utilities and
Licensees, and FERC Form No. 3-Q, Quarterly Financial Report of
Electric Utilities, Licensees, and Natural Gas Companies, to better
account for and report transactions associated with the use of energy
storage devices in public utility operations.

DATES: This rule is effective November 27, 2013.

FOR FURTHER INFORMATION CONTACT:
Rahim Amerkhail (Technical Information), Federal Energy Regulatory
Commission, Office of Energy Policy and Innovation, 888 First Street
NE., Washington, DC 20426, (202) 502-8266.
Christopher Handy (Accounting Information), Federal Energy Regulatory
Commission, Office of Enforcement, 888 First Street NE., Washington, DC
20426, (202) 502-6496.
Lina Naik (Legal Information), Federal Energy Regulatory Commission,
Office of the General Counsel, 888 First Street NE., Washington, DC
20426, (202) 502-8882.
Eric Winterbauer (Legal Information), Federal Energy Regulatory
Commission, Office of the General Counsel, 888 First Street NE.,
Washington, DC 20426, (202) 502-8329.

SUPPLEMENTARY INFORMATION:
Before Commissioners: Jon Wellinghoff, Chairman; Philip D. Moeller,
John R. Norris, Cheryl A. LaFleur, and Tony Clark.

Order No. 784

Final Rule

Issued July 18, 2013.

Table of Contents

Paragraph
No.

I. Background............................................... 6
II. Discussion.............................................. 12
A. The Avista Policy.................................... 12
1. Use of Market Power Analyses..................... 17
a. Reliance on Existing Indicative Screens...... 20
i. Application to Imbalance Ancillary 22
Services...................................
ii. Application to Other Ancillary Services. 43
b. Optional Market Power Screen................. 62
2. Alternative Mitigation........................... 75
a. Use of Price Caps............................ 76
i. Single OATT Rate Cap Option.............. 77
ii. Regional OATT Rate Cap Option........... 86
b. Competitive Solicitations.................... 95
B. Resource Speed and Accuracy in Determination of 102
Regulation and Frequency Response Reserve Requirements.
C. Accounting and Reporting for Energy Storage 122
Operations.............................................
D. Other Issues......................................... 188
III. Summary of Compliance and Implementation............... 201
IV. Information Collection Statement........................ 207
V. Environmental Analysis................................... 208
VI. Regulatory Flexibility Act.............................. 209
VII. Document Availability.................................. 210

1. The Federal Energy Regulatory Commission (Commission) is
revising its regulations to enhance competition and transparency in
ancillary services markets. The Commission is revising certain aspects
of its current market-based rate regulations, ancillary services
requirements under the pro forma open-access transmission tariff
(OATT), and accounting and reporting requirements. Specifically, the
Commission is revising Part 35 of its regulations to reflect reforms to
its Avista Corp.\1\ policy governing the sale of ancillary services at
market-based rates to public utility transmission providers. The
Commission is also requiring each public utility transmission provider
to add to its OATT Schedule 3 a statement that it will take into
account the speed and accuracy of regulation resources in its
determination of reserve requirements for Regulation and Frequency
Response service, including as it reviews whether a self-supplying
customer has made ``alternative comparable arrangements'' as required

[[Page 46179]]

by the Schedule. Each public utility transmission provider is also
required to post certain Area Control Error data on the open access
same-time information system (OASIS). Finally, the Commission is
revising the accounting and reporting requirements under its Uniform
System of Accounts for public utilities and licensees (USofA) \2\ and
its forms, statements, and reports, contained in FERC Form No. 1 (Form
No. 1), Annual Report of Major Electric Utilities, Licensees and
Others,\3\ FERC Form No. 1-F (Form No. 1-F), Annual Report for Nonmajor
Public Utilities and Licensees,\4\ and FERC Form No. 3-Q (Form No. 3-
Q), Quarterly Financial Report of Electric Utilities, Licensees, and
Natural Gas Companies,\5\ to better account for and report transactions
associated with the use of energy storage devices in public utility
operations.
---------------------------------------------------------------------------

\1\ See 87 FERC ] 61,223 (Avista), order on reh'g, 89 FERC ]
61,136 (1999).
\2\ Uniform System of Accounts Prescribed for Public Utilities
and Licensees Subject to the Provisions of the Federal Power Act, 18
CFR Part 101 (2012).
\3\ 18 CFR 141.1 (2012).
\4\ 18 CFR 141.2 (2012).
\5\ 18 CFR 141.400 (2012).
---------------------------------------------------------------------------

2. First, the Commission reforms the Avista policy governing sales
of certain ancillary services to a public utility purchasing the
ancillary service to satisfy its own OATT requirements to offer
ancillary services to its own customers. As noted in the Notice of
Proposed Rulemaking,\6\ there is a growing need for ancillary services
to support grid functions in the face of potential changes in the
portfolio of generation resources and a growing interest of
transmission providers to have flexibility in meeting ancillary
services needs.\7\ There is also interest in third-party provision of
ancillary services and that interest may be unnecessarily frustrated by
the Avista policy. Comments to the NOPR's proposal to reconsider the
Avista restrictions generally supported these concepts. As such, and as
discussed further below, we conclude that elements of our existing
market-based rate regulations can be modified in a manner that
continues to limit the exercise of market power, while also enhancing
the ability of third parties to compete for the sale of certain
ancillary services.
---------------------------------------------------------------------------

\6\ Third-Party Provision of Ancillary Services; Accounting and
Financial Reporting for New Electric Storage Technologies, Notice of
Proposed Rulemaking, FERC Stats. & Regs. ] 32,690 (2012) (NOPR).
\7\ Integration of Variable Energy Resources, Order No. 764,
FERC Stats. & Regs. ] 32,331, order on reh'g, Order No. 764-A, 141
FERC ] 61,232 (2012); and Demand Response Compensation in Organized
Wholesale Energy Markets, Order No. 745, FERC Stats. & Regs. ]
31,322, order on reh'g, Order No. 745-A, 137 FERC ] 61,215 (2011).
---------------------------------------------------------------------------

3. Second, we adopt reforms to provide greater transparency with
regard to reserve requirements for Regulation and Frequency Response.
Under the requirements of the pro forma OATT, transmission customers
may either purchase Regulation and Frequency Response service at cost-
based rates from the public utility transmission provider pursuant to
its OATT or self-supply the service, including through purchases from
third-parties.\8\ With regard to the notion of self-supply, the pro
forma OATT Schedule 3 merely states that the transmission customer must
make alternative comparable arrangements to satisfy is Regulation and
Frequency Response Service obligation. In particular, Schedule 3
provides no discussion of the meaning of the term ``comparable'' as it
relates to reliance on resources with dispatch speed and accuracy
characteristics that may differ from those used by the public utility
transmission provider. Because the system must be operated reliably at
all times, the customer may not decline the transmission provider's
offer of ancillary services unless it demonstrates that it has acquired
comparable services from another source.\9\ In order to clarify the
role of resource speed and accuracy in the determination of alternative
comparable arrangements, in this Final Rule the Commission requires
each public utility transmission provider to add to its OATT Schedule 3
a statement that it will take into account the speed and accuracy of
regulation resources in its determination of reserve requirements for
Regulation and Frequency Response service, including as it reviews
whether a self-supplying customer has made ``alternative comparable
arrangements'' as required by the Schedule. This statement will also
acknowledge that, upon request by the self-supplying customer, the
public utility transmission provider will share with the customer its
reasoning and any related data used to make the determination of
whether the customer has made ``alternative comparable arrangements.''
To aid the transmission customer's ability to make an ``apples-to-
apples'' comparison of regulation resources, the final rule also
requires each public utility transmission provider to post on OASIS
historical one-minute and ten-minute Area Control Error data as
described in the final rule for the most recent calendar year, and
update this posting once per year.
---------------------------------------------------------------------------

\8\ See, e.g., Promoting Wholesale Competition Through Open
Access Non-Discriminatory Transmission Services by Public Utilities;
Recovery of Stranded Costs by Public Utilities and Transmitting
Utilities, Order No. 888, FERC Stats. & Regs. ] 31,036, at 31,716
(1996), order on reh'g, Order No. 888-A, FERC Stats. & Regs. ]
31,048, order on reh'g, Order No. 888-B, 81 FERC ] 61,248 (1997),
order on reh'g, Order No. 888-C, 82 FERC ] 61,046 (1998), aff'd in
relevant part sub nom. Transmission Access Policy Study Group v.
FERC, 225 F.3d 667 (D.C. Cir. 2000), aff'd sub nom. New York v.
FERC, 535 U.S. 1 (2002); pro forma OATT, Original Sheet Nos. 20-21
and Schedule 3, Original Sheet No. 113.
\9\ Order No. 888, FERC Stats. & Regs. ] 31,036 at 31,716.
---------------------------------------------------------------------------

4. With this information, a transmission customer will be in a
position to demonstrate to the public utility transmission provider
that the resource(s) it selects for self-supply are comparable to those
of the public utility transmission provider. As such, these reforms are
necessary to address the potential for undue discrimination against
transmission customers choosing to self-supply Regulation and Frequency
Response, including through purchases from third-parties. Acknowledging
the speed and accuracy of the resources used to provide this service
will help to ensure that self-supply requirements of the public utility
transmission provider do not unduly discriminate by requiring customers
to procure a different amount of regulation reserves than the
particular speed and accuracy characteristics of the resources in
question justify (i.e., to be comparable, a customer self-supply
arrangement that relies on slower, less accurate resources than those
of the public utility transmission provider should probably involve a
larger reserve requirement than would a purchase from the transmission
provider, and vice versa). Moreover, as the Commission has previously
stated, because most generation-based ancillary services can be
provided by many of the generators connected to the transmission
system, some customers may be able to provide or procure such services
more economically than the transmission provider can.\10\
---------------------------------------------------------------------------

\10\ Id. at 31,718. We note that customers could conceivably
procure such services more economically either by paying much less
per unit for a larger amount of slower, less accurate resources, or
by paying somewhat more per unit for a smaller amount of faster,
more accurate resources.
---------------------------------------------------------------------------

5. Finally, we adopt reforms to our accounting and reporting
regulations to add new electric plant and operation and maintenance
(O&M) expense accounts for energy storage devices. These reforms are
necessary to accommodate the increasing availability of these new
resources for use in public utility operations. These reforms are also
necessary to ensure that the activities and costs of new energy

[[Page 46180]]

storage operations are sufficiently transparent to allow effective
oversight.

Background

6. The Commission has taken numerous steps over the last several
decades to foster the development of competitive wholesale energy
markets by ensuring non-discriminatory access and comparable treatment
of resources in jurisdictional wholesale markets.\11\ With regard to
ancillary services, the Commission in Order No. 888 delineated two
categories of ancillary services: Those that the transmission provider
is required to provide to all of its basic transmission customers \12\
and those that the transmission provider is only required to offer to
provide to transmission customers serving load in the transmission
provider's control area.\13\ With respect to the second category the
Commission reasoned that the transmission provider is not always
uniquely qualified to provide the services and customers may be able to
more cost-effectively self-supply them or procure them from other
entities. The Commission contemplated that third parties (i.e., parties
other than a transmission provider supplying ancillary services
pursuant to its OATT obligation) could provide ancillary services on
other than a cost-of-service basis if such pricing was supported, on a
case-by-case basis, by analyses that demonstrated that the seller lacks
market power in the relevant product market.\14\ Later, in Ocean Vista
Power Generation, L.L.C.,\15\ the Commission provided guidance
regarding such analyses, explaining that as a general matter a study of
ancillary services markets should address the nature and
characteristics of each ancillary service, as well as the nature and
characteristics of generation capable of supplying each service, and
that the study should develop market shares for each service.
---------------------------------------------------------------------------

\11\ See, e.g., Order No. 888, FERC Stats. & Regs. ] 31,036, at
31,781; Market-Based Rates for Wholesale Sales of Electric Energy,
Capacity and Ancillary Services by Public Utilities, Order No. 697,
FERC Stats. & Regs. ] 31,252, clarified, 121 FERC ] 61,260 (2007),
order on reh'g, Order No. 697-A, FERC Stats. & Regs. ] 31,268,
clarified, 124 FERC ] 61,055, order on reh'g, Order No. 697-B, FERC
Stats. & Regs. ] 31,285 (2008), order on reh'g, Order No. 697-C,
FERC Stats. & Regs. ] 31,291 (2009), order on reh'g, Order No. 697-
D, FERC Stats. & Regs. ] 31,305 (2010), aff'd sub nom. Montana
Consumer Counsel v. FERC, 659 F.3d 910 (9th Cir. 2011), cert. denied
sub nom. Pub. Citizen, Inc. v. FERC, 133 S. Ct. 26 (2012);
Preventing Undue Discrimination and Preference in Transmission
Service, Order No. 890, FERC Stats. & Regs. ] 31,241, order on
reh'g, Order No. 890-A, FERC Stats. & Regs. ] 31,261 (2007), order
on reh'g, Order No. 890-B, 123 FERC ] 61,299 (2008), order on reh'g,
Order No. 890-C, 126 FERC ] 61,228 (2009), order on reh'g, Order No.
890-D, 129 FERC ] 61,126 (2009); Wholesale Competition in Regions
with Organized Electric Markets, Order No. 719, FERC Stats. & Regs.
] 31,281 (2008), order on reh'g, Order No. 719-A, FERC Stats. &
Regs. ] 31,292 (2009), order on reh'g, Order No. 719-B, 129 FERC ]
61,252 (2009).
\12\ The first category consists of Scheduling, System Control
and Dispatch service and Reactive Supply and Voltage Control from
Generation Sources service.
\13\ The second category consists of Regulation and Frequency
Response service, Energy Imbalance service, Operating Reserve-
Spinning service, and Operating Reserve-Supplemental service. Order
No. 890 later added an additional OATT ancillary service to this
category: Generator Imbalance service. See Order No. 890, FERC
Stats. & Regs. ] 31,241 at P 85.
\14\ Order No. 888, FERC Stats. & Regs. ] 31,036 at 31,720-21.
\15\ 82 FERC ] 61,114, at 61,406-07 (1998) (Ocean Vista).
---------------------------------------------------------------------------

7. The Commission subsequently acknowledged in Avista \16\ that
data limitations can impair the ability of sellers to perform a market
power study for ancillary services consistent with the requirements of
Ocean Vista. The Commission therefore adopted a policy allowing third-
party ancillary service providers that could not perform a market power
study to sell certain ancillary services at market-based rates with
certain restrictions.\17\ In so doing, the Commission reasoned that the
backstop of cost-based ancillary services from transmission providers,
in effect, limits the price at which customers are willing to buy
ancillary services, thus ensuring that the third-party sellers' rates
would remain just and reasonable even without a showing of lack of
market power. However, the Commission found that this backstop failed
to provide adequate mitigation of potential third-party market power in
three situations: (1) Sales to a regional transmission organization
(RTO) or an independent system operator (ISO), which has no ability to
self-supply ancillary services but instead depends on third parties;
\18\ (2) to address affiliate abuse concerns, sales to a traditional,
franchised public utility affiliated with the third-party supplier, or
sales where the underlying transmission service is on the system of the
public utility affiliated with the third-party supplier; and (3) sales
to a public utility that is purchasing ancillary services to satisfy
its own OATT requirements to offer ancillary services to its own
customers.\19\ Therefore, the Commission's Avista policy has allowed
third-party suppliers to sell certain ancillary services at market-
based rates without showing a lack of market power, except under these
three circumstances.
---------------------------------------------------------------------------

\16\ Avista, 87 FERC at 61,882.
\17\ These ancillary services included: Regulation and Frequency
Response, Energy Imbalance, Operating Reserve-Spinning, and
Operating Reserve-Supplemental. The Commission did not extend this
Avista policy to Reactive Supply and Voltage Control from Generation
Sources service, which means that third parties wishing to sell this
ancillary service at market-based rates would remain subject to the
pre-Avista market power screen requirement. The Commission also did
not extend the Avista policy to Scheduling, System Control and
Dispatch service. However, because only balancing area operators can
provide this ancillary service, it does not lend itself to
competitive supply.
\18\ Subsequently, as the Commission recognized in Order No.
697, most RTOs and ISOs developed formal ancillary service markets,
thus rendering this component of the Avista policy largely
superfluous. See Order No. 697, FERC Stats. & Regs. ] 31,252 at
n.1194 and P 1069.
\19\ Avista, 87 FERC ] 61,223 at n.12.
---------------------------------------------------------------------------

8. In its ongoing effort to enhance competitive markets as a means
to ensure just and reasonable rates, including those for ancillary
services, the Commission has continued to evaluate its Avista policy,
including, with particular regard to this proceeding, the restriction
on the sale of ancillary services by third-parties to a public utility
that is purchasing ancillary services to satisfy its own OATT
requirements to offer ancillary services to its own customers. The
Commission's concern has been to ensure that the cost-based OATT
ancillary service rates of public utilities remain a viable backstop or
alternative that transmission customers can rely upon instead of the
market-based sales from third parties who have not been shown to lack
market power. The Commission has reasoned that, if such third-party
sellers were permitted to sell to public utilities seeking to meet
their OATT ancillary service obligations, the public utility's ability
to seek recovery of such purchase costs in OATT rates might lead to
increases in those OATT ancillary service rates that may reflect the
exercise of market power thus reducing the rates' ability to serve as
an effective alternative to purchases from a third-party seller unable
to show lack of market power. This would undermine the effectiveness of
the mitigation measure that the Commission relied upon in Avista to
relax the requirement for a market power analysis.\20\
---------------------------------------------------------------------------

\20\ See Avista Rehearing Order, 89 FERC at 61,391-92 (stating
that the Commission is ``able to grant blanket authority for
flexible pricing only because the price charged by the third-party
supplier is disciplined by the obligation of the transmission
provider to offer these services under cost-based rates. This
discipline would be thwarted if the transmission provider could
substitute purchases under non-cost-based rates for its mandatory
service obligation.'').
---------------------------------------------------------------------------

9. However, as the record in this proceeding demonstrates, the
restriction on sales of ancillary services at market-based rates to a
public utility for purposes of satisfying its OATT requirements has
proven to be an

[[Page 46181]]

unreasonable barrier to entry, unnecessarily restricting access to
potential suppliers. In the NOPR, the Commission proposed to address
this problem by reforming the Avista restrictions, both by modifying
the showing an entity must make to establish that it lacks market power
and by establishing market power mitigation options in the absence of
such a showing.
10. Building off the Commission's action in Order No. 755, which
found that accounting for a given resource's speed and accuracy can
help ensure just and reasonable rates and prevent against undue
discrimination, in the NOPR, the Commission also proposed to require
each public utility transmission provider to include provisions in its
OATT explaining how it will determine regulation service reserve
requirements for transmission customers, including those that choose to
self-supply regulation service, in a manner that takes into account the
speed and accuracy of resources used.
11. Finally, the Commission proposed to modify its accounting
regulations to increase transparency for energy storage facilities.
While the Commission's accounting and reporting requirements associated
with the USofA do not dictate the ratemaking decisions of this
Commission or State Commissions, these accounting and reporting
requirements nevertheless support the rate oversight needs of both this
Commission and State Commissions. This information is important in
developing and monitoring rates, making policy decisions, compliance
and enforcement initiatives, and informing the Commission and the
public about the activities of entities that are subject to these
accounting and reporting requirements.\21\
---------------------------------------------------------------------------

\21\ Applicants for market-based rate authority that do not sell
under cost-based rates frequently seek and typically are granted
waiver of many or all of these requirements.
---------------------------------------------------------------------------

Discussion

The Avista Policy

12. As noted above, the Commission's Avista policy authorizes the
sale of certain ancillary services at market-based rates without
showing a lack of market power except under specified circumstances. As
relevant here, a third-party may not sell ancillary services at market-
based rates to a public utility that is purchasing ancillary services
to satisfy its own OATT requirements to offer ancillary services to its
own customers. In order to overcome this restriction, a potential
seller must provide a market power study demonstrating a lack of market
power for the particular ancillary service in the particular geographic
market. Based on the record before us, the Commission adopts a number
of the reforms to the ancillary services pricing policy proposed in the
NOPR and in some instances adopts a number of modifications to those
reforms based on the comments received in response to the NOPR.
13. Specifically, this Final Rule allows a resource with market-
based rate authority for sales of energy and capacity to sell imbalance
services at market-based rates to a public utility transmission
provider in the same balancing authority area, or to a public utility
transmission provider in a different balancing authority area, if those
areas have implemented intra-hour scheduling for transmission service.
In addition, upon consideration of the comments to the NOPR, this Final
Rule also allows a resource with market-based rate authority for sales
of energy and capacity to sell operating reserve services at market-
based rates to a public utility transmission provider in the same
balancing authority area, or to a public utility transmission provider
in a different balancing authority area, if those areas have
implemented intra-hour scheduling for transmission service that
supports the delivery of operating reserve resources from one balancing
authority area to another. As a result, the only remaining limitation
on third-party market-based sales of ancillary services is on sales of
Reactive Supply and Voltage Control service and Regulation and
Frequency Response service to a public utility that is purchasing
ancillary services to satisfy its own OATT requirements absent a
showing of lack of market power or adequate mitigation of potential
market power. In that regard, third-party sales of Reactive Supply and
Voltage Control service and Regulation and Frequency Response service
to public utility transmission providers will be permitted at rates not
to exceed the buying public utility transmission provider's OATT rate
for the same service. Further, to the extent a transmission provider
chooses to procure either Reactive Supply and Voltage Control service
or Regulation and Frequency Response service through a competitive
solicitation that meets the requirements of this Final Rule, third-
party sellers of these services may sell at market-based rates.
14. While the record in this proceeding was insufficient for the
Commission to relieve the restrictions for Reactive Supply and Voltage
Control service and Regulation and Frequency Response service in the
same manner as Imbalance and Operating reserves, we remain interested
in exploring the technical, economic and market issues concerning the
provision of Reactive Supply and Voltage Control service and Regulation
and Frequency Response service. As such, the Commission intends to
gather further information regarding the provision of Reactive Supply
and Voltage Control service and Regulation and Frequency Response
service in a separate, new proceeding.
15. Thus, while we decline to adopt some of the reforms proposed in
the NOPR based on the record in this proceeding, we expect that this
Final Rule substantially enhances the overall opportunities for third-
parties to compete to make sales of ancillary services while continuing
to limit the exercise of market power.
16. We will first discuss the market power analyses used to
establish authority to sell at market-based rates, followed by a
discussion of alternative cost-based mitigation in the event a market
participant cannot show it lacks market power for a specific product or
service.
Use of Market Power Analyses
17. The Commission analyzes horizontal market power \22\ for sales
of energy and capacity using two indicative screens, the wholesale
market share screen and the pivotal supplier screen, to identify
sellers that raise no horizontal market power concerns and can
otherwise be considered for market-based rate authority.\23\ The
wholesale market share screen measures whether a seller has a dominant
position in the relevant geographic market in terms of the number of
megawatts of uncommitted capacity owned or controlled by the seller, as
compared to the uncommitted capacity of the entire market.\24\ A seller
whose share of the relevant market is less than 20 percent during all
seasons passes the wholesale market share screen.\25\ The pivotal
supplier screen evaluates the seller's potential to exercise horizontal
market power based on the seller's uncommitted capacity at the time of
annual peak demand in the relevant

[[Page 46182]]

market.\26\ A seller satisfies the pivotal supplier screen if its
uncommitted capacity is less than the net uncommitted supply in the
relevant market.\27\
---------------------------------------------------------------------------

\22\ 18 CFR 35.37(b) (2012).
\23\ Order No. 697, FERC Stats. & Regs. ] 31,252 at PP 13, 62.
See also 18 CFR 35.37(b), (c)(1) (2012).
\24\ Order No. 697, FERC Stats. & Regs. ] 31,252 at P 43.
Uncommitted capacity is determined by adding the total nameplate or
seasonal capacity of generation owned or controlled through contract
and firm purchases, less operating reserves, native load commitments
and long-term firm sales. Id. P 38.
\25\ Id. PP 43-44, 80, 89.
\26\ 18 CFR 35.37(c)(1) (2012).
\27\ Order No. 697, FERC Stats. & Regs. ] 31,252 at P 42.
---------------------------------------------------------------------------

18. Passing both the wholesale market share screen and the pivotal
supplier screen creates a rebuttable presumption that the seller does
not possess horizontal market power with respect to sales of energy or
capacity; failing either screen creates a rebuttable presumption that
the seller possesses horizontal market power for such sales.\28\ A
seller that fails one of the screens may present evidence, such as a
delivered price test (DPT), to rebut the presumption of horizontal
market power.\29\ In the alternative, a seller may accept the
presumption of horizontal market power and adopt some form of cost-
based mitigation.\30\
---------------------------------------------------------------------------

\28\ 18 CFR 35.37(c)(1) (2012).
\29\ 18 CFR 35.37(c)(2) (2012). For purposes of rebutting the
presumption of horizontal market power, sellers may use the results
of the DPT to refine the default relevant geographic market used to
perform pivotal supplier and market share analyses and market
concentration analyses using the Herfindahl-Hirschman Index (HHI).
The HHI is a widely accepted measure of market concentration,
calculated by squaring the market share of each firm competing in
the market and summing the results. The Commission has stated that a
showing of an HHI less than 2,500 in the relevant market for all
season/load periods for sellers that have also shown that they are
not pivotal and do not possess a market share of 20 percent or
greater in any of the season/load periods would constitute a showing
of a lack of horizontal market power, absent compelling contrary
evidence from intervenors. Order No. 697, FERC Stats. & Regs. ]
31,252 at P 111.
\30\ 18 CFR 35.37(c)(3) (2012).
---------------------------------------------------------------------------

19. Three of the key components of the analysis of horizontal
market power are the definition of products, the determination of
appropriate geographic scope of the relevant market for each product,
and the identification of the uncommitted generation supply within the
relevant geographic market. In Order No. 697, the Commission adopted a
default relevant geographic market for sales of energy and
capacity.\31\ In particular, the Commission will generally use a
seller's balancing authority area plus first-tier markets,\32\ or the
RTO/ISO market as applicable, as the default relevant geographic
market. For sales of energy and capacity, the product definitions are
well understood: the relevant geographic market is generally the
default market described above; and, the uncommitted generation supply
is generally identified as all such supply located within the seller's
balancing authority area, plus potential uncommitted imports, as
determined largely by available transmission capacity in the form of
simultaneous import limits.\33\ Except in the circumstances set forth
in Avista, entities seeking to sell ancillary services at market-based
rates have been required to provide market power analyses that address
the nature and characteristics of each ancillary service, as well as
the nature and characteristics of generation capable of supplying each
service.\34\ This requirement was based on an assumption that such
characteristics might differ from those related to sales of energy and
capacity.
---------------------------------------------------------------------------

\31\ Order No. 697, FERC Stats. & Regs. ] 31,252 at P 15.
\32\ First-tier markets are those markets directly
interconnected to the seller's balancing authority area. See, e.g.,
Order No. 697, FERC Stats. & Regs. ] 31,252 at P 232.
\33\ Studies of Simultaneous Transmission Import Limits (SIL)
quantify a study area's simultaneous import capability from its
aggregated first-tier area. SIL studies are used as a basis for
calculating import capability to serve load in the relevant
geographic market when performing market power analyses.
\34\ See, Ocean Vista, 82 FERC ] 61,114, at 61,406-07 (1998).
---------------------------------------------------------------------------

a. Reliance on Existing Indicative Screens
20. In the NOPR, the Commission analyzed whether passage of the
existing market-based rate screens for sales of energy and capacity can
adequately demonstrate lack of market power for sales of ancillary
services, based on the relevant characteristics of resources capable of
providing each ancillary service. Based on this analysis, the
Commission proposed that only the two imbalance ancillary services
(Energy Imbalance and Generator Imbalance), and no other ancillary
services, could be encompassed by the existing market-based rate
screens.\35\ The Commission sought comment on both this analysis and
the resulting proposal.\36\
---------------------------------------------------------------------------

\35\ NOPR, FERC Stats. & Regs. ] 32,690 at PP 18-24.
\36\ Id. P 24.
---------------------------------------------------------------------------

21. As discussed in more detail below, commenters addressed both
the Commission's ancillary service-by-ancillary service analysis of
this issue, and the proposal to apply the existing market power screens
to only the imbalance ancillary services.
i. Application to Imbalance Ancillary Services
Commission Proposal
22. In the NOPR, the Commission stated that resources capable of
providing Energy Imbalance and Generator Imbalance do not appear to
require any different technical equipment or suffer from any different
geographical limitations compared to resources that provide energy or
capacity. As a result, the Commission proposed that sellers passing
existing market power analyses should be permitted to sell not only
energy and capacity in the relevant geographic market(s), but also
Energy Imbalance and Generator Imbalance services at market-based
rates. The Commission sought comments on, among other things, any
unique technical requirements or limitations that might apply to the
provision of the imbalance ancillary services that might impact the
Commission's proposal to find that passage of the existing market power
screens also indicates a lack of market power for imbalance
services.\37\
---------------------------------------------------------------------------

\37\ Id. PP 19-20.
---------------------------------------------------------------------------

Comments
23. The majority of commenters support the Commission's proposal.
AWEA, Beacon, California Storage Alliance, EEI, Electricity Consumers,
EPSA, ESA, Iberdrola, Hydro Association, Public Interest Organizations,
Powerex, Solar Energy Association, Shell Energy, Southern California
Edison, and WSPP support the NOPR proposal to revise the Commission's
regulations governing market-based rate authorizations to provide that
sellers passing existing market-based rate analyses in a given
geographic market should be granted a rebuttable presumption that they
lack horizontal market power for sales of Energy Imbalance and
Generator Imbalance ancillary services in that market.
24. ESA, Electricity Consumers, Beacon, and EEI, among others,
agree that there are no special technical requirements or other
limitations that apply to the provision of the Energy Imbalance or
Generator Imbalance ancillary services.\38\ Electricity Consumers and
WSPP, among others, argue that the proposed revisions should reduce
barriers to ancillary service providers and increase the supply of
needed ancillary services. WSPP agrees that the proposal would enable
additional sellers of balancing energy to transact with public utility
transmission providers in both bilateral markets or a multi-lateral
balancing market, and states that it would likely foster sales of
balancing energy even outside of the transmission provider market. AWEA
contends that the Commission's proposed reforms strike

[[Page 46183]]

the appropriate balance between reducing barriers to entry and
protecting against market power.
---------------------------------------------------------------------------

\38\ ESA Comments at 6; Beacon Comments at 5; Electricity
Consumers Comments at 3; and EEI Comments at 9.
---------------------------------------------------------------------------

25. WSPP and Powerex, with Iberdrola concurring by reference, urge
the Commission to clarify that this proposal includes the capacity
associated with balancing energy sales, not just the energy.\39\ WSPP
states that without the underlying capacity, sales of balancing energy
could have no firmness and would be of little value in the market, in
particular the bilateral market. Further, WSPP contends that the likely
market for balancing energy would not differentiate energy and capacity
products by OATT Schedules. Rather, sellers would sell ``flexible
capacity'' capable of fulfilling multiple OATT Schedules and operators
would look to flexible capacity to support various system stabilizing
functions to which the OATT Schedules refer. Thus, WSPP contends that
the market would be more efficient if the capacity and energy required
to provide OATT services are not required to be unbundled when the
natural market for supply would be a bundled ``flexible capacity''
product.\40\
---------------------------------------------------------------------------

\39\ WSPP Comments at 6; and Powerex Comments at 9-10.
\40\ WSPP Comments at 7.
---------------------------------------------------------------------------

26. Solar Energy Association states conceptual support for the
proposal, but argues that sellers may have market power in certain
ancillary services markets even if not in energy or capacity markets,
and urges the Commission to police markets that are created due to the
adoption of a rebuttable presumption of lack of market power.\41\
---------------------------------------------------------------------------

\41\ Solar Energy Association Comments at 4.
---------------------------------------------------------------------------

27. Two commenters express concern with the NOPR proposal. TAPS
objects to the NOPR's preliminary finding that any available unit in a
given geographic market is capable of providing energy that helps
address imbalances in that market. TAPS contends that significant
technical limitations limit the resources that can provide imbalance
services absent special arrangements like pseudo-ties, and therefore
the first tier resources included in the horizontal market power screen
are not generally available to provide intra-hour imbalance service.
TAPS asserts that Order No. 890-A supports this contention by allegedly
finding ``that generation outside the control area can provide
imbalance service when pseudo-tied and thus subject to within-area
dispatch control.'' \42\ TAPS further states that outside organized
markets, generators capable of providing imbalance service must have a
special relationship with the control area operator in order to supply
changing within-the-hour energy needs, without the constraints of
hourly transmission scheduling requirements and that even the recently
adopted 15-minute scheduling requirement is insufficient, especially
when combined with the need to schedule 20 minutes in advance.\43\
---------------------------------------------------------------------------

\42\ TAPS Comments at 11-12.
\43\ Id. at 11-13.
---------------------------------------------------------------------------

28. TAPS asserts that, in non-RTO regions, imbalance service is
typically provided by the energy associated with regulation and
operating reserves, and thus resources capable of providing imbalance
services would necessarily be subject to the same technical
requirements as the NOPR described for regulation and operating
reserves.\44\ TAPS supports this assertion by claiming that Order No.
890 found that ``demand costs of providing imbalance service are
already being provided under Schedule 3, 5, and 6 charges [i.e.,
Regulation and Frequency Response Service, Operating Reserve-Spinning
Reserve Services, and Operating Reserve Supplemental Reserve
Services].'' \45\
---------------------------------------------------------------------------

\44\ Id. at 12-13.
\45\ Id. at 12 (citing Order No. 890, FERC Stats. & Regs. ]
31,241 at P 690).
---------------------------------------------------------------------------

29. TAPS further rejects the Commission's assertion in the NOPR
that this proposal is consistent with the decision in Order No. 890-A
to base cost-based imbalance charges in the OATT on the incremental
cost of the last 10 MW dispatched by the transmission provider for any
purpose, without imposing any requirement that this last 10 MW be based
on resources with any particular capabilities.\46\ TAPS contends that
the pricing of OATT imbalance service does not demonstrate the absence
of the alleged restrictions described above on the supply of intra-hour
energy that allows transmission providers to provide energy imbalance
service.
---------------------------------------------------------------------------

\46\ NOPR, FERC Stats. & Regs. ] 32,690 at P 19 (citing Order
No. 890-A, FERC Stats. & Regs. ] 31,261 at P 309).
---------------------------------------------------------------------------

30. Morgan Stanley contends that the existing market power screens
are flawed even in their application to energy and capacity products
and thus should not be applied to additional products. Morgan Stanley
argues that the existing market power screens in some cases fail to
assess the full import capability into a given geographic market, and
thus the true market size. Morgan Stanley ultimately argues that a
revised market power screen ``should include any transmission located
outside of the relevant market area, but which is interconnected and
over which there is transfer capacity.'' \47\ However, Morgan Stanley
does not state opposition to the idea that a lack of market power in
energy and capacity can justify an assumption of equivalent lack of
market power in Energy Imbalance and Generator Imbalance services.
---------------------------------------------------------------------------

\47\ Morgan Stanley Comments at 2-5.
---------------------------------------------------------------------------

Commission Determination
31. The Commission will adopt its proposal with modification. The
Commission will allow third-party sellers passing existing market power
screens to sell Energy Imbalance and Generator Imbalance services at
market-based rates to a public utility transmission provider within the
same balancing authority area, or to a public utility transmission
provider in a different balancing authority area, if those areas have
implemented intra-hour scheduling for transmission service.\48\ The
Commission continues to believe that there are no unique technical
requirements or limitations that apply to a resource's provision of
Energy Imbalance or Generator Imbalance services. However, the
Commission agrees with TAPS that the delivery of Energy Imbalance and
Generator Imbalance services may be limited by hourly transmission
scheduling practices in place within certain regions and, as such,
refines the NOPR proposal as discussed below.
---------------------------------------------------------------------------

\48\ We note that sales of Energy Imbalance and Generator
Imbalance services to entities other than a public utility
transmission provider remain authorized under Avista.
---------------------------------------------------------------------------

32. Energy Imbalance and Generator Imbalance services are a subset
of a broader set of ancillary services offered by a public utility
transmission provider to manage system conditions and ensure reliable
transmission service. Energy Imbalance and Generator Imbalance services
involve the balancing of differences between scheduled and actual
delivery of energy or output of generation over an hour.\49\ In
comparison, Regulation and Frequency Response service involves the
matching of resources to load in a shorter timeframe, requiring
automated dispatch at four- or five-second intervals.\50\ As a result,
resources used

[[Page 46184]]

to provide Regulation and Frequency Response service must be capable of
balancing moment-to-moment fluctuations, whereas resources used to
provide Energy and Generator Imbalance can respond at longer time
frames within the hour.
---------------------------------------------------------------------------

\49\ See pro forma OATT, Schedules 4 and 9. Under the pro forma
OATT, imbalances are calculated and charged on an hourly basis. See
Order No. 890, FERC Stats. & Regs. ] 31,241 at P 722; Order No. 890-
A, FERC Stats. & Regs. ] 61,297 at P 325 & n.117; see also Order No.
764, FERC Stats. & Regs. ] 32,331 at P 104. Energy Imbalance and
Generator Imbalance services also may be self-supplied by a
transmission customer.
\50\ See, e.g., Pro Forma OATT, Schedule 3 Regulation and
Frequency Response Service--``Regulation and Frequency Response
Service is necessary to provide for the continuous balancing of
resources (generation and interchange) with load . . . .''
---------------------------------------------------------------------------

33. In practice, public utility transmission providers often have a
portfolio of resources, some owned and some purchased from third-
parties, from which they provide capacity, energy, and ancillary
services. This portfolio typically includes resources with automatic
generation control (AGC) equipment capable of handling both moment-by-
moment frequency adjustments and longer duration imbalance needs, as
well as other capacity and energy resources that may only be capable of
addressing longer duration imbalance needs because they are not
equipped with AGC. These longer duration resources may include block
purchases from third parties that are dispatched or otherwise scheduled
at varying timeframes. The relative amount of AGC-controlled and other
resources used by a public utility transmission provider for intra-hour
balancing will depend on the resources available and the public utility
transmission provider's operating practices.
34. In the NOPR, the Commission did not separately discuss this
range of resources and, instead, preliminarily concluded that there are
no unique technical requirements or limitations that distinguish the
resources capable of providing energy and capacity from those capable
of providing imbalance services. The majority of commenters agree with
the Commission's preliminary conclusion, arguing that the set of
resources available to follow imbalances over an hour is the same set
of resources capable of providing energy and capacity. However, TAPS
disagrees, arguing that the set of resources capable of providing
imbalance services must have a special relationship with the control
area operator in order to supply changing within-the-hour energy needs.
35. We understand TAPS' argument to be that resources used to
provide imbalance service must be able to respond to a dynamic four- or
five-second signal, which might require special arrangements in order
to permit imbalance sales outside of the resource's home balancing
authority area such that even the ability to submit transmission
schedules on a 15-minute basis would be insufficient to provide intra-
hour imbalance energy.\51\ We agree that some of the public utility
transmission provider's energy imbalance needs are addressed by
resources that manage the moment-by-moment difference between load and
resources. We also agree that imbalance service would generally require
deliveries on intervals shorter than the current hour. But we do not
agree, as explained more fully below, that imbalance services require
dynamic dispatch or more sophisticated delivery mechanisms than intra-
hour transmission scheduling.
---------------------------------------------------------------------------

\51\ TAPS Comments at 13.
---------------------------------------------------------------------------

36. Under the pro forma OATT, imbalances are calculated on an
hourly basis.\52\ As a result, any energy deliveries within the hour
can be used by a public utility transmission provider (or by a
transmission customer) to manage imbalances across the hour. That is,
energy deliveries within the hour can be included in the portfolio of
resources used to follow imbalance trends across the hour, similar to a
public utility transmission provider's decision to redispatch its own
internal resources within the hour. While it is true, as TAPS states,
that dynamically dispatched resources capable of providing regulation
also would be capable of providing imbalance services, it does not
follow that resources using intra-hour transmission schedules are
incapable of providing imbalance services. As noted above, imbalance
service can be provided from a collection of resources so long as they
are deliverable within the hour.\53\
---------------------------------------------------------------------------

\52\ See Order No. 890, FERC Stats. & Regs. at P 722, order on
reh'g, Order No. 890-A, FERC Stats. & Regs. ] 61,297 at P 325 &
n.117; see also Order No. 764, FERC Stats. & Regs. ] 32,331 at P
104.
\53\ The Commission acknowledges that energy purchases scheduled
on an hourly basis might enable a public utility transmission
provider to use other resources to provide imbalance or other
ancillary services more efficiently or precisely. Such hourly sales
of energy would not be an indirect sale of ancillary services within
the meaning of Avista.
---------------------------------------------------------------------------

37. The question before the Commission here is whether the set of
resources considered available to provide energy and capacity in a
market power analysis is sufficiently similar to the set of resources
capable of providing imbalance services. Based on the record before us
in which numerous commenters agree that the resources are sufficiently
similar and given that intra-hour transmission schedules are currently
being offered by a number of public utility transmission providers, and
must be offered by all public utility transmission providers under
Order No. 764 on or before November 12, 2013,\54\ the Commission finds
it appropriate at this time to revise the Avista restriction to better
reflect current operational realities.
---------------------------------------------------------------------------

\54\ In order to comply with Order No. 764, public utility
transmission providers must allow transmission customers to modify
existing schedules as well as create new transmission schedules at
intervals not to exceed 15 minutes, on or before November 12, 2013.
Order No. 764, FERC Stats. & Regs. ] 32,331 at P 91, order on reh'g,
Order 764-A, 141 FERC ] 61,232.
---------------------------------------------------------------------------

38. With regard to TAPS' additional comments in support of its
basic argument, as stated above, just because a public utility
transmission provider may have chosen to rely on the energy associated
with regulation or operating reserves to meet imbalances, it does not
follow that those are the only resources capable of providing imbalance
services. Moreover, TAPS' reference to a portion of a passage from
Order No. 890 referring to demand costs of providing imbalance energy
being recoverable through regulation (Schedule 3) and operating reserve
(Schedules 5 and 6) services is not dispositive here. The rate
mechanisms used by a public utility transmission provider to recover
the cost of capacity associated with providing Energy Imbalance or
Generator Imbalance service do not precisely reflect the technical
capabilities of resources available to provide the imbalance services.
There is no requirement, in past Commission pronouncements or
otherwise, that imbalance services be provided only from resources
capable of providing regulation or operating reserves. Indeed, TAPS
criticizes the NOPR for asserting the Commission's proposal was
consistent with the decision in Order No. 890-A to base cost-based
imbalance charges on the incremental cost of the last 10 MW dispatched
by the transmission provider for any purpose, without imposing any
requirement that this last 10 MW be based on resources with any
particular capabilities.\55\ We agree with TAPS that the pricing of
OATT imbalance services does not necessarily determine the technical
capabilities of resources available to provide those services and
reject the NOPR's assertion in this regard. Similarly, we find that the
pricing of regulation and operating reserve services, whether through
Schedules 3, 5, 6 or some other mechanism (such as generator regulation
service), do not necessarily determine the technical capabilities of
resources available to provide imbalance services.
---------------------------------------------------------------------------

\55\ See NOPR, FERC Stats. & Regs. ] 32,690 at P 19 (citing
Order No. 890-A, FERC Stats. & Regs. ] 31,261 at P 309).
---------------------------------------------------------------------------

39. TAPS also cites Order No. 890-A as finding that generation
outside a control area can provide imbalance

[[Page 46185]]

service when pseudo-tied and thus subject to within-area dispatch.\56\
The cited passage of Order No. 890-A, however, states that a pseudo-tie
arrangement causes a control area to ``assum[e] responsibility for
ensuring that the load is properly balanced moment-to-moment, for
planning for the load, and for providing various other ancillary
services including energy or generator balancing service.'' The
Commission made no determination in that passage as to the universe of
resources capable, or incapable, of providing imbalance services.
Nevertheless, the Commission acknowledges that some public utility
transmission providers may choose not to purchase imbalance service
from resources that cannot also be dynamically dispatched. While that
may inform the relative ability of a resource to find a buyer for its
service, it does not define the set of resources from which imbalance
services are available, which is the relevant question for market power
analyses.
---------------------------------------------------------------------------

\56\ TAPS Comments at 12 (citing Order No. 890-A, FERC Stats. &
Regs. ] 31,261 at P 631).
---------------------------------------------------------------------------

40. We also find the opposing arguments of Morgan Stanley to be
beyond the scope of this proceeding. Morgan Stanley does not appear to
object to the use of the same market power screens for energy, capacity
and imbalance services. Rather, Morgan Stanley argues that the existing
indicative screens should be reformulated to include greater
transmission imports than are currently assumed. Arguments as to the
make-up of the existing market power screens are beyond the scope of
this proceeding. The question before us in this proceeding is whether
the resources in a given geographic market capable of providing
imbalance ancillary services are sufficiently similar to the resources
capable of providing energy and capacity that the same market power
analysis can apply to both sets of products. Moreover, the Commission
already permits applicants to demonstrate that the relevant geographic
market is larger or smaller than that default.\57\
---------------------------------------------------------------------------

\57\ Order No. 697, FERC Stats. & Regs. ] 31,252 at P 268.
---------------------------------------------------------------------------

41. Accordingly, this Final Rule establishes that sellers found to
lack market power in a geographic market, and which are granted market-
based rate authority to make sales of energy and capacity, will also be
granted market-based rate authority for sales of Energy Imbalance and
Generator Imbalance services to public utility transmission providers
within the same balancing authority area, or to public utility
transmission providers in different balancing authority areas, if those
areas allow transmission customers to modify or create transmission
schedules within the hour. Because, as explained above, such scheduling
practices enable the delivery of within-hour imbalance services from
one balancing authority area to another, their use ensures that the
first-tier resources included in the existing market power screens can
compete with resources in the home balancing authority area, and thus
that the existing market power screens can be applied to imbalance
services without modification. This finding applies both to sellers
that currently have a market-based rate tariff on file and applicants
seeking market-based rate authority. For administrative convenience, we
make this change to the Commission's ancillary services pricing policy
effective as of the effective date of this Final Rule (120 days after
publication in the Federal Register), which will result in these
changes becoming effective after November 12, 2013, the date by which
all public utility transmission providers must offer intra-hour
transmission scheduling. As noted above, we acknowledge that some
transmission providers already offer intra-hour scheduling. However,
rather than performing a transmission provider-by-transmission provider
review of current scheduling practices in this rulemaking, the
Commission will defer implementation of this change to our ancillary
services pricing policy until after the effectiveness of the intra-hour
scheduling requirements of Order No. 764, by which time all public
utility transmission providers must offer intra-hour scheduling. Thus,
as of the effective date, all sellers that have a market-based rate
tariff on file as of that date may begin making third-party sales of
Energy Imbalance and Generator Imbalance services at market-based rates
to a public utility transmission provider that is purchasing Energy
Imbalance and Generator Imbalance services to satisfy its own open
access transmission tariff requirements to offer ancillary services to
its own customers, without having to make a separate showing to the
Commission.
42. In response to WSPP, we clarify that this authorization to
undertake sales at market-based rates may include both the capacity and
the energy associated with providing Energy Imbalance and Generator
Imbalance services. Imbalance services are products designed to address
differences between scheduled and actual deliveries and withdrawals of
energy. As such, they can only be provided by ensuring the availability
of capacity and then increasing or decreasing the energy output from
that capacity as necessary to address these differences.\58\
---------------------------------------------------------------------------

\58\ See, e.g., Order No. 764, FERC Stats. & Regs. ] 32,331 at P
240.
---------------------------------------------------------------------------

ii. Application to Other Ancillary Services
Commission Proposal
43. In the NOPR, the Commission proposed to allow the existing
market-based rate screens to be applied to Energy Imbalance and
Generator Imbalance services, but sought comment on whether the
characteristics of resources used to provide the other ancillary
services would necessitate a market power analysis based on a different
geographic market or different set of resources as compared to those
analyzed to determine market power for sales of energy and
capacity.\59\
---------------------------------------------------------------------------

\59\ NOPR, FERC Stats. & Regs. ] 32,690 at P 24.
---------------------------------------------------------------------------

44. With regard to Operating Reserve-Spinning and Operating
Reserve-Supplemental, the NOPR discussed the technical considerations,
such as minimum ramp and start-up rates for off-line resources and the
ability for extended operation below fully loaded set point for online
resources, that seemed to indicate that fewer resources would be
capable of providing these ancillary services as compared to the set of
resources capable of providing energy or capacity. With regard to
Reactive Supply and Voltage Control from Generation Sources, the NOPR
discussed the technical and geographic considerations that generally
limit the resources capable of providing this ancillary service as
compared with the broader set of resources capable of providing energy
or capacity. With regard to Regulation and Frequency Response, the
Commission discussed the technical requirements, such as automatic
generation control (AGC) equipment, that limit the set of resources
capable of supplying this ancillary service.\60\
---------------------------------------------------------------------------

\60\ Id. PP 22-23.
---------------------------------------------------------------------------

Comments
45. A number of commenters argue for application of the existing
market power screens to Operating Reserve-Spinning and Operating
Reserve-Supplemental.\61\ EPSA argues that operating reserves are

[[Page 46186]]

merely derivatives of a resource's ability to generate energy.\62\
---------------------------------------------------------------------------

\61\ EPSA Comments at 6, WSPP Comments at 8 (with Iberdrola
supporting by reference), EEI Comments at 3 and 10, Western Group
Comments at 3-4, Hydro Association Comments at 7, and Powerex
Comments at 7 and 13.
\62\ EPSA Comments at 6.
---------------------------------------------------------------------------

46. WSPP argues that the same considerations that led the
Commission to believe that the rebuttable presumption should be
extended to the imbalance ancillary services also apply to the
operating reserve ancillary services. WSPP further asserts that all of
these ancillary services are widely deliverable and that all generators
capable of being redispatched to higher or lower set-points within a
scheduling window are capable of providing these ancillary
services.\63\
---------------------------------------------------------------------------

\63\ WSPP Comments at 8. Iberdrola supports these WSPP comments
by reference.
---------------------------------------------------------------------------

47. EEI argues that except for variable energy resources,
essentially the same set of resources evaluated as competing supply
under the existing market power screens possess the required technical
capabilities to provide operating reserves.\64\ Western Group makes a
similar argument, asserting that products in Schedules 3, 5, and 6
(Regulation and Operating Reserves) share operational characteristics
of Schedules 4 and 9 (Imbalance services).\65\
---------------------------------------------------------------------------

\64\ EEI Comments at 10.
\65\ Western Group Comments at 3.
---------------------------------------------------------------------------

48. While Powerex agrees that resources capable of providing
spinning and non-spinning reserves may be limited by response time
requirements, Powerex argues that the existing market power screens
nonetheless can be applied to operating reserve services.\66\
---------------------------------------------------------------------------

\66\ Powerex Comments at 7 and 13.
---------------------------------------------------------------------------

49. With respect to Regulation and Frequency Response, some
commenters argue that passage of the existing market power screens
indicates lack of market power for that service. For example, while
EPSA agrees that the market power of sellers of Reactive Supply and
Voltage Control service cannot be gauged by the existing market power
screens due to significant technical and geographic impediments, it
argues that Regulation and Frequency Response service is merely a
derivative of a resource's ability to generate energy. Accordingly,
EPSA argues that application of the existing market power screens to
this ancillary service would be appropriate.\67\
---------------------------------------------------------------------------

\67\ EPSA Comments at 6.
---------------------------------------------------------------------------

50. Powerex agrees that the existing market power screens could be
applied to Regulation and Frequency Response service. Powerex believes
that technical improvements such as the dynamic scheduling system
adopted by some users of the Western Interconnection facilitate
widespread delivery of regulating reserves, thus overcoming any
locational requirements for that service, while any technical
impediments could be overcome because AGC or equivalent power
electronic controls could be added by most market participants if the
markets provide correct price signals.\68\ WSPP similarly argues that,
while not all generators have the AGC equipment needed to provide
Regulation and Frequency Response service, installation of this
capability is an economic decision and is not such an impediment that
it should be treated as a market defining barrier to entry.\69\
---------------------------------------------------------------------------

\68\ Powerex Comments at 12.
\69\ WSPP Comments at 8. Iberdrola supports these WSPP comments
by reference.
---------------------------------------------------------------------------

51. FTC Staff urges the Commission to recognize that even though a
particular resource may not currently have the ability to provide a
given ancillary service due to lack of relevant equipment, if such
equipment could be installed in a timely fashion in response to high
prices, then such resource should be considered a potential competitor
for purposes of market power analysis. Accordingly, FTC Staff suggests
that the Commission revise its market power analysis to incorporate as
existing market participants those potential entrants that are likely
to enter a given ancillary service market (i.e., install needed
equipment such as AGC) rapidly and profitably should market prices
justify such entry.\70\
---------------------------------------------------------------------------

\70\ FTC Staff Comments at 6-8.
---------------------------------------------------------------------------

52. EEI argues that, before extending application of the existing
market power screens to Regulation and Frequency Response, the
Commission should separate this service into two separate ancillary
services: primary frequency control and secondary frequency control.
EEI argues that secondary frequency control, which it labels as
Regulation, is a prime candidate to be extended the rebuttable
presumption (i.e., to be subject to the existing market power
screens).\71\
---------------------------------------------------------------------------

\71\ EEI Comments at 10-11.
---------------------------------------------------------------------------

53. Two parties filed comments opposing the application of existing
market power screens to non-imbalance ancillary services. Southern
California Edison and TAPS state that they agree with the NOPR's
reasoning as to why the existing market power screens cannot be applied
to non-imbalance ancillary services.\72\ Remaining commenters did not
address the question of applying the existing market power screens to
non-imbalance ancillary services.
---------------------------------------------------------------------------

\72\ Southern California Edison Comments at 1-2; and TAPS
Comments at 9-10.
---------------------------------------------------------------------------

Commission Determination
54. Upon consideration of the comments to the NOPR, and as
discussed more fully below, the Commission will allow third-party
sellers passing existing market power screens to sell Operating
Reserve-Spinning and Operating Reserve-Supplemental services at market-
based rates to a public utility transmission provider within the same
balancing authority area, or to a public utility transmission provider
in a different balancing authority area, if those areas have
implemented intra-hour scheduling for transmission service that
supports the delivery of operating reserve resources from one balancing
authority area to another. Commenters have persuaded us that to the
extent there are technical requirements and limitations associated with
operating reserves, they do not materially distinguish resources
capable of providing energy and capacity from those capable of
providing operating reserves. As with the imbalance services, however,
the Commission finds that the delivery of operating reserves from one
balancing authority area to another may be limited by hourly scheduling
practices in place within certain regions, which could impact the
assumption in the existing market power screens that first-tier
resources are able to compete with home balancing authority area
resources. Therefore, the Commission will allow third-party sellers
passing existing market power screens to sell these services to public
utility transmission providers to the extent within-hour transmission
service scheduling practices, including intra-hour transmission
scheduling mandated by Order No. 764, support the delivery of operating
reserves from one balancing authority area to another.
55. In contrast, the Commission affirms the preliminary finding in
the NOPR that the set of resources capable of providing Regulation and
Frequency Response service and Reactive Supply and Voltage Control
service would differ significantly from the broader set of resources
capable of supplying energy and capacity. Accordingly, the Avista
restrictions will remain in place for sales of those services to public
utility transmission providers at market-based rates. As noted below,
the Commission will establish a new proceeding to further explore the
technical, economic and market issues concerning the provision of
Reactive Supply and Voltage Control service and Regulation and
Frequency Response service.

[[Page 46187]]

Operating Reserve Services
56. Operating Reserve-Spinning and Operating Reserve-Supplemental
are products designed to serve load temporarily in the event of
contingencies. As such, sellers must ensure the availability of
capacity sufficient to address a contingency event and, if the
contingency occurs, energy must be supplied from that capacity. While
the NOPR preliminarily found that the operating reserve products
appeared to require the availability of resources with relatively fast
ramping capabilities, and in the case of off-line resources used for
operating reserve-supplemental, relatively fast start-up capabilities
as well,\73\ comments to the NOPR argue otherwise.
---------------------------------------------------------------------------

\73\ See NOPR, FERC Stats. & Regs. ] 32,690 at P 22.
---------------------------------------------------------------------------

57. Many comments to the NOPR make the case that the flexibility
and response time requirements associated with operating reserve
services are not so significant that the universe of resources that can
provide these services is meaningfully different than the universe of
resources used to assess energy and capacity market power. While
traditional generation scheduling practices only require the resources
that provide energy and capacity to be able to change output levels
once an hour, the record in this proceeding indicates that most
resources can change output levels on shorter time scales. In other
words, most conventional resources can change output in response to
contingency events on a time scale shorter than the typical hourly
scheduling window, even if in the past they have only been selling
hourly block energy and capacity. Therefore, the Commission will allow
third-party sellers passing existing market power screens for energy
and capacity for a given market to also sell Operating Reserves-
Spinning and Operating Reserves-Supplemental services at market-based
rates to a public utility transmission provider within the same
balancing authority area, or to a public utility transmission provider
in a different balancing authority area, if within-hour transmission
scheduling practices in those areas support the delivery of operating
reserves from one balancing authority area to another.\74\
---------------------------------------------------------------------------

\74\ As with Energy Imbalance and Generator Imbalance services,
we clarify that the authorization to undertake sales at market-based
rates may include both the capacity and the energy associated with
providing Operating Reserve-Spinning and Operating Reserve-
Supplemental services.
---------------------------------------------------------------------------

58. We note that our approach for market-based sales of operating
reserves differs slightly from the reforms adopted above for sales of
imbalance services. We have found above that the existence of 15-minute
scheduling in a region renders the set of resources capable of
supplying imbalance services substantially similar to the set of
resources capable of providing energy and capacity so that the same
market power screens can be applied to both sets of services. This may
not be the case in all circumstances for potential sellers of operating
reserves and, therefore, we require such entities to explain in their
market-based rate applications for such authority how the scheduling
practices in their regions support the use of operating reserves. For
example, while 15-minute scheduling might be sufficient for Operating
Reserve-Supplemental because this service only requires designated
resources to be available within a short period of time,\75\ 15-minute
scheduling by itself may not be sufficient for Operating Reserve-
Spinning, which requires designated resources to be available
immediately.\76\ The Commission recognizes that unlike the imbalance
services, operating reserve services are targeted only at addressing
contingency events, and some regions such as WECC may have already
developed within-hour capacity tagging and scheduling practices
intended to support the use of operating reserves across multiple
balancing authority areas.\77\ These are the types of region-specific
practices that sellers seeking authority to sell operating reserves to
public utility transmission providers should describe in their market-
based rate applications. Thus, as of the effective date of this Final
Rule, both sellers that have a market-based rate tariff on file as of
that date and applicants seeking new market-based rate authority must
satisfactorily make the above showing and receive Commission
authorization before making sales of Operating Reserve-Spinning and
Operating Reserve-Supplemental to a public utility that is purchasing
Operating Reserve-Spinning and Operating Reserve-Supplemental to
satisfy its own open access transmission tariff requirements to offer
ancillary services to its own customers.
---------------------------------------------------------------------------

\75\ See pro forma OATT, Schedule 6 ``Supplemental Reserve
Service is needed to serve load in the event of a system
contingency; however, it is not available immediately to serve load
but rather within a short period of time.''
\76\ Id. Schedule 5 ``Spinning Reserve Service is needed to
serve load immediately in the event of a system contingency.''
\77\ See, e.g., WECC Regional Business Practice INT-018-WECC-
RBP-0, Tagging Protocols, at WR5.1 and WR5.2, defining capacity e-
tags for, respectively, spinning reserves and non-spinning reserves
as ``product(s) that can be activated through the adjustment of a
capacity e-tag.'' Available at https://www.wecc.biz/library/Documentation%20Categorization%20Files/Forms/AllItems.aspx?RootFolder=%2flibrary%2fDocumentation%20Categorization%20Files%2fRegional%20Business%20Practices&FolderCTID=0x01200015E7900DB2E794468FDE06D520B95C07.
---------------------------------------------------------------------------

Regulation and Reactive Power Services
59. The Commission affirms the preliminary finding in the NOPR that
the more stringent technical and geographic considerations associated
with the regulation and reactive power ancillary services suggest that
they are not simple combinations of basic energy and capacity products.
Most commenters addressing this issue agree that the set of resources
considered by the existing market power screens would differ too
significantly from the set of resources that would be considered by
market power analyses designed specifically for Reactive Supply and
Voltage Control service.
60. While some commenters do argue that the existing market power
screens are adequate for Regulation and Frequency Response service, we
are not persuaded by their arguments on the record here. We continue to
believe that significant technical requirements, such as the need for
AGC equipment, limit the set of resources capable of supplying this
ancillary service. While we agree in principle with FTC Staff's
comments that potential competitors could be viewed as existing
competitors for purposes of market power analysis if it is known that
they can install needed equipment rapidly and profitably in response to
appropriate price signals, the record does not conclusively support the
notion that such equipment upgrades (e.g., to install AGC equipment in
an existing generator) can be accomplished in such a manner. Although
Powerex asserts that AGC or equivalent power electronic controls could
be added by most market participants if the markets provide correct
price signals, and WSPP asserts that the addition of AGC is an economic
decision, we are not persuaded based on the limited information in the
record before us. Also, the record indicates that third-party sellers
of Regulation and Frequency Response service might need to enter into
or facilitate special arrangements between neighboring balancing
authorities, such as dynamic scheduling or pseudo-tie arrangements, in
order to make sales outside of their home balancing authority area.
61. Accordingly, because the record before us does not support a
modification at this time, the Avista restrictions will remain in place
for sales of Regulation and Frequency Response and Reactive Supply and

[[Page 46188]]

Voltage Control services to a public utility transmission provider that
is purchasing these ancillary services to satisfy its own OATT
requirements to offer ancillary services to its own customers. However,
the Commission intends to gather more information regarding this issue
in a separate, new proceeding that will further explore the technical,
economic and market issues concerning the provision of Reactive Supply
and Voltage Control service and Regulation and Frequency Response
service. Such proceeding will consider, among other things, the ease
and cost-effectiveness of relevant equipment upgrades, the need for and
availability of appropriate special arrangements such as dynamic
scheduling or pseudo-tie arrangements, and other technical requirements
for provision of Regulation and Frequency Response and Reactive Supply
and Voltage Control services.
b. Optional Market Power Screen
Commission Proposal
62. In the NOPR, the Commission proposed a new optional market
power screen solely applicable to ancillary services, together with a
limited new reporting requirement that would provide potential sellers
of ancillary services with the information needed to develop market
power analyses using that optional market power screen.\78\
Specifically, the optional market power screen for an ancillary service
would compare the amount of capacity in MWs (or, as applicable, MVARs)
that a potential seller can dedicate to providing the ancillary service
in the relevant geographic market with the buyer's aggregate
requirement for that ancillary service, taking into account any
historical locational requirements (e.g., locational requirements due
to such things as binding transmission constraints or the geographic
limitations of Reactive Supply). Using this optional market power
screen, sellers whose available capacity is no more than 20 percent of
the relevant aggregate requirement for an ancillary service would
receive a rebuttable presumption that they lack horizontal market power
for the ancillary service in question.
---------------------------------------------------------------------------

\78\ NOPR, FERC Stats. & Regs. ] 32,690 at PP 25-30.
---------------------------------------------------------------------------

63. In order to provide sellers with information as to the buyer's
aggregate requirement for an ancillary service, the Commission proposed
to require each public utility transmission provider to publicly post
on its OASIS the aggregate amount (MW or MVAR, as applicable) of each
ancillary service that it has historically required, including any
geographic limitations it may face in meeting such ancillary service
requirements. For example, a transmission provider may report that it
has historically maintained 100 MW of Regulation and Frequency Response
reserves for its balancing authority area and 100 MVAR of Reactive
Supply and Voltage Control in each of two submarkets within its
balancing authority area.
Comments
64. Some commenters support the optional market power screen on the
basis that it provides a practical alternative to performing a
traditional market power analysis, given the data constraints
associated with the latter. WSPP, for example, states that the optional
market power screen is a constructive response to the disconnection
between regulatory market power study requirements and the incapability
of market participants to perform those studies due to lack of
data.\79\ WSPP states that it strongly supports the Commission's
proposal that public utility transmission providers be required to post
the information needed for sellers to prepare the optional market power
screen if the rebuttable presumption applicable to the imbalance
ancillary service is not extended to all ancillary services.\80\
---------------------------------------------------------------------------

\79\ WSPP Comments at 12.
\80\ Id. at 10.
---------------------------------------------------------------------------

65. Public Interest Organizations argue that the optional screen is
similar in intent to a de minimis capacity threshold and, as such, can
remove the barrier of a burdensome market power analysis for smaller
entities.\81\ The Solar Energy Association asserts that the optional
market power screen likely will broaden the number of participants in
the markets for certain ancillary services.\82\ Electricity Consumers
similarly argues that the optional market power screen should reduce
barriers to ancillary service providers and increase the supply of
ancillary services in a timely and cost-effective manner.\83\
---------------------------------------------------------------------------

\81\ Public Interest Organizations Comments at 6.
\82\ Solar Energy Association Comments at 5.
\83\ Electricity Consumers Comments at 3.
---------------------------------------------------------------------------

66. However, there was no consensus among the commenters supporting
the proposed optional market power screen regarding the necessary
granularity of the associated reporting requirement. Some commenters,
such as WSPP and Shell Energy, argue that postings should reflect a
transmission provider's annual peak requirements for ancillary
services, rather than annual averages. WSPP argues that posting an
annual average would tend to understate requirements for higher
periods, thereby skewing screen results in the direction of
violations.\84\ Similarly, Shell Energy states that relying on annual
peaks is preferable to annual averages because it better reflects the
amounts that transmission providers need to procure. Shell Energy
further argues that postings of annual peak values are preferable to
postings of seasonal or quarterly values, which Shell Energy claims
would be burdensome for transmission providers and suppliers.\85\
---------------------------------------------------------------------------

\84\ WSPP Comments at 11.
\85\ Shell Energy Comments at 8.
---------------------------------------------------------------------------

67. Conversely, the ESA, Beacon, and California Storage Alliance
recommend that public utilities provide seasonal and time-of-day
requirements (if any) for each ancillary service versus a single
average annual amount and note that this is consistent with the type of
data provided by RTOs/ISOs in the open wholesale markets.\86\
---------------------------------------------------------------------------

\86\ ESA Comments at 7; Beacon Comments at 6; and California
Storage Alliance Comments at 4.
---------------------------------------------------------------------------

68. Some commenters oppose the optional market power screen,
arguing that it would yield too many false positives because it does
not measure a seller's ability to supply relative to the total
potential supply of the overall market. EPSA, for example, argues that
the optional screen would routinely result in false-positive
indications of market power.\87\ EPSA states that if the Commission
decides to use a threshold test, it should compare the subject
generator to total product capability, not merely the quantity
demanded.\88\ EEI similarly argues that the optional screen likely will
result in many suppliers failing the 20 percent threshold.\89\ EEI
contends that there are alternatives that would refine the test to be
more applicable and useful in promoting robust participation in
competitive ancillary services markets in bilateral regions. EEI offers
as an example requiring transmission providers to report on its OASIS
in the aggregate its historical demand and its historical ability to
supply the relevant ancillary services. EEI offers that if the
Commission decides to pursue optional screen it should have a technical
conference.\90\
---------------------------------------------------------------------------

\87\ EPSA Comments at 6.
\88\ Id. at 7.
\89\ EEI Comments at 16.
\90\ EEI Comments at 15.
---------------------------------------------------------------------------

69. Powerex claims that the optional market power screen does not
appear workable in certain respects and is likely to result in too many
false positives.\91\ Powerex argues that establishing a test that is
overly restrictive, and that a majority of sellers

[[Page 46189]]

will not be able to satisfy, will create a significant administrative
burden that will continue to pose an obstacle to the development of
competitive markets for ancillary services.\92\ Powerex asserts that
when using market shares as a metric of market power, the proper
measurement is a seller's ability to supply relative to the total
potential supply of the overall market.\93\
---------------------------------------------------------------------------

\91\ Powerex Comments at 16.
\92\ Id. at 17.
\93\ Id. at 19.
---------------------------------------------------------------------------

70. Morgan Stanley argues that the optional market power screen
does not provide a complete picture of an entity's market power and
that it is more relevant to compare the amount of supply a seller
controls to the total supply available and the total market demand,
than it is to compare it to a single buyer's requirements.\94\ Morgan
Stanley claims that a seller actually could have greater market power
even if it only can serve a small portion of the buyer's aggregate
requirements if the buyer has no other viable options for procuring the
remaining portion of its ancillary service needs.\95\
---------------------------------------------------------------------------

\94\ Morgan Stanley Comments at 6.
\95\ Id. at 7.
---------------------------------------------------------------------------

71. Other commenters oppose the optional market power screen on the
basis that its need and usefulness is unclear. For example, TAPS argues
that the usefulness of the optional screen is uncertain, particularly
given the acknowledged data limitations. TAPS further argues that one
cannot be confident that the proxy would provide a meaningful screen
for market power.\96\
---------------------------------------------------------------------------

\96\ TAPS Comments at 14.
---------------------------------------------------------------------------

72. The California PUC states that is sees no need for alternative
methodologies and further argues that a 20 percent threshold is too
high for ancillary services.\97\ The Hydro Association also states that
it does not see a need at this time for the Commission to develop
alternative market screens.\98\
---------------------------------------------------------------------------

\97\ California PUC Comments at 5-6.
\98\ Hydro Association Comments at 8.
---------------------------------------------------------------------------

Commission Determination
73. The Commission will not adopt the optional market power screen
for ancillary services as proposed in the NOPR. As suggested by EEI,
ESPA and others, the fact that the proposed optional screen would not
consider the full amount of competing supply available to a buyer
likely means that the screen may result in so many false positive
indications of potential market power that it would provide little
benefit to the effort to foster competition in ancillary service
markets.
74. The comments also indicate that establishing the reporting
requirements associated with the optional market power screen would not
be a trivial task, particularly given the lack of consensus regarding
the granularity of information needed. The Commission believes that the
costs of developing and imposing this new reporting requirement on
transmission providers might not be justified, particularly in light of
the other actions taken in this Final Rule. The need for the proposed
optional screen, and its associated reporting requirement, is
significantly reduced because this Final Rule, as explained above, will
permit sellers to apply the existing market power screens to imbalance
and operating reserve ancillary services. As such, the Commission has
determined not to adopt the optional market power screen and its
associated reporting requirement.
Alternative Mitigation
75. In the NOPR, the Commission proposed to permit sellers unable
or unwilling to perform the market power study for ancillary services
to propose price caps at or below which sales of Regulation and
Frequency Response, Reactive Supply and Voltage Control, Operating
Reserve-Spinning, or Operating Reserve-Supplemental service would be
allowed where the purchasing entity is a public utility transmission
provider purchasing ancillary services to satisfy its OATT requirements
to offer ancillary services to its own customers.\99\ Such a price cap
would have been based on one of the two possible OATT ancillary service
rate caps discussed below and, as in Avista, the Commission proposed
that sales under these price caps would only be permitted in geographic
markets where the seller has been granted market-based rate authority
for sales of energy and capacity. In addition, a seller unable to
perform a market power study for ancillary services could rely on
competitive solicitations meeting certain minimum requirements in order
to make sales in geographic markets where the seller has been granted
market-based rate authority for sales of energy and capacity.
---------------------------------------------------------------------------

\99\ NOPR, FERC Stats. & Regs. ] 32,690 at PP 33-40.
---------------------------------------------------------------------------

Use of Price Caps
Commission Proposal
76. In the NOPR, the Commission proposed two cost-based mitigation
measures as alternatives to the prohibition adopted in Avista with
regard to sales to a public utility transmission provider that is
purchasing ancillary services to meet its OATT requirements to offer
ancillary services to its own customers. Sales of ancillary services at
or below either alternative would be permitted. Under the first, third
parties would be permitted to sell to a public utility transmission
provider at rates not to exceed the buying public utility transmission
provider's existing OATT rate for the same ancillary service. Under the
second option, third parties could propose to sell a given ancillary
service to a public utility transmission provider at rates not to
exceed the highest public utility transmission provider OATT rate
within the relevant geographic market for physical trading of the
ancillary service in question. The Commission proposed that the seller
(or group of sellers) would file with the Commission a proposal that
defines the scope of a contiguous geographic region that both
encompasses the service territory(ies) of the public utility
transmission provider whose OATT ancillary service rate will form the
basis for the price cap, and within which trading of the ancillary
service in question is physically possible.
Single OATT Rate Cap Option
Comments
77. There was a range of support for the establishment of a rate
cap at the buyer's OATT rate for the same ancillary service. TAPS and
Southern California Edison support this proposal outright as an option
to enable ancillary service sales.\100\ EEI states that while the
Commission should primarily rely on existing market power analyses and
screens to allow third-parties to sell certain ancillary services at
market-based rates, cost-based mitigation measures are also appropriate
in certain seller-specific circumstances. EEI states that these two
alternative options should be included in any Final Rule. EEI contends
that this flexibility should encourage an increased number of
participating sellers in bilateral markets, provide options for
transmission providers to meet obligations, create market efficiencies,
and potentially lower prices.\101\
---------------------------------------------------------------------------

\100\ TAPS Comments at 15-18 and Southern California Edison
Comments at 6.
\101\ EEI Comments at 18-19.
---------------------------------------------------------------------------

78. WSPP states that it supports inclusion of this option to
enhance flexibility in the sale of ancillary services, but with
reservations. WSPP's reservations essentially concern whether existing
OATT ancillary services rates provide appropriate price signals. WSPP
contends that because reserve sales are from the same units as energy
sales, mitigation price caps that

[[Page 46190]]

fail to take opportunity costs into account during peak periods are
unduly low.\102\ Separately, WSPP asks the Commission to clarify that
for the single OATT rate cap there is no filing with the Commission as
a prerequisite to the sale.\103\ AWEA and Solar Energy Association
either support the proposal or do not state opposition to it.\104\
Iberdrola supports WSPP's and AWEA's comments by reference.\105\
Electricity Consumers state that they do not object to the proposed
alternatives provided that they are in fact promulgated as alternatives
to the proposed revisions to the market power analysis.\106\
---------------------------------------------------------------------------

\102\ WSPP Comments at 15.
\103\ Id. at 14.
\104\ AWEA Comments at 3 and Solar Energy Association Comments
at 6.
\105\ Iberdrola Comments at 3.
\106\ Electricity Consumers Comments at 4.
---------------------------------------------------------------------------

79. Although ESA, Beacon, and California Storage Alliance all
support this proposal, they each argue that for this mitigation measure
to be successful in fostering robust competitive markets, the
Commission must ensure that cost-based schedules for ancillary
services, in particular Regulation and Frequency Response, are compared
on an ``apples-to-apples'' basis taking into account resource
performance.\107\
---------------------------------------------------------------------------

\107\ ESA Comments at 8-10; Beacon Comments at 7-9; and
California Storage Alliance Comments at 5-6.
---------------------------------------------------------------------------

80. Some commenters oppose this price cap proposal unless the cap
can be raised in some way. For example, Shell Energy argues that a cap
based on the buyer's OATT rate would not produce prices high enough to
entice competitive supply. Instead, Shell Energy suggests establishment
of a price cap set at 200 percent of the buyer's OATT rate for the
ancillary service in question.\108\ Similarly, EPSA asserts that cost-
based price caps systematically fail to represent the true value of
capacity products and will fail to allow a full range of economic
tradeoffs in the bilateral markets. EPSA states support for the use of
price caps as a last resort, and only if they reflect the seller's lost
opportunity costs as represented by energy transactions during a recent
historical period.\109\ Powerex makes similar arguments, favoring the
use of energy price indices to represent lost opportunity costs.
Failing that, Powerex argues that a component for transmission costs
for remote suppliers should be added to any OATT-based price cap.\110\
---------------------------------------------------------------------------

\108\ Shell Energy Comments at 8-9.
\109\ EPSA Comments at 9-10.
\110\ Powerex Comments at 25-29.
---------------------------------------------------------------------------

81. ENBALA argues that a cost-based cap limited to the buying
utility's OATT rate might be too restrictive and lead the Commission to
scrutinize more agreements than necessary, but ENBALA states that
``Reactive Supply and Voltage Control service should be excluded from
the regional price cap, being priced by the buying utility's OATT rate
to reflect the geographic limitations of the ancillary service.'' \111\
---------------------------------------------------------------------------

\111\ ENBALA Comments at 2-4.
---------------------------------------------------------------------------

Commission Determination
82. As one option available to sellers, the Commission will permit
market-based sales of Regulation and Frequency Response service and
Reactive Supply and Voltage Control service to public utility
transmission providers at rates not to exceed the buying public utility
transmission provider's OATT rate for the same service.\112\ We find
that a price cap based on the buying public utility transmission
provider's OATT rate for the same ancillary service would produce a
just and reasonable rate, and do so in a manner that is
administratively simple. As discussed in the NOPR,\113\ because the
buying public utility transmission provider's OATT ancillary service
rates have already been found to be just and reasonable, it is
reasonable to find that any third-party sales of the same ancillary
service to that buyer at or below that buyer's own approved rates for
that service would also be just and reasonable. Accordingly, we will
not require sellers to make a separate showing as to the justness and
reasonableness of such rates and will allow sellers to make third-party
sales of such services at rates as discussed here as of the effective
date of this Final Rule.
---------------------------------------------------------------------------

\112\ We do not apply this mitigation option to the other OATT
ancillary services because this Final Rule allows sales of those
services at market-based rates for any seller that has market-based
rate authority for energy and capacity.
\113\ NOPR, FERC Stats. & Regs. ] 32,690 at P 34.
---------------------------------------------------------------------------

83. Allowing the sale of ancillary services below the purchasing
public utility transmission provider's OATT rate is a reasonable
extension of the mitigation measure relied upon by the Avista policy
itself. As discussed earlier,\114\ the Avista policy sought to protect
buyers of third-party ancillary services from potential exercise of
market power by ensuring that they would continue to have access to
cost-based ancillary services from transmission providers, in effect
limiting the price at which customers are willing to buy ancillary
services from third-parties. The result of the Avista mitigation
measure is an implicit soft cap on the price at which third-party
ancillary services could be offered to non-transmission provider
customers. The price cap proposal adopted here extends this concept to
transmission providers by creating an explicit price cap at the same
level.
---------------------------------------------------------------------------

\114\ See supra P 7.
---------------------------------------------------------------------------

84. While a few commenters opine that a cap based on the buyer's
OATT rate would not produce prices high enough to entice competitive
supply, the Commission finds that, given the reforms adopted elsewhere
in this Final Rule, it is appropriate to take the more conservative
step of adopting a price cap based on the buyer's OATT rate for sales
of Regulation and Frequency Response service and Reactive Supply and
Voltage Control service to public utility transmission providers. This
measure can be implemented quickly and easily with few administrative
burdens on either the Commission or the industry. Alternative proposals
by commenters would require more complicated design, analysis, and
oversight to ensure that they achieve just and reasonable rates.
85. With respect to the arguments of ESA, Beacon, and California
Storage Alliance that for this mitigation measure to be successful, the
Commission must ensure that cost-based schedules for ancillary services
are compared on an ``apples-to-apples'' basis taking into account
resource performance, the Commission addresses this issue below in sub-
section B of this Final Rule.
Regional OATT Rate Cap Option
Comments
86. Some commenters, such as ESA, Beacon, and the California
Storage Alliance, support the regional OATT rate cap option on the
basis that it is a reasonable approximation of the cost of entry.\115\
ENBALA also expresses support for a regional cost-based rate cap,
arguing that it provides an adequate alternative to the current formal
market power requirement.\116\ EEI and Electricity Consumers also
express support for a regional OATT rate cap but offer no specific
recommendations.\117\
---------------------------------------------------------------------------

\115\ ESA Comments at 10; California Storage Alliance Comments
at 7; and Beacon Comments at 9.
\116\ ENBALA Comments at 2.
\117\ EEI Comments at 18-19; and Electricity Consumers Comments
at 4.
---------------------------------------------------------------------------

87. Southern California Edison states that it supports a cap based
on the highest OATT rate within the geographic market as long as it is
capped at the lesser of (a) the highest OATT rate in the market or (b)
three times the median OATT rate in the relevant geographic market.
Southern

[[Page 46191]]

California Edison explains that it proposes this modification to
protect against having a small balancing authority area with an
extremely high outlier rate setting the cap.\118\
---------------------------------------------------------------------------

\118\ Southern California Edison Comments at 6-7.
---------------------------------------------------------------------------

88. Other commenters criticize the highest OATT rate cap proposal.
Some parties, such as WSPP, EPSA, and Powerex, argue that setting caps
based on cost-based rates would not allow sellers to recover foregone
opportunity costs associated with energy sales and thus would fail to
create any incentives for sellers to enter ancillary service markets.
They argue that this is particularly true for short-term ancillary
service sales, given that opportunity costs vary materially for hourly,
daily, monthly, and seasonal periods, but these variations are not
reflected in OATT rates and therefore would not be reflected in the
cap.
89. For example, Powerex contends that any alternative price cap
must be high enough to create economic incentives for potential sellers
to forego other opportunities, namely, energy sales.\119\ Powerex
argues that setting price caps based on transmission providers' cost-
based rates in many instances will not allow sellers to recover the
foregone opportunity costs associated with energy sales and that this
is particularly true for short-term ancillary service sales.\120\
Powerex states that short-term energy prices in the CAISO and other
Western markets are frequently several-fold higher than Northwest
transmission providers' OATT rates for ancillary services.\121\
---------------------------------------------------------------------------

\119\ Powerex Comments at 26.
\120\ Id.
\121\ Id. at 27.
---------------------------------------------------------------------------

90. Similarly, EPSA argues that a price cap should include a
seller's lost opportunity costs, represented by energy transactions
during a recent historical period. EPSA states that it is critically
important to include lost opportunity costs, in order to allow a
generator to rationally choose between producing energy and not
producing energy.\122\
---------------------------------------------------------------------------

\122\ EPSA Comments at 9-10.
---------------------------------------------------------------------------

91. WSPP asserts that the Commission's observation that the OATT
rate could be indicative of the cost of new entry appears speculative.
WSPP contends that a cost-based rate may reflect a fully or
substantially depreciated unit, rather than the cost of new
construction.\123\ WSPP also argues that because reserve sales are made
from the same resources as energy sales, mitigation price caps that
fail to take opportunity costs into account during peak periods are
unduly low.\124\
---------------------------------------------------------------------------

\123\ WSPP Comments at 15.
\124\ Id. at 15.
---------------------------------------------------------------------------

92. Other commenters raise concerns about setting the geographic
boundaries for a regional OATT rate cap. Shell Energy asserts that
identifying the region in which an ancillary service can be physically
traded can be difficult and recommends that the Commission, rather than
sellers, identify the relevant trading regions and post that
information on the Commission's Web site.\125\ TAPS argues that a
regional price cap would invite gerrymandering and provide no assurance
that the resulting cap is a more reasonable approximation of the cost
of new entry.\126\ TAPS argues that significant physical constraints
limit the provision of ancillary services over a geographic area.\127\
TAPS contends that the regional OATT rate cap proposal is not
defensible as either a cost-based or market-based rate and is at odds
with the physical limitations on the provision of ancillary services in
non-RTO regions.\128\ TAPS contends that another regional transmission
provider's higher rate (i.e., the highest regional rate) does not bear
any relationship to either a third-party supplier's or the purchasing
transmission provider's cost of supply.\129\
---------------------------------------------------------------------------

\125\ Shell Energy Comments at 9.
\126\ TAPS Comments at 22.
\127\ Id. at 20.
\128\ Id. at 2.
\129\ Id. at 19.
---------------------------------------------------------------------------

Commission Determination
93. The Commission will not adopt the NOPR proposal that would
allow sellers to propose a price cap equal to the highest OATT rate
within a specified region. Based on the comments received, the
Commission concludes that use of a regional OATT rate cap would be
inadequate to ensure that third-party sellers' rates remain just and
reasonable. In the NOPR, the Commission suggested that this mitigation
proposal might be justified on a cost basis in that the highest
regional rate may be a reasonable approximation of the cost of new
entry into the region in question.\130\ However, the record developed
in this proceeding does not support such a conclusion at this time.
---------------------------------------------------------------------------

\130\ NOPR, FERC Stats. & Regs. ] 32,690 at P 36.
---------------------------------------------------------------------------

94. We also share commenters' concerns associated with defining
appropriate regions for purposes of setting regional price caps. The
Commission is concerned that sellers would have an incentive to
``gerrymander'' or ``cherry-pick'' regional definitions to ensure
inclusion of a high-cost ancillary service provider. In light of the
other actions taken in this Final Rule, the Commission believes it
would not be productive to undertake the analyses necessary to
establish seller-specific regions for various ancillary services.
Competitive Solicitations
Commission Proposal
95. The NOPR proposed to allow applicants to engage in sales to a
public utility that is purchasing ancillary services to satisfy its
OATT requirements to offer ancillary services to its own customers
where the sale is made pursuant to a competitive solicitation that
meets the following guidelines: (1) Transparency--the competitive
solicitation process should be open and fair; (2) definition--the
product or products sought through the competitive solicitation should
be precisely defined; (3) evaluation--evaluation criteria should be
standardized and applied equally to all bids and bidders; (4)
oversight--an independent third-party should design the solicitation,
administer bidding, and evaluate bids prior to the company's
selection;\131\ and (5) competitiveness--adequate seller interest to
ensure competitiveness.
---------------------------------------------------------------------------

\131\ See, e.g., Allegheny Energy Supply Co. LLC, 108 FERC ]
61,082 (2004).
---------------------------------------------------------------------------

Comments
96. Commenters generally support the proposal to permit competitive
solicitations as an alternative to performing a market power
study.\132\ EEI, for example, expresses support for competitive
procurement as an option for long-term resource planning.\133\ EPSA
states that the Commission's proposed guidelines for competitive
solicitations conform to general principles that EPSA has advocated for
such processes.\134\
---------------------------------------------------------------------------

\132\ EPSA Comments at 8-9; EEI Comments at 19-20; ESA Comments
at 10-11; Beacon Comments at 9-11; California Storage Alliance
Comments at 7; and ENBALA Comments at 4.
\133\ EEI Comments at 19-20.
\134\ EPSA Comments at 8-9.
---------------------------------------------------------------------------

97. Some commenters object to certain aspects of the Commission's
proposal. Most criticism is directed at the proposed requirement for
independent third-party oversight of competitive solicitations. WSPP,
for example, expresses support for competitive solicitations as a means
of mitigating potential market power concerns but opposes the proposed
oversight by an independent third party. WSPP argues that such
oversight is unnecessary, and that the required filing

[[Page 46192]]

is ample to demonstrate whether or not the solicitation yielded
sufficient competition.\135\ Shell Energy agrees that third-party
oversight of competitive solicitations is unnecessary, arguing that
this requirement would hinder short-term procurement of ancillary
services and make the solicitation process unfeasible except for long-
term transactions.\136\
---------------------------------------------------------------------------

\135\ WSPP Comments at 17-18.
\136\ Shell Energy Comments at 10.
---------------------------------------------------------------------------

98. However, Morgan Stanley contends that it is not clear that the
Commission's competitive solicitation proposal would protect against
market power. Morgan Stanley contends that a competitive solicitation
only demonstrates lack of market power if it is robust enough to
attract offers that, in aggregate, are significantly in excess of the
quantity sought. Morgan Stanley states that it is not clear how a
competitive solicitation could help buyers looking to purchase such
services on a short-term basis, although it might for the long-term
provision of ancillary services.\137\
---------------------------------------------------------------------------

\137\ Morgan Stanley Comments at 8-9.
---------------------------------------------------------------------------

Commission Determination
99. The Commission adopts the NOPR proposal to allow applicants to
engage in market-based sales of ancillary services to a public utility
that is purchasing ancillary services to satisfy its OATT requirements
where the sale is made pursuant to a competitive solicitation that
meets the requirements specified in the NOPR as numerated above, except
as modified below. The Commission has relied on the use of competitive
solicitations to mitigate affiliate abuse concerns when affiliates seek
to enter into transactions pursuant to market-based rate
authority.\138\ In that context, the Commission has adopted guidelines
for independent, third-party review of competitive solicitations. The
requirements proposed for sales of ancillary services to public utility
transmission providers are based on these guidelines, which the
Commission concludes are reasonable to adopt here with one exception.
Upon review of comments, we have decided to partially eliminate the
requirement that an independent third-party design and administer the
solicitation and evaluate bids prior to the company's selection.
---------------------------------------------------------------------------

\138\ See Boston Edison Co. Re: Edgar Electric Energy Co., 55
FERC ] 61,382 (1991); Allegheny, 108 FERC ] 61,082.
---------------------------------------------------------------------------

100. As proposed, the independent third-party review requirement
would apply to all competitive solicitations. However, the record does
not support imposing a requirement for independent third-party review
when none of the parties participating in a competitive solicitation is
affiliated with the buying public utility transmission provider. If no
affiliate of the buyer participates in the solicitation, there is no
concern regarding preferential treatment and, therefore, no need for
review by an independent third party. As commenters suggest, requiring
an independent third-party reviewer could discourage the use of
competitive solicitations as it would add to the cost and time needed
to procure ancillary services. Some public utility buyers may have a
short-term, unexpected need for ancillary services and therefore need
to act quickly to fill this need. In such cases, the buyer itself will
have to conduct the solicitation, with very limited time for
independent review. The Commission therefore revises the NOPR proposal
to require independent third-party review of competitive solicitations
only when the buyer solicits offers from one or more of its affiliates.
101. However, the Commission emphasizes that any buyer seeking to
procure ancillary services from unaffiliated sellers through a
competitive solicitation will need to demonstrate compliance with the
four other requirements: transparency, definition, evaluation, and
competitiveness. In this regard, we reject Morgan Stanley's assertion
that the competitiveness requirement can only be met where a
solicitation attracts offers that, in aggregate, are significantly in
excess of the quantity sought. We believe there may be multiple methods
of demonstrating adequate competitiveness, and we will review such
proposals on a case-by-case basis. This will help ensure that any
ancillary services procured in this manner are purchased at a
competitive market price. At the same time, these requirements will not
hinder buyers' flexibility to design solicitations to meet their
specific needs. This demonstration must be made through a filing under
section 205 of the Federal Power Act, submitted by the seller to the
Commission prior to commencement of service under the third-party
ancillary service sales agreement that results from the competitive
solicitation. To be specific, the third-party seller will need to
submit both the actual sales agreement and a narrative description of
how the buyer's competitive solicitation meets the requirements of this
Final Rule. This narrative description will help demonstrate that
exercise of market power was not a factor in the negotiation of the
sales agreement, and therefore that the resulting rate is just and
reasonable.

Resource Speed and Accuracy in Determination of Regulation and
Frequency Response Reserve Requirements

Commission Proposal
102. The Commission proposed in the NOPR to require that each
public utility transmission provider submit provisions for inclusion in
its OATT that take into account the speed and accuracy of regulation
resources in determining its Regulation and Frequency Response reserve
requirements. Among other things, this would allow customers choosing
to self-supply this service with faster responding or more accurate
resources to self-supply with a lower volume of regulation capacity, or
vice versa. The Commission stated that it expects to evaluate each
proposed determination of regulation reserve requirements on a case-by-
case basis. It also stated that each description of how the public
utility will adjust its regulation capacity requirement must provide
enough detail that an entity wishing to self-supply may compare the
resources it is considering using with the resources that the public
utility is using. The Commission sought comment on how speed and
accuracy should be taken into account.\139\
---------------------------------------------------------------------------

\139\ NOPR, FERC Stats. & Regs. ] 32,690 at PP 47-54.
---------------------------------------------------------------------------

Comments
103. A majority of commenters\140\ generally support the NOPR
proposal to require each public utility transmission provider to submit
provisions for inclusion in its OATT that take into account the speed
and accuracy of regulation resources in determining its Regulation and
Frequency Response reserve requirements. Electricity Consumers, Hydro
Association, Morgan Stanley, California PUC, and EPSA highlight the
benefits of increased transparency, to which EPSA adds that lack of
transparency is an impediment to competitive compensation outside of
ISOs/RTOs and contributes to a lack of a discernible market value for
speed and accuracy. Other commenters, including Public Interest
Organizations, Iberdrola, Morgan Stanley, and FTC Staff cite avoidance
of undue discrimination, comparable treatment, and the potential that
the NOPR proposal will encourage innovation and new entry, as reasons
for

[[Page 46193]]

supporting the proposal. Solar Energy Association supports taking into
account the speed and accuracy of regulation resources when
establishing the rates that may be charged for those services, with
faster and more accurate resources priced accordingly.\141\
---------------------------------------------------------------------------

\140\ These commenters include Beacon, California Storage
Alliance, ESA, Hydro Association, Solar Energy Association, Public
Interest Organizations, California PUC, AWEA, Morgan Stanley, EPSA,
TAPS, FTC Staff, Electricity Consumers, and Iberdrola.
\141\ Solar Industry Association Comments at 3.
---------------------------------------------------------------------------

104. Hydro Association supports the idea of ``pay for performance''
standards that recognize the difference between accurate fast-
responding resources versus resources that ramp more slowly and respond
less nimbly, and agrees with the Commission that a case-by-case
evaluation of each proposed determination is more appropriate than
imposing a mandatory methodology. Similarly, California PUC states that
transparency should act as a deterrent against discrimination, but
cautions that the Commission should avoid an overly prescriptive
methodology that may dictate the amount of regulation resources that
are needed.
105. Several other commenters, including Beacon, ESA, California
Storage Alliance, and Morgan Stanley, encourage the Commission to
require transmission providers to provide an explanation of how they
set their regulation reserve requirements. ESA, Beacon, and California
Storage Alliance propose five elements of an explanation that each
transmission provider should be required to provide about how it sets
its regulation reserve requirement,\142\ as well as a list of specific
information that each transmission provider should make available.\143\
Morgan Stanley also urges the Commission to require public utility
transmission providers to provide demonstrations of equivalent
treatment for their own or their affiliate's requirements to ensure
that there is no undue discrimination, and to establish a process for
market participants to challenge and resolve the speed and accuracy
assumptions and requirements that public utility transmission providers
publish.\144\ Beacon and ESA also state that ideally the Commission
would require each utility to develop a conversion formula or chart
that specifies how much capacity a transmission customer must self-
supply given a certain ramp-rate and accuracy.
---------------------------------------------------------------------------

\142\ The five elements are: (1) A description of the
calculation; (2) the metric which is used to set the requirement;
(3) the average performance of the existing Regulation assets; (4)
the speed and accuracy of the units currently in place (including
ramp-rate and accuracy); and (5) sufficient data for a third party
to reproduce the results, including posting ACE data on its OASIS
reporting. ESA Comments at 12-13; Beacon Comments at 12; and
California Storage Alliance Comments at 6.
\143\ Each entity proposes a bulleted list of nine items
including generation capacity available to provide regulation,
rates, costs, accuracy and CPS scores, and representative ACE data.
ESA Comments at 13; and Beacon Comments at 12-13.
\144\ Morgan Stanley Comments at 10.
---------------------------------------------------------------------------

106. ESA, Beacon, Public Interest Organizations, California Storage
Alliance, and AWEA advocate extending the requirement of accounting for
speed and accuracy in regulation service to public utilities meeting
their own needs, including via third-party suppliers, not simply to
transmission customers choosing to self-supply.\145\ AWEA argues that
holding more reserves than needed may result in rates that are not just
and reasonable.\146\ ESA, Beacon, Public Interest Organizations, and
California Storage Alliance state that third party sales to a public
utility that is purchasing ancillary services to satisfy its own OATT
requirements to offer ancillary services to its own customers
represents the most significant potential market for sales of ancillary
services in non-RTO/ISO regions. Public Interest Organizations agree,
arguing that neither the current rules nor the NOPR encourage
transmission providers to improve the speed and accuracy of their owned
or contracted frequency regulation resources, and that allowing
generators to be displaced from providing frequency regulation will
enable them to operate at a more stable output, which also can lower
energy market prices. Public Interest Organizations contend that the
existing OATT Schedule 3 rate treatment is no longer adequate to
incorporate emerging technologies, and encourage the Commission to
require that OATT Schedule 3 rates incorporate Order No. 755's
framework of an objective accuracy and performance determination, and
that the amount of frequency regulation transmission customers are
required to procure or self-supply takes into account the speed and
accuracy capability of the ancillary service provider's
technology.\147\
---------------------------------------------------------------------------

\145\ Beacon and Public Interest Organizations support ESA's
comments regarding third party sales of regulation.
\146\ AWEA Comments at 4.
\147\ Public Interest Organizations Comments at 8.
---------------------------------------------------------------------------

107. Parties that support extending the proposal to public utility
transmission providers meeting their own needs also recommend that the
Commission consider performance-based rate treatment for public utility
investments and contracts with third-party ancillary service providers
that allow the public utility to reduce the total capacity and cost of
providing regulation service while maintaining the same level of
reliability.\148\ They argue that the potential benefits to ratepayers
could justify allowing a performance-based incentive rate adder that
public utility transmission providers could recover through rates, and
that if the public utility can demonstrate that it will be able to
reduce the total capacity and cost of providing regulation service and
maintain the same degree of reliability, such treatment should result
in public utilities improving the performance of their regulation fleet
and in turn reducing expenses for frequency regulation, ultimately
resulting in lower costs.
---------------------------------------------------------------------------

\148\ See comments of ESA, Beacon, Public Interest
Organizations, and California Storage Alliance.
---------------------------------------------------------------------------

108. TAPS asks the Commission to state explicitly that the NOPR's
proposal to account for the speed and accuracy of customer self-
supplied regulating resources includes demand resources and to state
that such a finding would be consistent with OATT Schedule 3 and Order
No. 755.\149\
---------------------------------------------------------------------------

\149\ TAPS Comments at 27.
---------------------------------------------------------------------------

109. EEI opposes the NOPR proposal. It contends that it is
premature to require each transmission provider to include provisions
in its OATT explaining how it will determine Regulation and Frequency
Response requirements, and requests that the Commission defer this
proposal pending experience with secondary frequency control (i.e.,
regulation) in the ISOs and RTOs following the issuance of Order No.
755.\150\ EEI requests that the Commission recognize the material
differences between primary and secondary frequency control resources
in the final rule. It argues that it is also premature to adopt
requirements regarding primary frequency control, and recommends that
the Commission encourage each balancing authority to continue
investigating the role of various types of resources, and allow the
industry to maintain its efforts to understand the relationship and
interdependencies between primary and secondary frequency response.
---------------------------------------------------------------------------

\150\ EEI Comments at 22-26.
---------------------------------------------------------------------------

110. EEI contends that the assumption that faster responding
technologies are necessarily more efficient than traditional methods of
frequency regulation has not been substantiated. EEI explains that
industry is still exploring frequency response, including current and
historical primary and secondary control response performance, and that
for system reliability it is important to maintain a balanced portfolio
of resources including inertial response, governor response, and
secondary frequency control (or regulation response). It further
explains that, although OATT Schedule 3 groups primary and secondary
frequency control into a single service, the nature of these

[[Page 46194]]

services are distinct. With regard to secondary frequency control
(regulation), EEI claims that the benefits from resources that ramp
more quickly for purposes of secondary frequency control may be offset
by a lack of capability to sustain that response, or to provide
automatic primary frequency control.
Commission Determination
111. The Commission will adopt the NOPR proposal with modification.
Rather than requiring OATT Schedule 3 to include a description of how
resource speed and accuracy will be taken into account in determining
Regulation and Frequency Response reserve requirements, we will require
each public utility transmission provider to add to its OATT Schedule 3
a statement that it will take into account the speed and accuracy of
regulation resources in its determination of reserve requirements for
Regulation and Frequency Response service, including as it reviews
whether a self-supplying customer has made ``alternative comparable
arrangements'' as required by the Schedule. This statement will also
acknowledge that, upon request by the self-supplying customer, the
public utility transmission provider will share with the customer its
reasoning and any related data used to make the determination of
whether the customer has made ``alternative comparable arrangements.''
\151\ To aid the transmission customer's ability to make an ``apples-
to-apples'' comparison of regulation resources, the Commission will
also amend Part 35 of its Regulations by adding a new section (k) to
Sec. 37.6,\152\ to require each public utility transmission provider
to post certain Area Control Error (ACE) data described further below.
We find that these reforms are necessary to address the potential for
undue discrimination in the provision of Regulation and Frequency
Response, including in instances when a customer self-supplies this
service using its own resources or purchases from a third-party.
Acknowledging the speed and accuracy of the resources used to provide
this service will help to ensure that an appropriate quantity of
resources is utilized for self-supply, whether those resources are
faster and more accurate or slower and less accurate than those used by
the public utility transmission provider. The weight of comments
support reform in this area, including arguments that such a reform
will help foster innovation and the entry of newer resources into the
market.
---------------------------------------------------------------------------

\151\ See Appendix B for the revised Schedule 3 of the pro forma
OATT provisions consistent with this Final Rule.
\152\ This regulation will replace the like-numbered proposed
regulation related to historical ancillary service requirements data
posting from the NOPR that we decline to adopt in section II.A.1.b.
of this Final Rule.
---------------------------------------------------------------------------

112. Under the current pro forma OATT, transmission customers
considering using their own or third-party resources to self-supply
regulation service are required to demonstrate to the public utility
transmission provider that they have made ``alternative comparable
arrangements.'' However, the pro forma OATT provides no further
information as to how the determination of ``alternative comparable
arrangements'' would be made. Moreover, the OATT contains no express
obligation on the part of the transmission provider to consider the
relative speed and accuracy of resources a customer might desire to use
in self-supplying Regulation and Frequency Response service. A public
utility transmission provider could require a customer seeking to self-
supply regulation services to provide a volume of regulation reserves
based on the characteristics of the resources used by the public
utility transmission provider to provide regulation service, which may
not be reflective of the characteristics of the customer's resources.
This could under- or overstate regulation reserve requirements
depending on the relative characteristics of the resources at issue. It
also could impair the customer's ability to self-supply regulation
requirements at the lowest possible cost.\153\ The Commission finds
that this lack of clarity as to the role of resource speed and accuracy
in the determination of ``alternative comparable arrangements'' for
regulation reserve requirements for self-supplying transmission
customers must be addressed in order to limit opportunities for
potential discrimination in the provision of regulation service by
public utility transmission providers.
---------------------------------------------------------------------------

\153\ For example, a self-supplying customer could save money
either by relying on a smaller amount of high quality regulation
resources at a slightly higher per-unit price or by relying on a
larger amount of lower quality regulation resources at a much lower
per-unit price. Provided that reliability is maintained, the
transmission customer should have the ability to self-supply
consistent with its preferences.
---------------------------------------------------------------------------

113. While the Commission initially proposed that each public
utility transmission provider should amend its OATT to include a
description of how regulation reserve requirement determinations would
take into account speed and accuracy of resources, we believe the
better course of action at this time is to place the obligation on the
public utility transmission provider to take into account speed and
accuracy without requiring it to develop detailed tariff language
describing the specific process to be used. This will provide the
public utility transmission provider with flexibility while also
providing the customer with information. While a number of commenters
suggested elements for what the public utility transmission provider
should be required to provide, the clearest proposal in the comments
related to this issue request that public utility transmission
providers be required to provide current monthly and 12-month rolling
average Control Performance Standard 1 (CPS1), Control Performance
Standard 2 (CPS2) and Balancing Authority ACE Limit (BAAL) scores for
Frequency Regulation.\154\ However, by itself availability of such
information would do nothing to explain how the public utility
transmission provider determines regulation reserve amounts.
Furthermore, while ACE information might help to characterize the speed
and accuracy of the public utility transmission provider's own
regulation resources, the Commission believes that using the relatively
long duration of monthly and 12-month rolling ACE averages implicit in
these scores may not provide information useful for measuring
performance over a fraction of an hour, which is the relevant time
frame for Regulation and Frequency Response service.
---------------------------------------------------------------------------

\154\ CPS1 and CPS2 are described in NERC Reliability Standard
BAL-001-0.1a--Real Power Balancing Control Performance. The BAAL
criterion is expected to replace CPS2 in that Reliability Standard
when it becomes effective, pending final approval by NERC and the
Commission.
---------------------------------------------------------------------------

114. Accordingly, the Commission declines to impose a ``one size
fits all'' approach to calculating regulation reserve requirements,
consistent with the comments of Hydro Association and California PUC,
and declines to require the inclusion of this process in Schedule 3.
Rather, we require that Schedule 3 be amended to include a statement
that the public utility transmission provider will take into account
the speed and accuracy of regulation resources in determining reserve
requirements for Regulation and Frequency Response service, including
when reviewing whether a self-supplying customer has made ``alternative
comparable arrangements.'' Self-supplying customers and their public
utility transmission providers will then have a basis to study and
negotiate appropriate arrangements case-by-case, very similar to how
such

[[Page 46195]]

interactions take place under other processes such as the
interconnection process.
115. That said, we agree with the comments of ESA, Beacon, and
California Storage Alliance that transmission customers considering
whether or not there would be any economic advantage to self-supply of
Regulation and Frequency Response service requirements would need to be
able to make an ``apples-to-apples'' comparison of their resources to
those of their public utility transmission provider.\155\ Doing so
would require the transmission customer to know both the potential
avoided cost of purchasing from its public utility transmission
provider, and some measure of the speed and accuracy of the public
utility transmission provider's Regulation resources. The first
requirement is met through the rate filed in the public utility
transmission provider's OATT Schedule 3. We believe the second
requirement can only be met through a new OASIS posting requirement.
---------------------------------------------------------------------------

\155\ ESA Comments at 8-10; Beacon Comments at 7-9; and
California Storage Alliance Comments at 5-6.
---------------------------------------------------------------------------

116. As noted earlier, the public utility transmission provider's
CPS1, CPS2, and BAAL scores might address this need in concept, except
that they currently reflect long-term averages that do not match the
relevant time frame for Regulation and Frequency Response service. We
believe the one-minute and ten-minute average ACE data collected by
public utility transmission providers to produce the CPS1, CPS2, and
BAAL scores would be more useful for this purpose because it does match
the relevant time frame. Accordingly, in order to ensure a level of
transparency adequate to support self-supply decision-making by
transmission customers, we will require public utility transmission
providers to post historical one-minute and ten-minute ACE data on
OASIS. For this purpose, we find that historical data for the most
recent calendar year, updated once per year, should meet the need. This
information is already collected and provided to NERC, through
balancing area operators and reliability coordinators, so there should
be minimal incremental burden associated with posting it on OASIS.
117. The Commission's standard filing requirements, including
opportunity for intervention and comment, address Morgan Stanley's
request to establish a process for market participants to challenge and
resolve speed and accuracy assumptions. For example, as is the case in
interconnection agreement proceedings, the transmission service
agreement that reflects an individually negotiated self-supply
arrangement for Regulation and Frequency Response service can be filed
by the public utility transmission provider unexecuted. This will leave
the transmission customer free to protest relevant aspects of the
public utility transmission provider's determination of whether the
customer has made ``alternative comparable arrangements,'' including as
those arrangements relate to the speed and accuracy of the customer's
proposed Regulation resources.
118. With respect to Morgan Stanley's request that public utilities
demonstrate equivalent treatment for their own or their affiliate's
regulation requirements, we find that the increased transparency
required by this Final Rule will accomplish this goal. The requirements
adopted above apply to the public utility transmission provider's own
regulation resources, in the sense that it must apply the same
procedures for determining regulation reserve requirements to itself as
it does to self-supplying customers.
119. With respect to the request of TAPS that the Commission state
explicitly that the NOPR's proposal to account for the speed and
accuracy of customer self-supplied regulating resources includes demand
resources, we note that OATT Schedule 3, as amended by Order No. 890
makes clear that Regulation and Frequency Response service may be
provided from non-generation resources capable of providing the
service. Accordingly, a transmission provider's determination of
regulation reserve requirements should take into account the speed and
accuracy characteristics of the resources in question, whether they are
generation-based or otherwise.
120. Turning to the various requests that the Commission step
beyond the NOPR proposals, the Commission declines to require two-part
pricing for regulation capacity and performance set forth in Order No.
755. We conclude that the requirements adopted above will allow
customers and the Commission to ensure that the speed and accuracy of
resources used for regulation reserves are properly taken into account
in reserve level determinations within the context of the bilateral
markets within which non-RTO/ISO public utility transmission providers
operate. The Commission also declines commenter requests to provide
incentive rate treatment for purchases of Regulation and Frequency
Response service by public utility transmission providers to meet their
OATT requirements. Commenters are not clear as to what mechanism they
believe the Commission should use to require such treatment, and the
Commission sees no reason to implement an incentives program in the
context of ancillary services rate design.
121. With respect to EEI's comments regarding differences between
primary frequency response and secondary frequency regulation, the
Commission acknowledges these distinctions. Improving the transparency
regarding the resources used to provide Regulation and Frequency
Response service under OATT Schedule 3 does not alter the ability of
any balancing authority to maintain adequate reserves to meet
reliability requirements. The Commission thus sees no need to wait for
the industry to better understand the relationship and
interdependencies between primary and secondary frequency response
prior to adopting the requirements of this final rule. The Commission
will evaluate a public utility transmission provider's compliance
proposal as part of the case-by-case review discussed above, which will
provide the public utility transmission provider the opportunity to
demonstrate how it establishes its regulation reserve requirements.

Accounting and Reporting for Energy Storage Operations

122. In the NOPR, the Commission proposed to revise certain
accounting and reporting requirements under its USofA and its forms,
statements, and reports contained in Form Nos. 1, 1-F, and 3-Q. The
Commission stated that the revisions were needed so that entities
subject to the Commission's accounting and reporting requirements could
better account for and report transactions associated with energy
storage devices used in public utility operations. Moreover, the
Commission noted that this information is important in developing and
monitoring rates, making policy decisions, compliance and enforcement
initiatives, and informing the Commission and the public about the
activities of entities subject to the accounting and reporting
requirements.
123. The Commission proposed that new electric plant and associated
O&M expense accounts be created to provide for the recording of
investment and O&M costs of energy storage assets. The Commission also
proposed to create a new purchased power account to provide for
recording the cost of power purchased for use in storage operations. In
addition, the Commission proposed that new Form Nos. 1 and 1-F
schedules be created and existing schedules in the forms and Form No.
3-

[[Page 46196]]

Q be amended to report operational and statistical data on storage
assets. Finally, the Commission inquired about whether entities seeking
to recover costs of energy storage assets and operations simultaneously
under cost-based and market-based rates should be required to forego
previously granted accounting and reporting waivers associated with
market-based rates, and if so, should the requirement to forego the
waivers be subject to some percentage threshold based on a ratio of
cost-based cost recovery to total cost to be recovered.
124. While most commenters support the Commission's proposal to
revise the accounting and reporting requirements, there were several
recommendations to make adjustments to the proposals and also requests
for clarification of certain proposals. Only Solar Energy Association
opposed the proposal, stating, without elaboration, that it believes it
is premature to establish reporting requirements for energy
storage.\156\ In the NOPR, the Commission responded to similar
arguments regarding maturity of the energy storage industry as it
relates to the use of energy storage assets to provide public utility
services, and found those arguments unconvincing.\157\ The Commission
explained that there is a need for certainty in the accounting and
reporting treatment for energy storage assets and operations,
especially in instances where utilities seek to recover costs of energy
storage operations in cost-based rates. Solar Energy Association has
not provided new information that we could consider on this issue,
therefore we find Solar Energy Association's argument unconvincing.
---------------------------------------------------------------------------

\156\ Solar Energy Association Comments at 7.
\157\ NOPR, FERC Stats. & Regs. ] 32,690 at P 71.
---------------------------------------------------------------------------

1. Electric Plant Accounts
Commission Proposal
125. In the NOPR, the Commission stated that the existing primary
plant accounts do not explicitly provide for recording the cost of
energy storage assets. The Commission concluded that this could lead to
inconsistent accounting and reporting for these assets by utilities
subject to the accounting and reporting requirements, making it
difficult for the Commission and others to determine costs related to
energy storage assets for cost-of-service rate purposes. The Commission
also noted that the lack of transparency affects interested parties',
including the Commission's, ability to monitor these utilities'
operations to prevent and discourage cross-subsidization between cost-
based and market-based activities. To address these issues, the
Commission proposed to create electric plant accounts in the existing
functional classifications--production, transmission, and
distribution--for new energy storage assets.\158\
---------------------------------------------------------------------------

\158\ Account 348, Energy Storage Equipment-Production; Account
351, Energy Storage Equipment--Transmission; and Account 363, Energy
Storage Equipment--Distribution, respectively.
---------------------------------------------------------------------------

126. The Commission proposed that the installed costs of energy
storage assets be recorded in the accounts based on the function or
purpose the asset serves. On this basis, an asset that performs a
single function will have its cost recorded in a single plant account.
In instances where an energy storage asset is used to perform more than
one function or purpose, the Commission proposed that the cost of the
asset be allocated among the relevant energy storage plant accounts
based on the functions performed by the asset and the allocation of the
asset's costs through cost-based rates that are approved by a relevant
regulatory agency, whether federal or state.\159\
---------------------------------------------------------------------------

\159\ NOPR, FERC Stats. & Regs. ] 32,690 at P 81.
---------------------------------------------------------------------------

Comments
127. In general, the commenters applaud the Commission's efforts to
improve transparency and prevent double-recovery of energy storage-
related costs. The proposal to require utilities to record the costs of
single-function energy storage assets in a single plant account
garnered widespread support. However, the proposal to require utilities
to allocate the costs of multi-function energy storage assets to the
relevant energy storage plant accounts based on the functions performed
and approved rate recovery, received comments supporting and opposing
the proposal. Commenters that agree with the proposal generally
indicate that the accounting would provide necessary transparency of a
utility's operations,\160\ while commenters that oppose the proposal
generally indicate that the accounting would place an undue
administrative burden on utilities and is inconsistent with the
Commission's existing accounting rules.\161\
---------------------------------------------------------------------------

\160\ Public Interest Organizations Comments at 9-10; California
PUC Comments at 9; NU Companies Comments at 4; APPA Comments at 5;
ESA Comments at 18-19; TAPS Comments at 28-29; and California
Storage Association Comments at 11-12.
\161\ Southern California Edison Comments at 8; SDG&E Comments
at 2-3; and EEI Comments at 29-30.
---------------------------------------------------------------------------

128. Public Interest Organizations state that they support the
development of requirements that can reveal the activities and costs of
energy storage operations thorough greater transparency and detail.
California PUC similarly states that in the event an energy storage
developer intends to use a facility to perform multiple functions, the
proposed accounting and reporting should provide transparency. NU
Companies state that they support flexible rate treatment for energy
storage assets and believe the proposed accounting will provide
transparency required to guard against inappropriate cross
subsidization of various services and double recovery cost.
129. In opposition to the proposal, SDG&E contends that while it
generally agrees with the Commission's allocation ``concept'' to
account for energy storage assets by functional category, i.e.,
production, transmission, and distribution, it is concerned that
generally applicable financial tools may not be able to efficiently
track or monitor up to three functional categories for one asset
without increased and ongoing manual intervention.\162\ SDG&E argues
that it agrees that the initial allocation concept would capture
expenses by each function as the Commission intends; however, if the
utility subsequently changes its initial allocation in the future the
proposed accounting would create an unnecessary administrative burden
that if a mistake is made could result in costs of the asset being
stranded. SDG&E contends that to ensure the asset is accounted for
properly so that asset costs are not stranded, a utility would be
required to continuously monitor the asset to make sure its initial
allocation is consistent with the asset's actual usage. SDG&E
acknowledges that the NOPR addresses this concern; \163\ however, SDG&E
asserts that there is a more straightforward approach that can be used
to allocate the costs of a multi-function energy storage asset. SDG&E
advocates, instead of using multiple plant accounts, that the cost of
an energy storage asset be recorded in a single plant account and its
cost allocated to the various functions it performs using current
ratemaking methods.
---------------------------------------------------------------------------

\162\ SDG&E Comments at 2-3.
\163\ SDG&E cites to the NOPR proposal that a utility transfer
reallocated cost of an energy storage asset in accordance with the
instructions of Electric Plant Instruction No. 12, Transfers of
Property, 18 CFR Part 101 (2012). See SDG&E Comments at 3-4 (citing
to NOPR, FERC Stats. & Regs. ] 32,690 at P 82).
---------------------------------------------------------------------------

130. Similar to SDG&E, Southern California Edison and EEI also
complain of an increased administrative burden resulting from
allocating an energy

[[Page 46197]]

storage asset's cost across multiple plant accounts as proposed in the
NOPR. Southern California Edison and EEI contend that it would be
necessary to create multiple unique property records for an energy
storage asset to allocate its costs across multiple functions. Southern
California Edison and EEI argue that having multiple records for each
asset would require significant manual intervention while providing
little practical value.\164\ Additionally, Southern California Edison
and EEI assert, without providing any detail, that the NOPR proposal is
inconsistent with the general principle that each asset should have a
single record within an accounting system.\165\ Southern California
Edison and EEI contend that there is neither a precedent for creating
multiple property records for a single asset, nor a precedent for
creating a record for a partial asset. Further, EEI argues that to the
extent the different functions the cost of an energy storage asset
could be spread across are subject to different depreciation rates, a
single asset with a unique, individual economic life would be
depreciated over multiple periods.
---------------------------------------------------------------------------

\164\ Southern California Edison Comments at 8; and EEI Comments
at 30.
\165\ Southern California Edison Comments at 8 and n 8 citing
Definition No. 8 Paragraph (A)(5), Continuing Plant Inventory
Record, 18 CFR Part 101 (2012); and EEI Comments at 30.
---------------------------------------------------------------------------

131. EEI indicates that while it generally opposes the NOPR's
proposed accounting, it believes that in some circumstances the
proposal may be a practical alternative for companies desiring to use
it.\166\ Therefore, EEI advocates that utilities be afforded two
options to account for energy storage assets that are used to perform
multiple functions. EEI proposes that utilities be allowed to either:
(1) Record the costs of multi-function storage asset costs as proposed
in the NOPR or (2) record the costs of the assets in a single plant
account based on the primary function of the asset and to allocate
costs to specific functions performed through the ratemaking process.
Moreover, EEI recommends that the Form Nos. 1, 1-F, and 3-Q be amended
to provide for reporting the option each company uses. EEI contends
that allowing both options will afford companies the ability to
maintain accounting and reporting records in the most efficient manner
while providing transparency via reporting and uniformity in the
ratemaking process.
---------------------------------------------------------------------------

\166\ EEI Comments at 29-31.
---------------------------------------------------------------------------

132. Southern California Edison supports EEI's option (2). Southern
California Edison and EEI contend that the option (2) approach is
consistent with the approach used for certain assets that provide both
state-jurisdictional and FERC-jurisdictional functions.\167\ Southern
California Edison and EEI explain that the ratemaking process may
include a formula or special study in order to appropriately allocate
the costs across functions.
---------------------------------------------------------------------------

\167\ Southern California Edison Comments at 8; and EEI Comments
at 31-32.
---------------------------------------------------------------------------

Commission Determination
133. SDG&E's, Southern California Edison's, and EEI's arguments
that requiring utilities to allocate the costs of energy storage assets
that perform multiple functions across the relevant energy storage
plant accounts places an undue administrative burden on utilities are
unpersuasive. These commenters generally argue that this perceived
undue administrative burden results from a requirement that utilities
maintain records that track the usage of energy storage assets and
costs associated with such use. However, utilities would be required to
maintain records with this information whether accounting for the costs
of an asset in multiple accounts as proposed in the NOPR or accounting
for the costs in a single account as proposed by SDG&E, Southern
California Edison and EEI. For example, information on the allocation
of the cost of an energy storage asset to a particular function will
have to be maintained by utilities operating multi-function, multi-cost
recovery energy storage assets, regardless of whether the information
is required to be reported in the reporting forms as proposed in the
NOPR or if the information is not reported in the forms yet is used in
ratemaking determinations as proposed by SDG&E, EEI, and Southern
California Edison. Because utilities with energy storage operations
that recover any portion of costs on a cost-of-service basis will be
required to maintain use and cost allocation information on the assets,
requiring these utilities to implement the NOPR's accounting proposal
does not result in an additional burden on utilities that could be
considered unduly burdensome.
134. Moreover, SDG&E's argument that costs could possibly be
stranded if a utility does not appropriately account for energy storage
operations is also unconvincing. This possibility exists throughout the
utility industry and is not uniquely attributable to utilities with
energy storage operations. Administrative errors, such as errors in
accounting, that lead to costs being stranded due to inadequate or
insufficient internal controls over policies, practices, and procedures
used to track costs associated with assets represent a risk for all
utilities whether or not the utilities own energy storage assets. Risks
of this nature are inherent to all utilities' operations. Utilities
must maintain adequate, sufficient, and reliable internal controls to
reduce the probability of this risk affecting operations.
135. As support for their argument that the NOPR's proposed
accounting causes an undue administrative burden and that their
advocated accounting avoids the burden, Southern California Edison and
EEI contend that their proposal to record the costs of an energy
storage asset in a single plant account could require utilities to
implement a formula or special study to appropriately allocate the
costs of the asset across multiple functions. However, this contention
does not support their argument. A formula or special study would
require utilities to maintain the same information on the functions
performed by an energy storage asset and costs associated with such
performance, as would be required by the NOPR's proposed accounting.
Thus, a formula or special study would not avoid the administrative
burden associated with accounting for energy storage assets and
operations. Furthermore, Southern California Edison and EEI have not
provided information to support a determination that the burden would
be decreased by implementing their proposed accounting. Their proposal
would result in less transparent reporting of information on energy
storage operations as compared to the NOPR's proposed accounting.
136. While the commenters argue that the accounting proposal might
require increased manual intervention to account for and report storage
assets, it is not clear that such intervention, if any, results in an
undue administrative burden. As the Commission observed in the NOPR,
uniform, transparent, and consistent reporting of information on energy
storage operations by utilities is essential, especially by those
seeking to recover costs of energy storage services in cost-based
rates.\168\ We believe that adopting the NOPR's proposed accounting and
reporting revisions will improve transparency.\169\ The revisions will
enhance the Commission's and other form users' ability to make a
meaningful assessment of a utility's cost-of-service rates, and will
provide for better monitoring for cross-subsidization. In instances
where an energy storage asset performs multiple

[[Page 46198]]

functions, it is imperative that costs associated with each function be
transparent and allocable to the function performed so that cross-
subsidization of costs can be prevented. SDG&E, EEI, and Southern
California Edison have not provided information that would refute the
Commission's determination in the NOPR that the accounting proposal is
not overly burdensome.
---------------------------------------------------------------------------

\168\ NOPR, FERC Stats. & Regs. ] 32,690 at P 71.
\169\ Id. P 72.
---------------------------------------------------------------------------

137. EEI's recommendation that utilities be afforded two options to
account for and report storage assets that provide multiple services
and recover associated costs simultaneously under cost-based and
market-based rate methods is not consistent with the intent of the
NOPR's proposed accounting and reporting revisions. The NOPR proposed
one method to account for energy storage assets performing multiple
functions under multiple cost recovery mechanisms to ensure that
utilities account for the assets on a uniform and consistent basis.
EEI's proposal for two methods of accounting could result in similarly-
situated utilities with energy storage assets reporting the same type
of transaction differently. This would not provide the uniformity
sought by the accounting and reporting proposals and could disrupt
consistency, which would make it difficult to compare utilities with
energy storage operations across the industry. In addition, adopting
EEI's proposal to record the costs of the assets in a single account
would reduce the transparency of information reported in the forms.
This information is critical to the clarity and transparency needed to
support a reasonable analysis of a utility's cost. Consequently, we
will not adopt EEI's proposal.
138. Southern California Edison's assertion that the NOPR
requirement adopted here is not consistent with Definition No. 8,
Continuing Plant Inventory Record, is incorrect.\170\ While the
definition pre-dates the NOPR's accounting and reporting requirements,
the definition is broad enough such that its premise is as relevant for
energy storage assets as it is for conventional electric plant assets.
The accounting and reporting proposals require utilities to maintain a
detailed record of the descriptive operational and cost information
associated with energy storage assets consistent with the provisions of
Definition No. 8.
---------------------------------------------------------------------------

\170\ 18 CFR Part 101 (2012).
---------------------------------------------------------------------------

139. Further, Southern California Edison's and EEI's contentions
that there is no precedent for creating multiple property records for a
single or partial asset misconstrues the proposed accounting and
reporting requirements. The accounting and reporting proposals we adopt
here do not require utilities to maintain multiple records for a single
or partial asset as Southern California Edison and EEI contend. Rather,
the reforms maintain the existing requirement of Definition No. 8 that
utilities maintain descriptive operational and cost information on each
asset. Moreover, we do not consider allocating the cost of a single
asset to multiple property accounts to be the same as creating multiple
property records as though there were multiple assets. A utility can
maintain information on a single energy storage asset with costs
allocated to multiple plant accounts in a single record that provides
descriptive operational and cost information on the asset.
Additionally, in accordance with General Instruction No. 12, Records
for Each Plant, utilities are required to maintain a record, by
electric plant accounts, on the book costs of each plant owned.\171\
The requirement to record the cost of a multi-function, multi-cost
recovery energy storage asset to more than one plant account is
consistent with this instruction.
---------------------------------------------------------------------------

\171\ The instructions indicate that the term ``plant'' means
each generating station and each transmission line or appropriate
group of transmission lines. This term is also applicable to energy
storage facilities. 18 CFR Part 101 (2012).
---------------------------------------------------------------------------

140. EEI argues that if different depreciation rates are applied to
a single energy storage asset in accordance with each function the
asset performs the various allocated costs of the asset would be
depreciated over multiple periods. EEI is correct that there is a
possibility of this occurring if costs of a single asset were subjected
to multiple differing depreciation rates. However, this has neither
been the experience of this Commission nor do we expect that a
utility's primary rate regulator would subject a single asset to
multiple depreciation rates. Although the costs of an energy storage
asset may be allocated across multiple plant accounts, we agree with
EEI that the asset is a single unique asset with a single economic
life. Thus, there should be a single depreciation rate applied to the
asset that allocates in a systematic and rational manner the service
value of the asset over its service life. To the extent possible, a
utility should apply a single depreciation rate to an energy storage
asset.
141. The reforms adopted here are designed to provide needed
transparency, but also to reflect a fair balance between the need for
information and the additional burden on the utility. We believe these
accounting reforms for energy storage reflect this balance.
Accordingly, Account 348, Energy Storage Equipment--Production, Account
351, Energy Storage Equipment--Transmission, and Account 363, Energy
Storage Equipment--Distribution, as proposed in the NOPR are adopted in
this Final Rule.
2. Power Purchased Account
Commission Proposal
142. In the NOPR, the Commission noted that to provide some
electrical services, energy storage devices may need to maintain a
particular state of charge, or as in the case of compressed air
facilities, may need to maintain some minimum pressure, and that some
companies may be required to purchase power to maintain a desired state
of charge or pressure. Further, the Commission determined that the
benefits of enhanced transparency, in this instance, resulting from
having the cost of power purchased for energy storage operations
reported separately from other power purchases, outweighs the
associated burden of requiring the accounting. Therefore, the
Commission proposed a new Account 555.1, Power Purchased for Storage
Operations, to report the cost of: (1) Power purchased and stored for
resale; (2) power purchased that will not be resold but instead
consumed in operations during the provisioning of services; (3) power
purchased to sustain a state of charge; and (4) power purchased to
initially attain a state of charge, with item 4 being capitalized as a
component cost of initially constructing the asset.
Comments
143. Most commenters support the proposed accounting. For example,
ESA and others state that the new account will enhance the transparency
of reporting the operations of storage resources.\172\ Hydro
Association indicates that similar accounting should be established for
the cost of power purchased for pumped storage operations to account
for initial unit testing and commissioning.\173\
---------------------------------------------------------------------------

\172\ ESA Comments at 21-22.
\173\ Hydro Association Comments at 12-13.
---------------------------------------------------------------------------

144. Hydro Association states, in particular, for closed-loop
pumped storage projects, the first unit testing entails pumping or
charging the upper reservoir. Hydro Association explains that at an
early stage of development of a pumped storage project, the generating
station is months away from being declared ``commercial'' and testing
the station requires energy from the grid to initially attain a fully
charged state (i.e., a full upper reservoir). Hydro Association argues
that these initial

[[Page 46199]]

charging costs should be capitalized. Further, Hydro Association
contends that costs incurred to test the generating station should
likewise be capitalized into the cost of the project. In contrast to
Hydro Association's assertion that the existing accounting requirements
for pumped storage operations are not sufficient, EEI argues that the
existing requirements appropriately and transparently provide for
pumped storage plants.\174\
---------------------------------------------------------------------------

\174\ EEI Comments at 27.
---------------------------------------------------------------------------

Commission Determination
145. We will adopt the new Account 555.1, Power Purchased for
Storage Operations, as proposed in the NOPR. The accounting reforms
here requiring initial charging and testing costs to be capitalized
seek to apply existing requirements for conventional electric plant,
such as pumped storage plant, to new energy storage assets. The
requirements do not seek to differentiate the accounting for new energy
storage assets from pumped storage plant in this instance.
146. We disagree with Hydro Association's assertion that the
existing accounting requirements for pumped storage operations are not
sufficient. Contrary to Hydro Association's assertion, pumped storage
is not prohibited, for accounting purposes, by the existing accounting
rules and regulations from capitalizing costs incurred to initially
bring a pumped storage facility into operation nor is it prohibited
from capitalizing costs incurred to test pump storage facilities prior
to commercial operation. Electric Plant Instruction No. 3, Components
of Construction Cost, provides that expenses incidental to the
construction of plant such as cost to initially attain a fully charged
state to bring the plant into operation may be capitalized as a
component cost of the plant.\175\ Further, Electric Plant Instruction
No. 9, Equipment, provides that the costs of plant shall include
necessary costs of testing or running plant or parts thereof during the
test period prior to the plant becoming ready for or being placed in
service.\176\ Consequently, we agree with EEI's statement that the
existing accounting requirements for pumped storage are sufficient. The
NOPR proposals for Account 555.1 are adopted in this Final Rule as
proposed.
---------------------------------------------------------------------------

\175\ 18 CFR Part 101 (2012).
\176\ Id.
---------------------------------------------------------------------------

3. Operation and Maintenance Expense Accounts
Commission Proposal
147. In the NOPR, the Commission observed that there are O&M
expenses related to the use of energy storage assets to provide utility
services, and there are no existing O&M expense accounts in the USofA
specifically dedicated to accounting for the cost of energy storage
operations. Therefore, the Commission proposed new O&M expense accounts
for energy storage-related O&M expenses that are not specifically
provided for in the existing O&M expense accounts in the USofA and
revision of certain existing O&M expense accounts. Specifically, the
Commission proposed that energy storage expenses be recorded in Account
548.1, Operation of Energy Storage Equipment, and Account 553.1,
Maintenance of Energy Storage Equipment, for energy storage plant
classified as production; Account 562.1, Operation of Energy Storage
Equipment, and Account 570.1, Maintenance of Energy Storage Equipment,
for energy storage plant classified as transmission; and Account 582.1,
Operation of Energy Storage Equipment, and Account 592.2, Maintenance
of Energy Storage Equipment, for energy storage plant classified as
distribution, to the extent that the existing O&M expense accounts do
not adequately support recording of the cost.\177\
---------------------------------------------------------------------------

\177\ NOPR, FERC Stats. & Regs. ] 32,690 at P 96.
---------------------------------------------------------------------------

Comments
148. The commenters support the proposed O&M expense accounts. Most
commenters state that the proposed accounts will provide sufficient
transparency of energy storage-specific O&M expenses.\178\
---------------------------------------------------------------------------

\178\ See, e.g., ESA Comments at 22; Beacon Power Comments at
21-22; and California Storage Alliance Comments at 17.
---------------------------------------------------------------------------

Commission Determination
149. This Final Rule adopts the NOPR proposals for the O&M expense
accounts with the exception that the account number for Account 582.1
will be changed to Account 584.1. The name and text of the account will
remain as proposed in the NOPR.
150. In addition, the NOPR proposed that the text of Account 592,
Maintenance of Station Equipment (Major only), and Account 592.1,
Maintenance of Structures and Equipment (Nonmajor only), be revised
such that the accounts do not provide for O&M expenses related to
energy storage operations and also to remove the reference to Account
363. Accordingly, the following text is struck from Accounts 592 and
592.1:

``and account 363, Storage Battery Equipment.''
4. New and Amended Form Nos. 1, 1-F, and 3-Q Schedules
Commission Proposal
151. In the NOPR, the Commission acknowledged that the existing
schedules in the Form Nos. 1, 1-F, and 3-Q do not provide for reporting
information on new types of energy storage assets such as batteries and
flywheels.\179\ Consequently, the Commission proposed to amend several
schedules of the Form Nos. 1, 1-F, and 3-Q to include energy storage
plant, purchased power, and O&M expense accounts.\180\ In addition, the
Commission proposed to add new schedule pages 414-416, Energy Storage
Operations (Large Plants), and pages 419-420, Energy Storage Operations
(Small Plants), to the Form Nos. 1 and 1-F to provide for reporting
operational and statistical information on new types of energy storage
assets.\181\ The Commission proposed that filers with energy storage
assets having a rated capacity of 10,000 kilowatts (KW) or more record
the operations of the assets on schedule pages 414-416, and filers with
energy storage assets with less than 10,000 KW of capacity record the
operations on schedule pages 419-420. In addition, the Commission
sought comment on whether 10,000 KW is an appropriate threshold for
requiring utilities to report more detailed plant and cost information
for energy storage plant.\182\ The Commission noted that certain
existing schedules in the Form No. 1 have a 10,000 KW threshold.\183\
However, the Commission opined that this threshold may not be
appropriate for new energy storage assets that in

[[Page 46200]]

many instances may be rated below 10,000 KW.
---------------------------------------------------------------------------

\179\ NOPR, FERC Stats. & Regs. ] 32,690 at P 101.
\180\ NOPR, FERC Stats. & Regs. ] 32,690 at P 106; and Appendix
B Proposed Amendments to Form Nos. 1, 1-F and 3-Q.
\181\ The text of the NOPR indicated that the schedules pages
were 414-417 and 419-421 for the respective Large and Small Plant
schedules. However, the proposed schedules included in Appendix B of
the NOPR used different page numbers. We clarify that the schedule
page numbers are 414-416 and 419-420, for the respective Large and
Small Plant schedules, as indicated in this Final Rule.
\182\ NOPR, FERC Stats. & Regs. ] 32,690 at P 103.
\183\ See Form No. 1, schedule pages 408-409, Generating Plant
Statistics (Large Plants) and schedule pages 410-411, Generating
Plant Statistics (Small Plants). Schedule pages 408-409 require
filers to report more detailed information for generating assets
with a rated capacity of 10,000 KW or more than schedule pages 410-
411, which require less detailed information for generating assets
with a rated capacity of less than 10,000 KW.
---------------------------------------------------------------------------

Comments
152. Most commenters support the NOPR's forms proposals, and a few
commenters recommend revisions to the forms in addition to those
proposed.\184\ Consistent with its recommendation that the Commission
implement two options to account for energy storage assets, EEI
proposes that the forms provide for disclosing the specific option a
utility is using to account for the assets.\185\ However, because we
are not adopting EEI's recommendation for two accounting options, its
disclosure proposal is unnecessary as utilities will have one uniform
method for accounting for energy storage assets.
---------------------------------------------------------------------------

\184\ See, e.g., APPA Comments at 5; Beacon Comments at 22-23;
California Storage Alliance Comments at 19; and ESA Comments at 23.
\185\ EEI Comments at 5.
---------------------------------------------------------------------------

153. Hydro Association contends that there are shortcomings in the
way the Form No. 1 treats existing pumped storage plants, as they are
now used, and it suggests modifications that it believes will improve
reporting of information on the assets. Hydro Association recommends
that the heading of Line 6 ``Plant Hours Connect to Load While
Generating'' of schedule pages 408-409, Pumped Storage Generating Plant
Statistics (Large Plants), in the Form No. 1 be changed to read ``Plant
Hours Connect to Load.'' \186\ Hydro Association reasons that the total
hours a facility is synchronized and connected to the grid are
important to identify. Hydro Association explains that a facility's
effectiveness is based on its total utilization factor, which Hydro
Association describes as the sum of hours generating, pumping, and
condensing. Hydro Association asserts that this sum should be reported
on Line 6 under its proposed heading. Alternatively, Hydro Association
proffers that if further detail is needed, the heading of Line 6 can
remain as is and two new line items can be added to the schedule to
report pumping and condensing hours.
---------------------------------------------------------------------------

\186\ Hydro Association Comments at 11.
---------------------------------------------------------------------------

154. Further, Hydro Association also contends that Line 38,
``Expenses for KWh (line 37/9)'' incorrectly calculates the cost per
kilowatt hour (KWh) of pumped storage operations.\187\ Hydro
Association asserts that the calculation should include energy
generated and energy used for pumping operations. Hydro Association
proposes that Line 38 be revised to read as ``Expenses for KWh (line
37/9+10).''
---------------------------------------------------------------------------

\187\ Id.
---------------------------------------------------------------------------

155. TAPS recommends revisions to new schedule pages 414-416,
Energy Storage Operations (Large Plants).\188\ TAPS observes that the
instruction for column heading (l) refers to ``revenues from energy
storage operations'' while the name of the column is ``Revenues from
the Sale of Stored Energy.'' TAPS asserts that because revenues from
energy storage operations can be garnered by means other than from
energy sales, the name of the column should be revised to be consistent
with the instructions of the column or additional columns should be
created, with corresponding instructions, to report other types of
revenues.
---------------------------------------------------------------------------

\188\ TAPS Comments at 28-29.
---------------------------------------------------------------------------

156. In regard to the 10,000 KW threshold, California Storage
Alliance states that it believes 10,000 KW is an appropriate threshold
for requiring a difference in the reporting requirements for the
assets.\189\ In contrast, Beacon and ESA recommend a higher threshold
of 20,000 KW.\190\ Beacon and ESA assert that this threshold would
align with the Small Generator Interconnection threshold and the
capacity value for many existing and planned energy storage assets.
---------------------------------------------------------------------------

\189\ California Storage Alliance Comments at 19.
\190\ Beacon Comments at 22; and ESA Comments at 22-23.
---------------------------------------------------------------------------

Commission Determination
157. We generally agree with the premise of Hydro Association's
contention that Line 6 of schedule pages 408-409 could benefit from
additional detail. However, the cost of additional detail must be
weighed against any associated benefit that could result. To this end,
we strive to achieve a balance such that the cost of implementing new
reporting requirements does not excessively exceed the benefits of
implementation. A particularly important benefit to the Commission of
additional detail is that it provides data necessary for the regulation
and review of companies' operations. Hydro Association has neither
explained how information on pumping and condensing hours is needed for
the regulation and review of pumped storage operations nor has it
explained how the information would be beneficial for other uses. Hydro
Association indicates that this information will provide for a measure
of a facility's effectiveness, however, it is not clear that the cost
of requiring this information is on par with any perceived benefits or
that the requirement would not be overly burdensome. Consequently, we
will not adopt Hydro Association's proposal to include the sum of
generating, condensing and pumping on Line 6, nor will we adopt its
alternate proposal to add two new line items to the schedule.
158. With regard to Hydro Association's contention that Line 38 of
schedule pages 408-409 incorrectly calculates the cost per KWh of
pumped storage operations, this line is not intended to report this
cost, rather it is intended to report the cost per KWh of energy
generated and transmitted to the grid. Line 38 of the schedule includes
a formula that requires filers to divide total production expenses
reported on Line 37 by energy generated and transmitted to the grid
reported on Line 9. Nevertheless, we recognize Hydro Association's
underlying concern that, as a conforming change given the other
accounting requirements in this Final Rule, the schedule should report
this information, including the energy generated and energy used in
pumping, as illustrated in the formula example submitted by Hydro
Association--Line 37/9+10.
159. We agree that reporting this information on schedule pages
408-409 will help create a more accurate database for benchmarking and
O&M cost studies, and this information also will assist interested
parties', including the Commission's, review of the operations of
pumped storage facilities across the industry. We note that the data
inputs needed to perform the calculation are currently required to be
reported on Lines 9, 10 and 37 of schedule pages 408-409, so this
requirement is not wholly new and the burden on utilities to calculate
and report the information specifically on schedule pages 408-409 is
minimal. Accordingly, the item on Line 38 of schedule pages 408-409 is
revised to read ``Expenses per KWh of Generation (line 37/line 9)'' and
a new Line 39 is added which reads ``Expenses per KWh of Generation and
Pumping (line 37/(line 9 + line 10)).''
160. TAPS asserts that revenues from energy storage operations can
originate from activities other than energy sales, thus it recommends
that proposed schedule pages 414-416 be revised to provide for other
types of revenues. We agree that there are potentially other activities
that energy storage operators can engage in to generate revenue. For
example, as TAPS noted, an energy storage operator can conceivably earn
revenues from the sale of storage capacity. While we are not aware of
any instances where these types of storage capacity transactions have
occurred, to ensure that the schedule provides

[[Page 46201]]

adequate flexibility to allow for the reporting of all revenues from
energy storage operations we will revise the name of the column to read
``Revenues from Energy Storage Operations.'' We will not create
additional columns to report the various types of revenue because the
instructions to the schedule already require filers to disclose this
information in a footnote.
161. Beacon and ESA recommend that the Commission align the
threshold for detailed reporting in the new schedules with the existing
20,000 KW threshold established in Order No. 2006 for the
interconnection of small generators.\191\ To this end, Beacon and ESA
propose a 20,000 KW threshold as opposed to the 10,000 KW proposed in
the NOPR. However, the 20,000 KW threshold in Order No. 2006 was
established notwithstanding the requirement that small generators
having 10,000 KW or more but less than 20,000 KW that are subjected to
the Commission's accounting and reporting requirements would be
subjected to a higher reporting burden than companies with generators
of less than 10,000 KW. In this instance, the Commission determined
that while there is a need to further remove barriers to participation
in energy markets by establishing terms and conditions under which
public utilities must provide interconnection service, there is also a
parallel need for detailed information on the activities and operations
of companies using these assets in the provisioning of utility
services. Thus, the Commission maintained its existing 10,000 KW
threshold for these small generators.
---------------------------------------------------------------------------

\191\ Standardization of Small Generator Interconnection
Agreements and Procedures, Order No. 2006, FERC Stats. & Regs. ]
31,180, order on reh 'g, Order No. 2006-A, FERC Stats. & Regs. ]
31,196 (2005), order on clarification, Order No. 2006-B, FERC Stats.
& Regs. ] 31,221 (2006). This order originally set forth the terms
and conditions under which public utilities must provide
interconnection service to Small Generating Facilities of no more
than 20,000 KW.
---------------------------------------------------------------------------

162. Beacon and ESA have not provided information that supports a
decreased reporting burden for energy storage assets over 10,000 KW as
compared to the reporting burden of conventional assets that are
currently subject to the 10,000 KW threshold. Nor has Beacon or ESA
provided information that would support increasing the existing 10,000
KW threshold for conventional assets to maintain parity between those
assets and energy storage assets. Their proposal may result in an
unduly discriminatory reporting requirement for energy storage assets
compared to conventional assets, therefore we will not adopt the
recommended 20,000 KW reporting threshold.
163. We will adopt the NOPR's proposed 10,000 KW threshold as this
amount is neither unduly conservative nor is it overly burdensome. As
we indicated in the NOPR, information that would be reported for energy
storage assets and operations differs little from other data public
utilities maintain under the USofA.\192\ If a utility owns and operates
these energy storage assets, reporting information on them in the
proposed accounts and FERC form schedules should not be burdensome.
---------------------------------------------------------------------------

\192\ NOPR, FERC Stats. & Regs. ] 32,690 at P 73.
---------------------------------------------------------------------------

164. Finally, we will amend schedule pages 2-4, 204-207, 320-323,
324a-324b, 326-327, 397, and 401a of the Form Nos. 1, 1-F, and 3-Q as
proposed in the NOPR.\193\ We note that these amendments include
revising schedule page 401a, Electric Energy Account, of the Form No. 1
to change the title of line item 10 to ``Purchases (other than for
Energy Storage)'' and add a new line item 11 ``Purchases for Energy
Storage'' to provide for reporting power purchased for energy storage
operations. These changes require an additional line item on Form No. 1
schedule page 401a to provide for reporting stored energy because total
net sources of energy must equal total disposition of energy as
instructed by the requirement on Line 30 of the schedule. Utilities
with energy storage operations that have stored energy as of the
reporting date of the form must report the amount by megawatt hour in
the schedule so that total net sources of energy is equal to total
disposition of energy reported. Accordingly, as a conforming change, a
new line item titled ``Total Energy Stored'' will be added to schedule
page 401a under the heading ``Disposition of Energy.''
---------------------------------------------------------------------------

\193\ NOPR, FERC Stats. & Regs. ] 32,690 at Appendix B Proposed
Amendments to Form Nos. 1, 1-F, and 3-Q.
---------------------------------------------------------------------------

5. Other Accounting and Reporting Issues
a. Existing Waivers of Accounting and Reporting Requirements
Commission Proposal
165. In the NOPR, the Commission proposed that public utilities
currently providing jurisdictional services and recovering costs of the
services under market-based rates that have been granted waiver of the
accounting and reporting requirements and that seek recovery of a
portion of service costs under cost-based rates, be required to forego
the previously issued waivers and account for and report all cost and
operational information to the Commission in accordance with its
accounting and reporting requirements.\194\ In addition, the Commission
also inquired whether there should be a percentage of cost recovery
threshold or other determining factor that triggers the accounting and
reporting obligations in this situation, or should any instance of
multiple cost recovery, regardless of the percentage of a utility's
total costs, trigger the accounting and reporting obligations.
---------------------------------------------------------------------------

\194\ Id. P 75.
---------------------------------------------------------------------------

Comments
166. Most commenters agree with the proposal to rescind previously
issued waivers and many of these commenters argue that there should not
be a percentage threshold that triggers the requirement. California
Storage Alliance states that rescinding the waivers will enhance
transparency and facilitate development and monitoring of the cost-
based portion of rates.\195\ Further, California Storage Alliance
states that there should not be a percentage threshold that triggers
accounting and reporting requirements. California Storage Alliance, and
others,\196\ also recommend that in instances where a competitive
solicitation process is used to determine recovery of the cost-based
portion of rates, a public utility should not be required to forego any
reporting and accounting waivers. In further describing their position,
these commenters suggest that a particular ``storage asset may be
capable of simultaneously providing two distinct functions, one
traditionally cost-based use, and another generally market-based.''
They then posit the possibility of a public utility issuing a
competitive solicitation solely for the ``cost-based use.'' Their
comments then assert that the winning bidder would be obligated to
provide the ``cost-based service'' and would be paid through a ``rate-
based mechanism.'' \197\ We also received requests to clarify that the
waivers will only be rescinded if energy storage is involved.\198\
---------------------------------------------------------------------------

\195\ California Storage Alliance Comments at 10.
\196\ California Storage Alliance Comments at 10-11; ESA
Comments at 18; and Beacon Comments at 18.
\197\ Id.
\198\ Indicated Suppliers Comments at 6-11; EPSA Comments at 13;
and EEI Comments at 33-34.
---------------------------------------------------------------------------

Commission Determination
167. We will adopt the NOPR proposal requiring public utilities to
forego previously issued accounting and reporting waivers in instances
where the utility seeks to recover costs associated with operation of
an energy storage asset simultaneously under market-based and

[[Page 46202]]

cost-based rate recovery mechanisms. We will not impose a percentage
recovery threshold, therefore any cost-based recovery of the cost will
trigger rescission of previously granted accounting and reporting
waivers.
168. Regarding the comments of California Storage Alliance, ESA,
and Beacon, the Commission clarifies that sellers under a competitive
solicitation that meets the requirements of this Final Rule \199\ will
not be required to forego any prior accounting and reporting waivers.
However, we feel it necessary to explain that the reason for this
outcome differs from what these commenters seem to propose.
---------------------------------------------------------------------------

\199\ See supra PP 87-90.
---------------------------------------------------------------------------

169. Their comments seem to indicate a belief that there are some
products that are inherently cost-based and others that are inherently
market-based, and that if a competitive solicitation were held for a
cost-based product, the resulting rates would still be cost-based. We
are not persuaded by these commenters' arguments that products should
be classified as inherently cost-based or market-based. Some potential
sellers of these products will qualify to sell them at market-based
rates because they either lack market power in the relevant product
market, or it has been adequately mitigated. Other sellers who do not
qualify to make market-based sales, because they either have market
power or cannot prove they lack it, will be limited to charging cost-
based rates.
170. Under the competitive solicitation proposal at bar, proof that
the competitive solicitation meets the requirements of this Final Rule
will demonstrate that a seller qualifies to make market-based sales at
the rates resulting from the solicitation, and thus can avoid having to
justify those rates on a cost-of-service basis. Because such sellers
will still only be making market-based sales, there is no reason to
rescind the prior accounting and reporting waivers that were granted
because they would only be making market-based rate sales. Cost-based
sales of ancillary services have always been an option for third party
sellers, and remain an option for them after issuance of this Final
Rule. However, all of the requirements of cost-of-service regulation,
such as the very accounting and reporting requirements at issue here,
would apply to such sales. We also clarify that the requirement for a
company to forego previously issued accounting and reporting waivers,
in this instance, is only applicable when energy storage is involved.
There may be other occasions when previously issued waivers may be
rescinded however those occasions are outside the scope of this
rulemaking.
b. Definition of Energy Storage Asset or Technology
171. EEI asks that the Commission clarify the definition of energy
storage assets or technologies that are subject to these accounting and
reporting requirements.\200\ EEI proposes that the Commission define
energy storage assets as ``commercially available technology that is
capable of absorbing energy, storing energy, and subsequently releasing
the energy to the electric system.'' \201\ Further, EEI states that
certain other energy storage assets should be exempted from the Final
Rule, and thus the new accounts, if the function of the asset is so
clearly related to activities properly reflected in existing accounts
such that the asset is not designed to be used as an ``energy storage
asset'' under the definition articulated in this Final Rule. EEI
states, for example, that the following assets or technologies should
be exempted:
---------------------------------------------------------------------------

\200\ EEI Comments at 26-28.
\201\ Id.

Batteries used primarily in connection with the control and
switching of electric energy produced and the protection of electric
circuits and equipment that are recorded in the following existing
---------------------------------------------------------------------------
FERC accounts:

Account 315, Accessory Electric Equipment
Account 324, Accessory Electric Equipment (Major Only)
Account 345, Accessory Electric Equipment

Batteries used in connection with controlling station equipment or
for general station purposes that are recorded in the following
existing FERC accounts:

Account 353, Station Equipment

Batteries used in connection with controlling station equipment or
for general station purposes that are recorded in the following
existing FERC accounts:

Account 362, Station Equipment

Compressed air systems used for pneumatic or air tools that are
recorded in the following existing FERC accounts:

Account 316, Miscellaneous Power Plant Equipment
Account 325, Miscellaneous Power Plant Equipment (Major Only)
Account 346, Miscellaneous Power Plant Equipment
Commission Determination
172. We agree with EEI that there are certain assets that are
excluded from the scope of this Final Rule, however, we will not adopt
EEI's proposed definition for an energy storage asset or technology.
The definition is too broad and could be interpreted to include
storage-type technologies that are outside the scope of this Final
Rule. As EEI indicated, the assets listed above are the type of assets
that should be excluded. This list is not exhaustive; rather it is an
example of the type of assets and activities served by those assets
that are a baseline indicator of assets that are outside the scope of
the accounting and reporting requirements adopted in this Final Rule.
For the purposes of this Final Rule, an energy storage asset shall be
defined as property that is interconnected to the electrical grid and
is designed to receive electrical energy, to store such electrical
energy as another energy form,\202\ and to convert such energy back to
electricity and deliver such electricity for sale, or to use such
energy to provide reliability or economic benefits to the grid. The
term may include hydroelectric pumped storage and compressed air energy
storage, regenerative fuel cells, batteries, superconducting magnetic
energy storage, flywheels, thermal energy storage systems, and hydrogen
storage, or combination thereof, or any other technologies as the
Commission may determine.\203\
---------------------------------------------------------------------------

\202\ Electrical energy may be converted to and stored as
several different forms of energy such as chemical, mechanical, and
thermal energies.
\203\ Although hydroelectric pumped storage is an energy storage
technology in accordance with our definition, the accounting and
reporting requirements of this rulemaking do not apply to the
assets, notwithstanding the revisions to schedule pages 408-409. As
we indicated previously, our existing accounting and reporting
requirements for pumped storage sufficiently accommodate pumped
storage assets and operations.
---------------------------------------------------------------------------

c. Incorporating Energy Storage Plant Accounts Into Existing Formula
Rates
173. EEI requests that the Commission pre-authorize inclusion of
the new energy storage plant and O&M expense accounts in existing
formula rates without the need for separate, company-specific section
205 proceedings.\204\ EEI contends that many jurisdictional utilities
that own and operate energy storage technologies account for the assets
in existing accounts that are incorporated in formula rates. EEI states
that to the extent the new accounts require a revision to existing
filed rates, the Commission should allow such changes to be filed in a
compliance filing in this proceeding.
---------------------------------------------------------------------------

\204\ EEI Comments at 32-33.
---------------------------------------------------------------------------

Commission Determination
174. We agree with EEI that utilities currently owning and
operating these assets are using existing accounts and reporting
schedules. Moreover, in many instances these accounts are incorporated
in the companies' formula rate templates and costs reported in the
accounts are through operation of the formula rate included in rate

[[Page 46203]]

determinations. For some of these companies, transferring amounts from
an existing plant account under a particular functional classification
to a new energy storage plant account under the same functional
classification may involve a relatively straight-forward transfer of
cost. In this type of situation, a compliance filing will provide
adequate transparency to allow interested parties, including the
Commission, to review amounts being transferred from one account to
another and also to establish the incorporation of the new energy
storage plant and O&M expense accounts in the formula rate tariff.
However, a compliance filing may not be suitable for all situations.
175. For example, in instances where a company intends on recording
the costs of an energy storage asset to multiple plant accounts in
accordance with a plan to support multiple functions using the asset, a
compliance filing may not provide for an adequate review of the many
variables involved that can impact the determination of the appropriate
allocation of the cost and rates charged based on the allocation.
Moreover, if a company intends on recovering capital and O&M costs of
the asset simultaneously under cost-based and market-based rate
recovery mechanisms, a compliance filing would not provide sufficient
notice or review of the cost to be recovered under the two rate
mechanisms. Consequently, because a compliance filing is not
appropriate for all situations, we will limit approval of its use to
companies that are transferring amounts from an existing plant account
under a particular functional classification to a new energy storage
plant account under the same functional classification. Transfers of
the costs to other plant accounts after this initial compliance filing
shall be subject to the requirements of Electric Plant Instruction
No.12, Transfers of Property,\205\ as proposed in the NOPR,\206\ and
the provisions of utilities' formula rate tariffs, as applicable.
Utilities that do not qualify to use the compliance filing process must
first receive approval from a relevant rate regulator to revise their
existing formula rate tariffs to incorporate the new energy storage
accounts.
---------------------------------------------------------------------------

\205\ 18 CFR Part 101 (2012).
\206\ NOPR, FERC Stats. & Regs. ] 32,690 at P 82.
---------------------------------------------------------------------------

d. Depreciation Rates for Energy Storage Assets
Commission Proposal
176. In the NOPR, the Commission proposed that the cost of energy
storage assets be charged to depreciation expense using the
depreciation rates developed for each function.\207\
---------------------------------------------------------------------------

\207\ Id.
---------------------------------------------------------------------------

Comments
177. Commenters generally support this proposal. For example,
Beacon and ESA acknowledge support for the proposal.\208\ EEI
recommends that instead of requiring depreciation rates to be based on
a utility's existing rate for a particular function, the Commission
allow utilities to set initial depreciation rates for new energy
storage battery equipment based on the manufacturer's estimated useful
life, prior to the utilities receiving approval of new depreciation
rates through a rate proceeding where new approved rates are ordered
for these accounts.\209\ EEI explains that the current life of storage
batteries is expected to be approximately 10 to 15 years and it
contends that this expected life can be substantially less than the
life used to calculate the depreciation rate for the function the asset
may be classified under.
---------------------------------------------------------------------------

\208\ Beacon Comments at 19; and ESA Comments at 19.
\209\ EEI Comments at 32.
---------------------------------------------------------------------------

Commission Determination
178. For accounting purposes, utilities are required to use
percentage rates of depreciation that are based on a method of
depreciation that allocates in a systematic and rational manner the
service value of depreciable property over the service life of the
property.\210\ Where composite depreciation rates are used, the rate
should be based on the weighted average estimated useful lives of
depreciable property comprising the composite group. Furthermore,
estimated service lives of depreciable property must be supported by
engineering, economic, or other depreciation studies.\211\ To the
extent that an energy storage asset, such as a battery, has an
estimated useful service life that is supported by engineering,
economic, or other studies of the manufacturer or utility, the
depreciation rate derived from such study must result in a systematic
and rational allocation of the asset's costs over the estimated service
life. Therefore, for accounting purposes, utilities may set initial
rates for new energy storage assets based on manufacturer or utility
estimated service lives that are supported by engineering, economic or
other studies. In addition, as we indicated above, utilities should use
a single depreciation rate for an energy storage asset regardless the
number of functions to which the costs of the asset are allocated.\212\
---------------------------------------------------------------------------

\210\ General Instruction No. 22, Depreciation Accounting, 18
CFR Part 101 (2012).
\211\ Id.
\212\ See supra P 128.
---------------------------------------------------------------------------

e. Jurisdictional Authority
179. The California PUC warns that the Commission's authority over
the accounting and reporting for energy storage assets should not limit
or infringe upon States' jurisdictional authority over the assets as
the majority of the assets are likely to be financed pursuant to state
jurisdictional procurement authority.\213\
---------------------------------------------------------------------------

\213\ California PUC Comments at 8.
---------------------------------------------------------------------------

Commission Determination
180. The accounting and reporting requirements of this rulemaking
are not intended to limit or infringe upon States' jurisdictional
authority. Pursuant to section 301(a) of the Federal Power Act (FPA),
the Commission has authority to prescribe a system of accounts and
rules and regulations that are applicable in principle to all licensees
and public utilities subject to the Commission's accounting and
reporting requirements.\214\ The Commission may determine the accounts
in which particular outlays and receipts will be entered, charged or
credited. The amendments to the accounting and reporting requirements
are in accordance with the authority bestowed upon the Commission under
the FPA and as such do not preempt or affect any jurisdiction a State
commission or other State authority may have under applicable State and
Federal law or limit the authority of a State commission in accordance
with State and Federal law.
---------------------------------------------------------------------------

\214\ 16 U.S.C. 825(a).
---------------------------------------------------------------------------

f. Implementation Date
181. EEI requests clarification of the implementation date of the
proposed accounting and reporting requirements. EEI states that it
believes assets and related amounts recorded in other accounts under
the existing accounting requirements should be reclassified to the new
energy storage accounts provided the asset meets the definition of an
energy storage asset.\215\ However, EEI argues that it would not be
beneficial or cost effective to require utilities to retroactively
amend prior year reports to implement the requirements. Therefore, EEI
recommends that the accounting and reporting requirements be effective
prospectively only.
---------------------------------------------------------------------------

\215\ EEI Comments at 28-29.

---------------------------------------------------------------------------

[[Page 46204]]

Commission Determination
182. While we agree with EEI that it may not be cost effective to
require utilities with energy storage assets to retroactively amend
prior year reports to implement the accounting and reporting
requirements of this Final Rule; we disagree with EEI's contention that
it would not be beneficial to interested parties desiring more
transparent reporting of the costs associated with energy storage
operations. In these instances, the Commission must weigh the perceived
cost of implementing a requirement against the expected benefits of
implementation. Although requiring utilities with energy storage assets
to retroactively implement the requirements would provide a more
transparent historical record of these utilities energy storage
operations, this information would not be necessary to provide
oversight of these utilities energy storage operations going forward.
Moreover, it is not clear that the benefits of retroactive
implementation are sufficient to justify the cost. Consequently, we
will not require utilities to retroactively implement the accounting
and reporting requirements.
183. Utilities subject to the Commission's accounting and reporting
requirements must implement the requirements as of January 1, 2013.
Utilities are not required to adjust prior year, comparative
information reported in 2013 Form Nos. 1 and 1-F that must be filed by
April 18, 2014, nor are they required to adjust prior year, comparative
information reported in 2013 Form No. 3-Q reports. However, a footnote
disclosure must be provided describing any amounts transferred from an
existing account to a new energy storage account.
184. Due to outdated software, discussed in more detail below, the
adopted new and revised schedules of Form Nos. 1, 1-F and 3-Q will not
be available for use as of the effective date of this Final Rule.
Consequently, utilities with energy storage assets and those that
acquire the assets at a later date must continue or begin, as
appropriate, using the existing form schedules to report energy storage
assets pending availability of the new and revised schedules.
Furthermore, we direct the Chief Accountant to issue interim accounting
and reporting guidance for utilities to report to the Commission the
costs of energy storage operations contemplated in this Final Rule
until the new and revised schedules are available.
185. Regarding the reporting software issues, the Commission's
forms software applications are built with Visual FoxPro development
tools and must be installed on a Windows-based computer. Microsoft, the
Visual FoxPro vendor, announced in 2007 that it would no longer sell or
issue new versions of Visual FoxPro and would provide support for it
only through 2015. Also, over time, the Commission has found that it is
difficult to update tables in the software to accommodate revisions to
existing schedules and add new schedules to the forms because Visual
FoxPro does not allow data tables to exceed two gigabytes. These data
size limitations will soon restrict the Commission's ability to add
data fields in the forms. These limitations make the forms software
application outmoded, ineffective, and unsustainable.
186. Pursuant to Sections 141.1, 141.400, and 385.2011 of the
Commission's Regulations,\216\ Form Nos. 1 and 3-Q must be submitted
using electronic media.\217\ Due to technology changes that will render
the current forms filing process outmoded, ineffective, and
unsustainable, the Commission will discontinue the use of Commission-
distributed software to file forms. Moreover, because of the software
limitations, the new and revised form schedules will not be available
to utilities with energy storage assets and those that acquire the
assets later as of the effective date of this Final Rule. Consequently,
due to the time lag between implementation of the accounting and
reporting requirements adopted here and the availability of a filing
platform that accommodates the Commission's reporting forms, utilities
should submit their 2013 Form No. 1 and 2014 Form No. 3-Qs using the
existing forms filing process until an updated filing platform is made
available by the Commission. Commission staff will issue appropriate
notices and hold technical conferences if necessary concerning changes
to the filing process.\218\
---------------------------------------------------------------------------

\216\ 18 CFR 141.1, 141.400, and 385.2011 (2012), respectively.
\217\ Form No. 1-F filers may also submit the reports
electronically; however, the Commission's regulations do not
explicitly require these filers to submit the reports
electronically. See 18 CFR 141.2 (2012).
\218\ Filers with energy storage assets and operations may be
required to amend and refile their 2013 Form Nos. 1 and 1-F and 2014
Form No. 3-Q to report energy storage operation information in the
schedules adopted in this final rule as a result of the anticipated
new filing platform. However, these filers will not be required to
amend and refile previously submitted 2013 Form No. 3-Qs.
---------------------------------------------------------------------------

D. Other Issues

187. Some commenters raised issues beyond the scope of the NOPR.
WSPP argues that public utility participation in a competitive market
for ancillary services is hindered by certain OATT requirements
applicable to network transmission customers. Specifically, WSPP refers
to the requirement that network resources be undesignated as such, and
thus lose their firm network transmission service, when they are
committed to third-party sales instead of network load obligations.
WSPP points to timing mismatches between the operational needs of
ancillary service use and the undesignation requirements of the OATT as
the main source of this issue. It argues that the Commission previously
acknowledged these issues in connection with contingency reserves under
the Southwest Reserve Sharing Group.\219\ WSPP argues that this
undesignation requirement hinders robust participation from network
transmission customers, including the transmission providers
themselves, in ancillary service markets.
---------------------------------------------------------------------------

\219\ WSPP Comments at 19-21.
---------------------------------------------------------------------------

188. EEI makes similar arguments with respect to the network
resource undesignation requirements, and asks that the Commission
remain receptive to utility-specific requests for flexibility.\220\
---------------------------------------------------------------------------

\220\ EEI Comments 21-22.
---------------------------------------------------------------------------

189. Hydro Association and Public Interest Organizations argue that
the Commission should develop policies that facilitate long-term
contracts with energy storage owners. Hydro Association asserts that
the Commission should solicit further input on policies that would
allow RTO, ISO, and stand-alone transmission providers to enter into
long-term contracts with energy storage owners.\221\ Public Interest
Organizations make similar arguments.\222\
---------------------------------------------------------------------------

\221\ Hydro Association Comments at 4-6.
\222\ Public Interest Organizations Comments at 11.
---------------------------------------------------------------------------

190. Shell Energy suggests that the current distinction between
Energy Imbalance and Generator Imbalance is unnecessary, and that the
two services should be combined into a single product. Shell Energy
cites similar definitions in the EQR Data Dictionary, and states that
treating the two services as different products provides little
benefit, creates unnecessary complexity and may result in confusion and
regulatory uncertainty.\223\
---------------------------------------------------------------------------

\223\ Shell Energy Comments at 3-4.
---------------------------------------------------------------------------

191. Shell Energy also urges the Commission to recognize
``Balancing Reserves'' as a separate energy and capacity product used
to firm variable energy resources. Shell Energy argues that such a
product would be differentiated from ancillary services because, unlike
ancillary services, it would not be limited to addressing

[[Page 46205]]

contingencies. Shell Energy seeks clarification that such a product
would not be considered an ancillary service, and thus would not be
subject to the Avista restrictions. Rather it would be subject to a
seller's existing authorization to sell energy and capacity at market-
based rates.\224\ EPSA makes similar arguments regarding the need for a
new, non-contingency-related balancing reserves product.\225\ While
WSPP's comments do not specifically seek to identify a new product
based on whether or not it can be used for issues other than
contingencies, as do Shell Energy and EPSA, WSPP nevertheless makes
certain similar arguments in part of its comments. WSPP asserts that
sellers may not always wish to sell specific ancillary services, but
rather may wish to sell ``flexible capacity'' products capable
generally of fulfilling multiple OATT schedules. While its comments are
not entirely clear on this point, WSPP could be interpreted to argue
that the Commission should recognize flexible capacity as a product
different from ancillary services.\226\
---------------------------------------------------------------------------

\224\ Shell Energy Comments at 5-6.
\225\ EPSA Comments at 10-11.
\226\ WSPP Comments at 7.
---------------------------------------------------------------------------

192. AWEA requests that the Commission explore the role that
dynamic transfer capability, or lack thereof, plays in protecting
against exertion of market power. AWEA argues that lack of dynamic
transfer capability severely constrains competitive ancillary service
markets in many parts of the country. AWEA suggests that the Commission
could require transmission providers to analyze, inventory, and market
dynamic scheduling capability on a non-discriminatory basis.\227\
---------------------------------------------------------------------------

\227\ AWEA Comments at 3.
---------------------------------------------------------------------------

193. Powerex argues that there may be certain locations where there
is sufficient market liquidity such that a seller should be able to
make ancillary service sales without performing a separate market power
analysis. Powerex believes that these locations might be defined by
some measure of market liquidity, or by a specific minimum number of
potential sellers, and gives as examples the trading hubs of Mid-
Columbia, California-Oregon Border, Palo Verde, Four Corners, and Mead.
Powerex does not suggest specific liquidity metrics, but does have
suggestions regarding the appropriate minimum number of potential
suppliers. It suggests that third-party sales to a transmission
provider could be deemed competitive any time there are: (1) At least
three potential suppliers, each capable of providing 100 percent of the
buyer's needs for the ancillary service in question; or (2) at least
five potential suppliers, each capable of meeting a significant portion
(e.g., at least 25 percent) of the buyer's need for the ancillary
service in question.
Commission Determination
194. With respect to WSPP's request for more flexibility on the
requirements for network resource undesignation, the Commission
declines to consider such changes on a generic basis at this time. This
undesignation requirement is intended to ensure that network
transmission customers cannot inappropriately withhold firm
transmission capacity from potential competitors. While WSPP is correct
that the Commission has permitted limited deviations from this
requirement in connection with established reserve sharing groups, we
are not persuaded that a more general relaxation is justified. WSPP
indicates in its comments that a public utility is unable to
undesignate the network resource providing the energy associated with
the provision of ancillary services because the unit providing the
energy may differ from the unit providing the capacity. This suggests
that the public utility will be using transmission service from a unit
that is different from the unit for which transmission service has been
reserved. Thus, WSPP is essentially asking the Commission to permit a
public utility transmission provider to implicitly use firm point-to-
point transmission service without reserving it or paying for it. The
Commission has previously expressly prohibited this practice and
nothing in the comments suggests that the Commission's concerns are no
longer valid.\228\ Further, participating in a reserve sharing group
differs from making third-party market sales of ancillary services. A
reserve sharing group essentially expands a public utility transmission
provider's native load obligations to serving other load serving
entities' native load in the event of a contingency with like
protection in return. Permitting a public utility transmission provider
to deliver energy associated with its reserve sharing group obligations
without undesignating the resource providing the energy is an
appropriate recognition of the network service elements of reserve
sharing arrangements. On the other hand, market sales of ancillary
services must be delivered using point-to-point transmission service.
---------------------------------------------------------------------------

\228\ Order No. 890, FERC Stats. & Regs. ] 31,241 at P 834.
---------------------------------------------------------------------------

195. With respect to the requests of Hydro Association and Public
Interest Organizations to facilitate long-term contracting with energy
storage owners, we see no basis for any additional action at this time.
In bilateral markets, assuming that parties are able to avoid the
Avista restrictions through use of one of the options provided in this
rule, potential buyers including transmission owners and sellers are
free to transact through contracts of whatever length they find
mutually agreeable.
196. Shell Energy's suggestion that Energy Imbalance and Generator
Imbalance services be combined into a single product is beyond the
scope of this rulemaking, and Shell Energy's arguments in support of
this idea do not rise to a level concrete enough to justify such an
expansion at this time.
197. With respect to Shell Energy and EPSA's comments regarding
recognition of non-contingency-related balancing reserves as separate
from ancillary services, and WSPP's similar discussion of ``flexible
capacity,'' we clarify that sales of energy and capacity at market-
based rates are permissible, provided the buyer may not use the
purchases to meet its OATT obligations to provide Regulation and
Frequency Response or Reactive Supply and Voltage Control ancillary
services.
198. AWEA's comments regarding dynamic transfer capability raise
issues beyond the scope of this rulemaking, which have not been fully
explored in this proceeding, and whose resolution is not necessary to
the completion of this rulemaking. Accordingly, the Commission will not
direct changes with respect to dynamic scheduling or dynamic transfer
capability at this time.
199. Regarding Powerex's argument for development of a new market
liquidity screen for ancillary service market power, we decline to
attempt such development at this time. The record does not currently
support either development of a generic market liquidity metric, or the
particular minimum participant number thresholds proposed by Powerex.
We remain open to a more detailed discussion of these ideas in the
future if needed, but at this time will move forward with the rule
changes contained elsewhere in this Final Rule, which we hope will
reduce the need to develop alternative market power analyses.

III. Summary of Compliance and Implementation

BILLING CODE 6717-01-P

[[Page 46206]]

[GRAPHIC] [TIFF OMITTED] TR30JY13.004

[[Page 46207]]

[GRAPHIC] [TIFF OMITTED] TR30JY13.005

BILLING CODE 6717-01-C
201. While the authorization is effective as of the date specified
in this Final Rule, sellers should file this tariff revision the next
time they make a market-based rate filing with the Commission. To the
extent sellers do not currently have this provision in their tariff but
wish to make third-party sales of ancillary services, they should
include this revised provision in their tariff the next time they make
a market-based rate filing with the Commission.
202. With regard to sales of Operating Reserves, as discussed
above, both sellers that have a market-based rate tariff on file and
applicants seeking new market-based rate authority must satisfactorily
make the required showing and receive Commission authorization before
making sales of Operating Reserve-Spinning and Operating Reserve-
Supplemental to a public utility that is purchasing Operating Reserve-
Spinning and Operating Reserve-Supplemental to satisfy its own open
access transmission tariff requirements to offer ancillary services to
its own customers.
203. With respect to the Final Rule's reforms to provide greater
transparency with regard to reserve requirements for Regulation and
Frequency Response, within 30 days from the effective date of this
Final Rule, we require each public utility transmission provider to
revise its OATT Schedule 3 consistent with the revised Schedule 3 in
accordance with Appendix B to this Final Rule.
204. With respect to Final Rule's reforms to our accounting and
reporting regulations, utilities subject to these requirements must
implement the requirements as of January 1, 2013. Utilities are not
required to adjust prior year, comparative information reported in 2013
Form Nos. 1 and 1-F that must be filed by April 18, 2014, nor are they
required to adjust prior year, comparative information reported in 2013
Form No. 3-Q reports. However, a footnote disclosure must be provided
describing any amounts transferred from an existing account to a new
energy storage account.
205. Due to outdated software, discussed in more detail in the body
of this Final Rule, the adopted new and revised schedules of Form Nos.
1, 1-F and 3-Q will not be available for use as of the effective date
of this Final Rule. Consequently, utilities with energy storage assets
and those that acquire the assets at a later date must continue or
begin, as appropriate, using the existing form schedules to report
energy storage assets pending availability of the new and revised
schedules.

IV. Information Collection Statement

206. The following collections of information contained in this
Final Rule have been submitted to the Office of Management and Budget
(OMB) for review under Section 3507(d) of the Paperwork Reduction Act
of 1995.\229\ OMB's regulations require approval of certain information
collection requirements imposed by agency rule.\230\ Upon approval of a
collection of information, OMB will assign an OMB control number and an
expiration date. Respondents subject to the filing requirements of a
rule will not be penalized for failing to respond to these collections
of information if the collections of information do not display a valid
OMB control number.
---------------------------------------------------------------------------

\229\ See 44 U.S.C. 3507(d).
\230\ 5 CFR 1320.11 (2012).
---------------------------------------------------------------------------

Burden Estimate: The additional estimated public reporting burdens
and costs for the reporting requirements in this Final Rule are as
follows.\231\
---------------------------------------------------------------------------

\231\ In the NOPR, the Commission proposed changes to FERC-919
(related to the `20 percent screen'). The FERC-919 is not affected
by the Final Rule. In addition, changes to FERC-516, which were not
contained in the NOPR, are included in the Final Rule.

--------------------------------------------------------------------------------------------------------------------------------------------------------
Change in the total
Change in the number annual hours for Estimated annual
of hours per filing Filings per this collection cost (averaging
Data collection Number of respondents (averaging respondent per year (averaging implementation over
(a) implementation over (c) implementation over Yrs. 1-3) (at $120/
Yrs. 1-3) \232\ (b) Yrs. 1-3) (aXbXc=d) hr.) (dX$120/hr.)
(hrs.) (hrs.) ($)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Form No. 1......................... 210................... 7 [3 hrs. (one-time 1.................... 1,470................ 176,400
implementation in
Year 1), plus 6 hrs.
annually].
Form No. 1-F....................... 5..................... 7 [3 hrs. (one-time 1.................... 35................... 4,200
implementation in
Year 1), plus 6 hrs.
annually].
Form No. 3-Q....................... 213................... 1..................... 3.................... 639.................. 76,680
FERC-917 [includes one-time filing 132................... 17.33 averaged over 1.................... 2,288 averaged over 274,560 averaged over
of Pro forma open-access Years 1-3 [4 hrs. one- Years 1-3. Years 1-3
transmission tariff (OATT) & data time in Yr. 1, plus
sharing] \233\. an average recurring
burden in Years 1-3
of 16 hrs.].
FERC-516........................... no change............. no change............. no change............ no change............ no change

[[Page 46208]]

FERC-717 (OASIS posting under 18 176................... 1..................... 1.................... 176.................. 9,889 \234\
CFR 37.6k).
Total.......................... ...................... ...................... ..................... 4,608 (averaged over $541,729 (averaged
Years 1-3). over Years 1-3)
--------------------------------------------------------------------------------------------------------------------------------------------------------

---------------------------------------------------------------------------

\232\ For the Forms 1 and 1-F, the one-time implementation
burden in Year 1 is estimated to be 3 hours per respondent. However,
for the burden and cost estimates, we are averaging those additional
3 hours over Years 1-3, giving an average annual one-time
implementation burden of 1 hour. That 1 hour is in addition to the
normal annual filing burden of 6 hours each, giving an average
annual estimate of 7 hours for Forms 1 and 1-F, for Years 1-3.
\233\ This includes the one-time refiling of OATT Schedule 3
(estimated average of 4 hours per utility respondent), and if
requested, the utility's sharing data and a narrative description
with its self-supplying customer(s) (estimated average of 4 customer
requests per utility respondent per year, taking 4 hours per
request). The estimated annual burden per utility is
Year 1: 4 hrs. (for one-time refiling) + (4 requests *
4 hrs.), giving an estimate of 20 hrs. per utility
Years 2 and 3, each: 4 requests * 4 hrs., giving 16
hrs. per utility per year. When the one-time implementation burden
(of 4 hours) is averaged over Years 1-3, the annual additional
burden per utility is 17.33 hours.
\234\ Based on the 2012 data from the Bureau of Labor Statistics
at https://bls.gov/oes/current/naics2_22.htm, the hourly cost of
salary plus benefits would be $56.19.
---------------------------------------------------------------------------

In paragraph 96, the Commission is requiring that any third-party
seller seeking to sell ancillary services to a public utility
transmission provider through a competitive solicitation will need to
demonstrate compliance with the competitive solicitation requirements
of this rule, through a filing under section 205 of the Federal Power
Act. This requirement for submittal in a section 205 filing would be
made under FERC-516 (OMB Control No. 1902-0096). The filing would be
submitted by the seller to the Commission prior to commencement of
service under the third-party ancillary service sales agreement that
results from the competitive solicitation. The filing will include both
the actual sales agreement and a narrative description of how the
buyer's competitive solicitation meets the requirements of this Final
Rule. Meeting those requirements demonstrates the justness and
reasonableness of the resulting rate. If the seller did not have this
option to sell under the competitive solicitation, the seller could not
use market-based rates and would have to either submit an application
for cost-based rates under FERC-516 or an application seeking waiver of
the Avista restrictions on a case-by-case basis.\235\ The Commission
believes that the burden associated with the new requirements is far
less burden than a full cost-of-service rate filing and approximately
the same burden as the burden associated with an Avista waiver filing.
In addition, the numbers of respondents and filings are not expected to
change significantly. Therefore, no changes are proposed to the burden
or number of responses for FERC-516.
---------------------------------------------------------------------------

\235\ See, e.g., Powerex, 125 FERC ] 61,179 (2008).
---------------------------------------------------------------------------

Title: FERC Form No. 1, ``Annual Report of Major Electric
Utilities, Licensees, and Others;'' FERC Form No. 1-F, ``Annual Report
for Nonmajor Public Utilities and Licensees;'' FERC Form No. 3-Q,
``Quarterly Financial Report of Electric Utilities, Licensees and
Natural Gas Companies;'' FERC-917, ``Non-discriminatory Open Access
Transmission Tariff;'' FERC-516, '' Electric Rate Schedules and Tariff
Filings,'' and FERC-717, ``Open Access Same-Time Information System and
Standards for Business Practices & Communication Protocols.''
Action: Proposed revisions to information collections.
OMB Control Nos.: 1902-0021 (FERC Form No. 1); 1902-0029 (FERC Form
No. 1-F); 1902-0205 (FERC Form No. 3-Q); 1902-0233 (FERC-917), 1902-
0096 (FERC-516), and 1902-0173 (FERC-717).
Respondents: Businesses or other for profit and/or not-for-profit
institutions.
Frequency of responses: Annually (FERC Form Nos. 1 and 1-F, and
FERC-717); quarterly (FERC Form No. 3-Q); and as needed (FERC-917 and
FERC-516).
Necessity of the Information: The final rule amends the
Commission's regulations to reflect changes that are occurring in the
electric industry due to the availability of new energy storage
technologies that are being used in the provision of large-scale
utility operations. These technologies are providing services that were
typically provided by traditional single-purpose production,
transmission and distribution resources. The addition of these new
plant accounts and new and amended reporting forms are intended to
enhance transparency and provide detailed information on transactions
and events affecting public utilities and licensees that file reports
with the Commission. The accounting regulations currently found in the
USofA and related reporting requirements capture financial and
operational information along traditional primary business functions
but do not provide sufficient detailed information concerning energy
storage operations, and in particular, the costs incurred by
organizations using these resources to simultaneously provide multiple
utility services with a single asset. The addition of these accounts is
intended to improve the transparency, completeness and consistency of
accounting practices for the cost of assets, the expenses incurred in
providing services, along with revenues collected. Without specific
instructions and accounts for recording and reporting the above
transactions and events, inconsistent and incomplete accounting and
reporting will result.
Internal Review: The Commission has reviewed the requirements
pertaining to the USofA and to the reports it prescribes and determined
that the proposed amendments are necessary because the Commission needs
to establish uniform accounting and reporting requirements for the
costs of utility assets and the expenses incurred for providing
services as part of its operations.
These requirements conform to the Commission's need for efficient
information collection, communication, and management within the energy
industry. The Commission has assured itself, by means of internal
review, that there is specific, objective support for

[[Page 46209]]

the burden estimates associated with the information collection
requirements.
Interested persons may obtain information on the reporting
requirements by contacting the following: Federal Energy Regulatory
Commission, 888 First Street NE., Washington, DC 20426 [Attention:
Ellen Brown, Office of the Executive Director], email:
DataClearance@ferc.gov, Phone (202) 502-8663, fax: (202) 273-0873.
Comments on the collection of information and the associated burden
estimates in the rule should be sent to the Commission in this docket
and may also be sent to the Office of Information and Regulatory
Affairs, Office of Management and Budget, Washington, DC 20503
[Attention: Desk Officer for the Federal Energy Regulatory Commission].
For security reasons, comments to OMB should be submitted by email to:
oira_submission@omb.eop.gov. Please refer to OMB Control Nos. 1902-
0021 (FERC Form No. 1), 1902-0029 (FERC Form No. 1-F), 1902-0205 (FERC
Form No. 3-Q), and 1902-0233 (FERC-917), 1902-0096 (FERC-516), and
1902-0173 (FERC-717) and Docket Number RM11-24.

Environmental Analysis

207. The Commission is required to prepare an Environmental
Assessment or an Environmental Impact Statement for any action that may
have a significant adverse effect on the human environment.\236\ The
Commission concludes that neither an Environmental Assessment nor an
Environmental Impact Statement is required for this Final Rule under
section 380.4(a)(15) of the Commission's regulations, which provides a
categorical exemption for approval of actions under sections 205 and
206 of the FPA relating to the filing of schedules containing all rates
and charges for the transmission or sale subject to the Commission's
jurisdiction, plus the classification, practices, contracts, and
regulations that affect rates, charges, classifications, and
services.\237\
---------------------------------------------------------------------------

\236\ Regulations Implementing the National Environmental Policy
Act, Order No. 486, 52 FR 47897 (Dec. 17, 1987), FERC Stats. & Regs.
Regulations Preambles 1986-1990 ] 30,783 (1987).
\237\ 18 CFR 380.4(a)(15) (2012).
---------------------------------------------------------------------------

VI. Regulatory Flexibility Act

208. The Regulatory Flexibility Act of 1980 (RFA) \238\ generally
requires a description and analysis of rules that will have significant
economic impact on a substantial number of small entities. The RFA
mandates consideration of regulatory alternatives that accomplish the
stated objectives of a proposed rule and that minimize any significant
economic impact on a substantial number of small entities. The Small
Business Administration's (SBA) Office of Size Standards develops the
numerical definition of a small business.\239\ The SBA has established
a size standard for electric utilities, stating that a firm is small
if, including its affiliates, it is primarily engaged in the
transmission, generation and/or distribution of electric energy for
sale and its total electric output for the preceding twelve months did
not exceed four million megawatt hours.\240\ The rule applies
exclusively to public utilities that own, control, or operate
facilities for transmitting electric energy in interstate commerce and
not electric utilities per se. Based on the filers of the 2011 annual
FERC Form No. 1 and Form No. 1-F, as well as the number of companies
that have obtained waivers, we estimate that 44 entities (20 percent of
the filers) affected by this proposed rule are ``small.'' For each of
the 44 ``small'' entities, the Commission estimates an additional
annual burden of only ten hours (seven hours for the annual Form 1 or
Form 1-F (averaging implementation over years 1-3), plus one hour per
quarter for the Form 3-Q). The Commission believes this rule will not
have a significant economic impact on a substantial number of small
entities, and therefore no regulatory flexibility analysis is required.
---------------------------------------------------------------------------

\238\ 5 U.S.C. 601-612.
\239\ 13 CFR 121.101 (2011).
\240\ 13 CFR 121.201, Sector 22, Utilities.
---------------------------------------------------------------------------

VII. Document Availability

209. In addition to publishing the full text of this document in
the Federal Register, the Commission provides all interested persons an
opportunity to view and/or print the contents of this document via the
Internet through the Commission's Home Page (https://www.ferc.gov) and
in the Commission's Public Reference Room during normal business hours
(8:30 a.m. to 5:00 p.m. Eastern time) at 888 First Street NE., Room 2A,
Washington, DC 20426.
210. From the Commission's Home Page on the Internet, this
information is available on eLibrary. The full text of this document is
available on eLibrary in PDF and Microsoft Word format for viewing,
printing, and/or downloading. To access this document in eLibrary, type
the docket number, excluding the last three digits of this document in
the docket number field.
211. User assistance is available for eLibrary and the Commission's
Web site during normal business hours from the Commission's Online
Support at 202-502-6652 (toll free at 1-866-208-3676) or email at
ferconlinesupport@ferc.gov, or the Public Reference Room at (202) 502-
8371, TTY (202)502-8659. Email the Public Reference Room at
public.referenceroom@ferc.gov.
Effective Date and Congressional Notification. These regulations
are effective November 27, 2013. The Commission has determined, with
the concurrence of the Administrator of the Office of Information and
Regulatory Affairs of OMB, that this rule is not a ``major rule'' as
defined in section 351 of the Small Business Regulatory Enforcement
Fairness Act of 1996.

List of Subjects

18 CFR Part 35

Electric power rates, Electric utilities, Reporting and
recordkeeping requirements

18 CFR Part 101

Electric power, Electric utilities, Uniform System of Accounts.

By direction of the Commission.
Nathaniel J. Davis, Sr.,
Deputy Secretary.

In consideration of the foregoing, the Commission amends Parts 35
and 101, Chapter I, Title 18, Code of Federal Regulations, as follows.

PART 35--FILING OF RATE SCHEDULES AND TARIFFS

0
1. The authority citation for part 35 continues to read as follows:

Authority: 16 U.S.C. 791a-825r, 2601-2645; 31 U.S.C. 9701; 42
U.S.C. 7101-7352.

0
2. Amend Sec. 35.37 by revising paragraph (c)(1) to read as follows:

Sec. 35.37 Market power analysis required.

* * * * *
(c)(1) There will be a rebuttable presumption that a Seller lacks
horizontal market power with respect to sales of energy, capacity,
energy imbalance, and generator imbalance services if it passes two
indicative market power screens: A pivotal supplier analysis based on
annual peak demand of the relevant market, and a market share analysis
applied on a seasonal basis. There will be a rebuttable presumption
that a Seller lacks horizontal market power with respect to sales of
operating reserve-spinning and operating reserve-supplemental services
if the Seller passes these two indicative market power screens and
demonstrates in its market-based rate application how the scheduling
practices in its region

[[Page 46210]]

support the delivery of operating reserve resources from one balancing
authority area to another. There will be a rebuttable presumption that
a seller possesses horizontal market power with respect to sales of
energy, capacity, energy imbalance, generator imbalance, operating
reserve-spinning, and operating reserve-supplemental services if it
fails either screen.
* * * * *

0
3. Amend Sec. 35.38 as follows:
0
a. Paragraph (a) is revised.
0
b. Paragraph (b) introductory text is revised.
0
c. Paragraph (c) is added.
The revisions and addition read as follows:

Sec. 35.38 Mitigation.

* * * * *
(a) A Seller that has been found to have market power in generation
or ancillary services, or that is presumed to have horizontal market
power in generation or ancillary services by virtue of failing or
foregoing the relevant market power screens, as described in 35.37(c),
may adopt the default mitigation detailed in paragraph (b) of this
section for sales of energy or capacity or paragraph (c) of this
section for sales of ancillary services or may propose mitigation
tailored to its own particular circumstances to eliminate its ability
to exercise market power. Mitigation will apply only to the market(s)
in which the Seller is found, or presumed, to have market power.
(b) Default mitigation for sales of energy or capacity consists of
three distinct products:
* * * * *
(c) Default mitigation for sales of ancillary services consist of:
(1) A cap based on the relevant OATT ancillary service rate of the
purchasing transmission operator; or (2) the results of a competitive
solicitation that meets the Commission's requirements for transparency,
definition, evaluation, and competitiveness.

0
4. Amend Sec. 37.6 by adding paragraph (k) to read as follows:

Sec. 37.6 Information to be posted on the OASIS.

* * * * *
(k) Posting of historical area control error data. The Transmission
Provider must post on OASIS historical one-minute and ten-minute area
control error data for the most recent calendar year, and update this
posting once per year.

PART 101--UNIFORM SYSTEM OF ACCOUNTS PRESCRIBED FOR PUBLIC
UTILITIES AND LICENSES SUBJECT TO THE PROVISIONS OF THE FEDERAL
POWER ACT

0
5. The authority citation for part 101 continues to read as follows:

Authority: 16 U.S.C. 791a-825r, 2601-2645; 31 U.S.C. 9701; 42
U.S.C. 7101-7352, 7651-7651o.

0
6. In Part 101:
0
a. Under Electric Plant Chart of Accounts, Account 348 is added to the
list;
0
b. Under Electric Plant Accounts, Account 351, the name of the account
is revised and instructions are added;
0
c. Under Electric Plant Accounts, Account 363, the name of the account
and the instructions are revised;
0
d. Under Electric Plant Accounts, primary plant account 348 is added;
0
e. Under Operation and Maintenance Expense Chart of Accounts, Accounts
548.1, 553.1, 555.1, 562.1, 570.1, 584.1, and 592.2 are added to the
list;
0
f. Under Operation and Maintenance Expense Accounts, operation expense
account 548.1 is added;
0
g. Under Operation and Maintenance Expense Accounts, maintenance
expense account 553.1 is added;
0
h. Under Operation and Maintenance Expense Accounts, power supply
expense account 555.1 is added;
0
i. Under Operation and Maintenance Expense Accounts, operation expense
account 562.1 is added;
0
j. Under Operation and Maintenance Expense Accounts, maintenance
expense account 570.1 is added;
0
k. Under Operation and Maintenance Expense Accounts, operation expense
account 584.1 is added;
0
l. Under Operation and Maintenance Expense Accounts, maintenance
expense account 592.2 is revised; and
0
m. Under Operation and Maintenance Expense Accounts, maintenance
expense account 592.1 is revised;
The revisions and additions read as follows:

PART 101--UNIFORM SYSTEM OF ACCOUNTS PRESCRIBED FOR PUBLIC
UTILITIES AND LICENSES SUBJECT TO THE PROVISIONS OF THE FEDERAL
POWER ACT

* * * * *

Electric Plant Chart of Accounts

* * * * *

2. Production Plant

* * * * *

D. Other Production

* * * * *
348 Energy Storage Equipment--Production
* * * * *

Electric Plant Accounts

* * * * *
351 Energy Storage Equipment--Transmission
A. This account shall include the cost installed of energy storage
equipment used to store energy for load managing purposes. Where energy
storage equipment can perform more than one function or purposes, the
cost of the equipment shall be allocated among production,
transmission, and distribution plant based on the services provided by
the asset and the allocation of the asset's cost through rates approved
by a relevant regulatory agency. Reallocation of the cost of equipment
recorded in this account shall be in accordance with Electric Plant
Instruction No. 12, Transfers of Property.
B. Labor costs and power purchased to energize the equipment are
includible on the first installation only. The cost of removing,
relocating and resetting energy storage equipment shall not be charged
to this account but to Account 562.1, Operation of Energy Storage
Equipment, and Account, 570.1, Maintenance of Energy Storage Equipment,
as appropriate.
C. The records supporting this account shall show, by months, the
function(s) each energy storage asset supports or performs.
Items
1. Batteries/Chemical
2. Compressed Air
3. Flywheels
4. Superconducting Magnetic Storage
5. Thermal
* * * * *
363 Energy Storage Equipment--Distribution
A. This account shall include the cost installed of energy storage
equipment used to store energy for load managing purposes. Where energy
storage equipment can perform more than one function or purpose, the
cost of the equipment shall be allocated among production,
transmission, and distribution plant based on the services provided by
the asset and the allocation of the asset's cost through rates approved
by a relevant regulatory agency. Reallocation of the cost of equipment
recorded in this account shall be in accordance with Electric Plant
Instruction No. 12, Transfers of Property.
B. Labor costs and power purchased to energize the equipment are
includible

[[Page 46211]]

on the first installation only. The cost of removing, relocating and
resetting energy storage equipment shall not be charged to this account
but to Account 582.1, Operation of Energy Storage Equipment, and
Account, 592.1, Maintenance of Energy Storage Equipment, as
appropriate.
C. The records supporting this account shall show, by months, the
function(s) each energy storage asset supports or performs.
Items
1. Batteries/Chemical
2. Compressed Air
3. Flywheels
4. Superconducting Magnetic Storage
5. Thermal
* * * * *
348 Energy Storage Equipment--Production
A. This account shall include the cost installed of energy storage
equipment used to store energy for load managing purposes. Where energy
storage equipment can perform more than one function or purpose, the
cost of the equipment shall be allocated among production,
transmission, and distribution plant based on the services provided by
the asset and the allocation of the asset's cost through rates approved
by a relevant regulatory agency. Reallocation of the cost of equipment
recorded in this account shall be in accordance with Electric Plant
Instruction No. 12, Transfers of Property.
B. Labor costs and power purchased to energize the equipment are
includible on the first installation only. The cost of removing,
relocating and resetting energy storage equipment shall not be charged
to this account but to accounts Account 548.1, Operation of Energy
Storage Equipment, and Account 553.1, Maintenance of Energy Storage
Equipment., as appropriate.
C. The records supporting this account shall show, by months, the
function(s) each energy storage asset supports or performs.
Items
1. Batteries/Chemical
2. Compressed Air
3. Flywheels
4. Superconducting Magnetic Storage
5. Thermal
Note: The cost of pumped storage hydroelectric plant shall be
charged to hydraulic production plant. These are examples of items
includible in this account. This list is not exhaustive.
* * * * *

Operation and Maintenance Expense Chart of Accounts

* * * * *

1. Power Production Expenses

* * * * *

D. Other Power Generation

* * * * *
Operation
* * * * *
548.1 Operation of Energy Storage Equipment
* * * * *
Maintenance
553.1 Maintenance of Energy Storage Equipment
* * * * *

E. Other Power Supply Expenses

* * * * *
555.1 Power Purchased for Storage Operations
* * * * *

2. Transmission Expenses

* * * * *
Operation
* * * * *
562.1 Operation of Energy Storage Equipment
* * * * *
Maintenance
* * * * *
570.1 Maintenance of Energy Storage Equipment
* * * * *

4. Distribution Expenses

* * * * *
Operation
* * * * *
584.1 Operation of Energy Storage Equipment
* * * * *
Maintenance
* * * * *
592.2 Maintenance of Energy Storage Equipment
* * * * *

Operation and Maintenance Expense Accounts

* * * * *
548.1 Operation of Energy Storage Equipment
This account shall include the cost of labor, materials used and
expenses incurred in the operation of energy storage equipment
includible in Account 348, Energy Storage Equipment--Production, which
are not specifically provided for or are readily assignable to other
production operation expense accounts.
* * * * *
553.1 Maintenance of Energy Storage Equipment
This account shall include the cost of labor, materials used and
expenses incurred in the maintenance of energy storage equipment
includible in Account 348, Energy Storage Equipment--Production, which
are not specifically provided for or are readily assignable to other
production maintenance expense accounts.
* * * * *
555.1 Power Purchased for Storage Operations
A. This account shall include the cost at point of receipt by the
utility of electricity purchased for use in storage operations,
including power purchased and consumed or lost in energy storage
operations during the provision of services, including but not limited
to energy purchased and stored for resale. It shall also include but
not be limited to net settlements for exchange of electricity or power,
such as economy energy, off-peak energy for on-peak energy, and
spinning reserve capacity. In addition, the account shall include the
net settlements for transactions under pooling or interconnection
agreements wherein there is a balancing of debits and credits for
energy, capacity, and possibly other factors. Distinct purchases and
sales shall not be recorded as exchanges and net amounts only recorded
merely because debit and credit amounts are combined in the voucher
settlement.
B. The records supporting this account shall show, by months, the
kilowatt hours and prices thereof under each purchase contract and the
charges and credits under each exchange or power pooling contract.
* * * * *
562.1 Operation of Energy Storage Equipment
This account shall include the cost of labor, materials used and
expenses incurred in the operation of energy storage equipment
includible in Account 351, Energy Storage Equipment--Transmission,
which are

[[Page 46212]]

not specifically provided for or are readily assignable to other
transmission operation expense accounts.
* * * * *
570.1 Maintenance of Energy Storage Equipment
This account shall include the cost of labor, materials used and
expenses incurred in the maintenance of energy storage equipment
includible in Account 351, Energy Storage Equipment--Transmission,
which are not specifically provided for or are readily assignable to
other transmission maintenance expense accounts.
* * * * *
584.1 Operation of Energy Storage Equipment
This account shall include the cost of labor, materials used and
expenses incurred in the operation of energy storage equipment
includible in Account 363, Energy Storage Equipment--Distribution,
which are not specifically provided for or are readily assignable to
other distribution operation expense accounts.
* * * * *
592.2 Maintenance of Energy Storage Equipment
This account shall include the cost of labor, materials used and
expenses incurred in the maintenance of energy storage equipment
includible in Account 363, Energy Storage Equipment--Distribution,
which are not specifically provided for or are readily assignable to
other distribution maintenance expense accounts.
* * * * *
592 Maintenance of Station Equipment (Major Only)
This account shall include the cost of labor, materials used and
expenses incurred in maintenance of plant, the book cost of which is
includible in account 362, Station Equipment. (See operating expense
instruction 2.)
* * * * *
592.1 Maintenance of Structures and Equipment (Nonmajor Only)
This account shall include the cost of labor, materials used and
expenses incurred in maintenance of structures, the book cost of which
is includible in account 361, Structures and Improvements, and account
362, Station Equipment. (See operating expense instruction 2.)

Note: The following appendix will not appear in the Code of
Federal Regulations.

Appendix A: List of Short Names of Commenters on the Federal Energy
Regulatory Commission's Notice of Proposed Rulemaking on Third-Party
Provision of Ancillary Services; Accounting and Financial Reporting for
New Electric Storage Technologies--Docket No. RM11-24-000, June 2012

------------------------------------------------------------------------
Short name or acronym Commenter
------------------------------------------------------------------------
APPA......................... American Public Power Association
AWEA......................... American Wind Energy Association
Beacon....................... Beacon Power Corporation
California PUC............... California Public Utilities Commission
California Storage Alliance.. California Energy Storage Alliance
EEI.......................... Edison Electric Institute
Electricity Consumers........ Electricity Consumers Resource Council
ENBALA....................... ENBALA Power Networks
EPSA......................... Electric Power Supply Association
ESA.......................... Electricity Storage Association
FTC Staff.................... Staff of the Federal Trade Commission
Hydro Association............ National Hydropower Association
Iberdrola.................... Iberdrola Renewables, LLC
Indicated Suppliers.......... Calpine Corporation, Dynegy Inc., Exelon
Corporation, GenOn Energy, Inc., and
Tenaska Energy, Inc.
Midwest ISO.................. Midwest Independent Transmission System
Operator Inc.
Morgan Stanley............... Morgan Stanley Capital Group Inc.
NAATBatt..................... National Alliance for Advanced Technology
Batteries
New York ISO................. New York Independent System Operator,
Inc.
NU Companies................. Northeast Utilities Service Company on
behalf of Connecticut Light and Power
Company, Western Massachusetts Electric
Company, Public Service Company of New
Hampshire, and NSTAR Electric Company
Powerex...................... Powerex Corporation
Public Interest Organizations Center for Rural Affairs, Clean
Wisconsin, Climate + Energy Project,
Conservation Law Foundation, Environment
Northeast, Fresh Energy, Land Trust
Alliance, Natural Resources Defense
Council, Pace Energy and Climate Center,
Project for Sustainable FERC Energy
Policy, Sierra Club and Union of
Concerned Scientists
Public Power Council......... Public Power Council
SDG&E........................ San Diego Gas & Electric Company
Shell Energy................. Shell Energy North America (US), L.P.
Solar Energy Association..... Solar Energy Industries Association
Southern California Edison... Southern California Edison Company
TAPS......................... Transmission Access Policy Study Group
and Transmission Dependent Utility
Systems
Western Group................ Arizona Public Service, Avista
Corporation, Bonneville Power
Administration, Idaho Power Company,
PacifiCorp, Portland General Electric,
Xcel Energy Services, Puget Sound
Energy, Inc., Seattle City Light, and
Takoma Power
WSPP......................... WSPP, Inc.
------------------------------------------------------------------------

Note: The following Appendix will not appear in the Code of
Federal Regulations.

Appendix B: Pro Forma Open Access Transmission Tariff

The Commission amends Schedule 3, Regulation and Frequency Response
Service of the pro forma OATT:

Schedule 3

Regulation and Frequency Response Service

Regulation and Frequency Response Service is necessary to provide
for the continuous balancing of resources

[[Page 46213]]

(generation and interchange) with load and for maintaining scheduled
Interconnection frequency at sixty cycles per second (60 Hz).
Regulation and Frequency Response Service is accomplished by committing
on-line generation whose output is raised or lowered (predominantly
through the use of automatic generating control equipment) and by other
non-generation resources capable of providing this service as necessary
to follow the moment-by-moment changes in load. The obligation to
maintain this balance between resources and load lies with the
Transmission Provider (or the Control Area operator that performs this
function for the Transmission Provider). The Transmission Provider must
offer this service when the transmission service is used to serve load
within its Control Area. The Transmission Customer must either purchase
this service from the Transmission Provider or make alternative
comparable arrangements to satisfy its Regulation and Frequency
Response Service obligation. The Transmission Provider will take into
account the speed and accuracy of regulation resources in its
determination of Regulation and Frequency Response reserve
requirements, including as it reviews whether a self-supplying
Transmission Customer has made alternative comparable arrangements.
Upon request by the self-supplying Transmission Customer, the
Transmission Provider will share with the Transmission Customer its
reasoning and any related data used to make the determination of
whether the Transmission Customer has made alternative comparable
arrangements. The amount of and charges for Regulation and Frequency
Response Service are set forth below. To the extent the Control Area
operator performs this service for the Transmission Provider, charges
to the Transmission Customer are to reflect only a pass-through of the
costs charged to the Transmission Provider by that Control Area
operator.

Note: The following Appendix will not appear in the Code of
Federal Regulations.

BILLING CODE 6717-01-P

[[Page 46214]]

[GRAPHIC] [TIFF OMITTED] TR30JY13.006

[[Page 46215]]

[GRAPHIC] [TIFF OMITTED] TR30JY13.007

[[Page 46216]]

[GRAPHIC] [TIFF OMITTED] TR30JY13.008

[[Page 46217]]

[GRAPHIC] [TIFF OMITTED] TR30JY13.009

[[Page 46218]]

[GRAPHIC] [TIFF OMITTED] TR30JY13.010

[[Page 46219]]

[GRAPHIC] [TIFF OMITTED] TR30JY13.011

[[Page 46220]]

[GRAPHIC] [TIFF OMITTED] TR30JY13.012

[[Page 46221]]

[GRAPHIC] [TIFF OMITTED] TR30JY13.013

[[Page 46222]]

[GRAPHIC] [TIFF OMITTED] TR30JY13.014

[[Page 46223]]

[GRAPHIC] [TIFF OMITTED] TR30JY13.015

[[Page 46224]]

[GRAPHIC] [TIFF OMITTED] TR30JY13.016

[[Page 46225]]

[GRAPHIC] [TIFF OMITTED] TR30JY13.017

[[Page 46226]]

[GRAPHIC] [TIFF OMITTED] TR30JY13.018

[[Page 46227]]

[GRAPHIC] [TIFF OMITTED] TR30JY13.019

[[Page 46228]]

[GRAPHIC] [TIFF OMITTED] TR30JY13.020

[[Page 46229]]

[GRAPHIC] [TIFF OMITTED] TR30JY13.021

[[Page 46230]]

[GRAPHIC] [TIFF OMITTED] TR30JY13.022

[[Page 46231]]

[GRAPHIC] [TIFF OMITTED] TR30JY13.023

[[Page 46232]]

[GRAPHIC] [TIFF OMITTED] TR30JY13.024

[[Page 46233]]

[GRAPHIC] [TIFF OMITTED] TR30JY13.025

[[Page 46234]]

[GRAPHIC] [TIFF OMITTED] TR30JY13.026

[[Page 46235]]

[GRAPHIC] [TIFF OMITTED] TR30JY13.027

[[Page 46236]]

[GRAPHIC] [TIFF OMITTED] TR30JY13.028

[[Page 46237]]

[GRAPHIC] [TIFF OMITTED] TR30JY13.029

[FR Doc. 2013-17746 Filed 7-29-13; 8:45 am]
BILLING CODE 6717-01-C

This site is protected by reCAPTCHA and the Google Privacy Policy and Terms of Service apply.