# Electricity Market Transparency Provisions of Section 220 of the Federal Power Act > Briefs, arguments, decisions, and more. URL: https://www.frixlaw.com/law-library/documents/fr%3A2012-23746 ## Record - **Collection:** Federal Register - **Document type:** Rule - **Published:** October 11, 2012 - **Citation:** 77 FR 61896 ## Text DEPARTMENT OF ENERGY Federal Energy Regulatory Commission 18 CFR Part 35 [Docket No. RM10-12-000; Order No. 768] Electricity Market Transparency Provisions of Section 220 of the Federal Power Act AGENCY: Federal Energy Regulatory Commission, DOE. ACTION: Final rule. SUMMARY: The Commission is revising its regulations pursuant to section 220 of the Federal Power Act (FPA), as enacted by section 1281 of the Energy Policy Act of 2005 (EPAct 2005), to facilitate price transparency in markets for the sale and transmission of electric energy in interstate commerce. In doing so, the Commission revises its regulations to require market participants that are excluded from the Commission's jurisdiction under FPA section 205 and have more than a de minimis market presence to file Electric Quarterly Reports (EQR) with the Commission. In addition, the Commission revises the existing EQR filing requirements applicable to market participants in the interstate wholesale electric markets by adding new fields for: reporting the trade date and the type of rate; identifying the exchange used for a sales transaction, if applicable; reporting whether a broker was used to consummate a transaction; reporting electronic tag (e-Tag) ID data; and reporting standardized prices and quantities for energy, capacity and booked out power transactions. The Commission also requires EQR filers to indicate in the existing ID data section whether they report their sales transactions to an index publisher and, if so, to which index publisher(s), and, if applicable, identify which types of transactions are reported. The Commission also eliminates the time zone from the contract section and the Data Universal Numbering System (DUNS) data requirement. These refinements to the existing EQR filing requirements reflect the evolving nature of interstate wholesale electric markets, will increase market transparency for the Commission and the public, and will allow market participants to file the information in the most efficient manner possible. DATES: Effective Date: This rule will become effective December 10, 2012. FOR FURTHER INFORMATION CONTACT: Maria Vouras, Office of Enforcement, Federal Energy Regulatory Commission, 888 First Street NE., Washington, DC 20426, (202) 502-8062, Maria.Vouras@ferc.gov. Steven Reich, Office of Enforcement, Federal Energy Regulatory Commission, 888 First Street NE., Washington, DC 20426, (202) 502-6446, Steven.Reich@ferc.gov. Christina Switzer, Office of the General Counsel, Federal Energy Regulatory Commission, 888 First Street NE., Washington, DC 20426, (202) 502-6379, Christina.Switzer@ferc.gov. SUPPLEMENTARY INFORMATION: Order No. 768 Final Rule Table of Contents Paragraph No. I. Introduction 5 A. Order No. 2001 5 B. EPAct 2005 7 C. Procedural History 9 II. Discussion 10 A. Extending the EQR Filing Requirements to Non-Public Utilities 10 1. Need for Information from Non-Public Utilities and Commission's Legal Authority 10 a. Value of Information from Non-Public Utilities 10 i. NOPR 10 ii. Comments 12 iii. Commission Determination 19 b. Existing Sources of Information 28 i. NOPR 28 ii. Comments 29 iii. Commission Determination 35 c. De Minimis Threshold 40 i. NOPR 40 ii. Comments 41 (a) Setting the Threshold 41 (b) Applying the Threshold 47 iii. Commission Determination 54 2. Filing Requirements for Non-Public Utilities 59 a. Scope of EQR Filing Requirements for Non-Public Utilities 59 i. NOPR 59 ii. Comments 60 iii. Commission Determination 73 b. Burden 76 i. NOPR 76 ii. Comments 77 iii. Commission Determination 82 B. Refinements to the Existing EQR Requirements 86 1. General Refinements 86 a. Trade Date & Time and Type of Rate 86 i. NOPR 86 ii. Comments 87 (a) Trade Date 88 (1) Commission Determination 90 (b) Time of Trade 96 (1) Commission Determination 102 (c) Type of Rate 103 (1) Commission Determination 105 b. Resale of Financial Transmission Rights in Secondary Markets 109 i. NOPR 109 ii. Comments 110 iii. Commission Determination 111 c. Standardizing the Unit for Reporting Energy and Capacity Transactions 112 i. NOPR 112 ii. Comments 113 iii. Commission Determination 116 d. Omitting the Time Zone from the Contract Section of the EQR 119 i. NOPR 119 ii. Comments 120 iii. Commission Determination 121 2. Additional EQR Enhancements 122 a. Identify Transactions Reported to Index Publishers 122 i. NOPR 122 ii. Comments 123 iii. Commission Determination 127 b. Identify the Exchange/Broker Used To Consummate a Transaction 132 i. NOPR 132 ii. Comments 133 iii. Commission Determination 137 c. Collection of e-Tag ID Data 143 i. NOPR 143 ii. Comments 144 (a) Burdens 145 (b) Implementation Issues 146 iii. Commission Determination 156 d. Eliminating the DUNS Number Requirement 168 i. NOPR 168 ii. Comments 169 iii. Commission Determination 171 e. Other Issues 172 i. Comments 172 ii. Commission Determination 173 III. Information Collection Statement 176 A. Comments 176 B. Commission Determination 178 IV. Environmental Analysis 185 V. Regulatory Flexibility Act 186 VI. Document Availability 192 VII. Effective Date and Congressional Notification 195 Attachment A: Revisions to the EQR Data Dictionary Clean Version Attachment B: List of Commenters on the NOPR Before Commissioners: Jon Wellinghoff, Chairman; Philip D. Moeller, John R. Norris, Cheryl A. LaFleur, and Tony T. Clark. Final Rule Issued September 21, 2012. 1. To facilitate price transparency in markets for the sale and transmission of electric energy in interstate commerce, the Federal Energy Regulatory Commission (Commission) pursuant to section 220 of the Federal Power Act (FPA) 1 revises its regulations to require market participants that are excluded from the Commission's jurisdiction under section 205 of the FPA 2 and have more than a de minimis market presence to file Electric Quarterly Reports (EQR) with the Commission. 3 After consideration of the comments filed in response to the Notice of Proposed Rulemaking (NOPR), 4 the Commission concludes that the requirements in this Final Rule will allow the Commission and the public to gain a more complete picture of interstate wholesale electric power and transmission markets by providing additional information concerning price formation and market concentration in these electric markets. Public access to additional sales and transmission-related information in the EQR improves market participants' ability to assess supply and demand fundamentals and to price interstate wholesale electric market transactions. It also strengthens the Commission's ability to identify potential exercises of market power or manipulation and to better evaluate the competitiveness of interstate wholesale electric markets. 1 EPAct 2005, Public Law 109-58, 119 Stat. 594 (2005). 2 16 U.S.C. 824d. 3 This Final Rule refers to market participants that are not public utilities under section 201(f) of the FPA as “non-public utilities.” FPA section 201(f) provides: No provision in this Part shall apply to, or be deemed to include, the United States, a State or any political subdivision of a State, an electric cooperative that receives financing under the Rural Electrification Act of 1936 (7 U.S.C. 901 et seq. ) or that sells less than 4,000,000 megawatt hours of electricity per year, or any agency, authority, or instrumentality of any one or more of the foregoing, or any corporation which is wholly owned, directly or indirectly, by any one or more of the foregoing, or any officer, agent, employee of any of the foregoing acting as such in the course of his official duty, unless such provision makes specific reference thereto. 16 U.S.C. 824(f). In the NOPR, the Commission proposed to amend Part 35 to add a definition of “non-public utility,” and incorrectly referenced 16 U.S.C. 824f. In this Final Rule, we have corrected the reference, which now refers to 16 U.S.C. 824(f). 4 Electricity Market Transparency Provisions of Section 220 of the Federal Power Act, Notice of Proposed Rule Making, FERC Stats. & Regs. ¶ 32,676 (2011) (NOPR). 2. In adopting the requirements in this Final Rule, the Commission has balanced the need to increase transparency with the burden on non-public utilities associated with filing the EQR by revising some of the proposals in the NOPR. As explained below, the Commission uniformly adopts a 4,000,000 MWh de minimis threshold for all non-public utilities, including for non-public utilities that are Balancing Authorities. The Commission also will not require non-public utilities to report the following types of wholesale sales: (1) Sales by a non-public utility, such as a cooperative or joint action agency, to its members; and (2) sales by a non-public utility under a long-term, cost-based agreement required to be made to certain customers under a Federal or state statute. 3. In addition, the Commission revises the existing EQR filing requirements applicable to market participants in the interstate wholesale electric markets. The Commission revises the EQRs currently filed by public utilities under FPA section 205(c) and that will be filed by non-public utility filers under FPA section 220. These revisions include the addition of new fields for: (1) Reporting the trade date and the type of rate; (2) identifying the exchange used for a sales transaction, if applicable; (3) reporting whether a broker was used to consummate a transaction; (4) reporting electronic tag (e-Tag) ID data; and (5) reporting standardized prices and quantities for energy, capacity, and booked out power transactions. The Commission also requires EQR filers to indicate in the existing ID data section whether they report their sales transactions to an index publisher and, if so, to which index publisher(s) and, if applicable, which types of transactions are reported. The Commission also eliminates the time zone from the contract section and the Data Universal Numbering System (DUNS) data requirement. These refinements to the existing EQR filing requirements reflect the evolving nature of interstate wholesale electric markets, will increase market transparency for the Commission and the public, and will allow market participants to file the information in the most efficient manner possible. 5 5 The Commission has proposed to change the process for filing EQRs. Specifically, the Commission has proposed to replace the Visual FoxPro-based EQR software with two new filing options. See Revisions to Electric Quarterly Report Filing Process, 139 FERC ¶ 61,234 (2012). 4. The requirement for certain non-public utilities to file EQRs will be implemented at the same time as the requirement for all EQR filers (both public utilities and non-public utilities) to report the data fields discussed in this rule, i.e., beginning the third quarter of 2013. I. Introduction A. Order No. 2001 5. The Commission set forth the EQR filing requirements in Order No. 2001. 6 Order No. 2001 requires public utilities to electronically file EQRs summarizing transaction information for short-term and long-term cost-based sales and market-based rate sales and the contractual terms and conditions in their agreements for all jurisdictional services. 7 The Commission established the EQR reporting requirements to help ensure the collection of information needed to perform its regulatory functions over transmission and sales of electric energy, 8 while making data more useful to the public and allowing public utilities to better fulfill their responsibility under FPA section 205(c) 9 to have rates on file in a convenient form and place. 10 As noted in Order No. 2001, the EQR data is designed to “provide greater price transparency, promote competition, enhance confidence in the fairness of the markets, and provide a better means to detect and discourage discriminatory practices.” 11 6 Revised Public Utility Filing Requirements, Order No. 2001, 67 FR 31043 (May 8, 2002), FERC Stats. & Regs. ¶ 31,127, reh'g denied, Order No. 2001-A, 100 FERC ¶ 61,074, reh'g denied, Order No. 2001-B, 100 FERC ¶ 61,342, order directing filing, Order No. 2001-C, 101 FERC ¶ 61,314 (2002), order directing filing, Order No. 2001-D, 102 FERC ¶ 61,334, order refining filing requirements, Order No. 2001-E, 105 FERC ¶ 61,352 (2003), order on clarification, Order No. 2001-F, 106 FERC ¶ 61,060 (2004), order revising filing requirements, Order No. 2001-G, 72 FR 56735 (Oct. 4, 2007), 120 FERC ¶ 61,270, order on reh'g and clarification, Order No. 2001-H, 73 FR 1876 (Jan. 10, 2008), 121 FERC ¶ 61,289 (2007), order revising filing requirements, Order No. 2001-I, 73 FR 65526 (Nov. 4, 2008), 125 FERC ¶ 61,103 (2008). 7 Order No. 2001, FERC Stats. & Regs. ¶ 31,127. 8 Id. PP 13-14. 9 16 U.S.C. 824d(c). 10 Order No. 2001, FERC Stats. & Regs. ¶ 31,127 at P 31. 11 Id. 6. Since issuing Order No. 2001, the Commission has provided guidance and refined the reporting requirements, as necessary, to simplify the filing requirements and to reflect changes in the Commission's rules and regulations. 12 For instance, in 2007 the Commission adopted an Electric Quarterly Report Data Dictionary, which provides in one document the definitions of certain terms and values used in filing EQR data. 13 Moreover, in 2007, the Commission required transmission capacity reassignments to be reported in the EQR. 14 The refinements to the existing EQR requirements that we are adopting in this Final Rule build upon the Commission's prior improvements to the reporting requirements and further enhance the goals of providing greater price transparency, promoting competition, instilling confidence in the fairness of the markets, and providing a better means to detect and discourage anti-competitive, discriminatory, and manipulative practices. 12 See, e.g., Revised Public Utility Filing Requirements for Electric Quarterly Reports, 124 FERC ¶ 61,244 (2008) (providing guidance on the filing of information on transmission capacity reassignments in EQRs); Notice of Electric Quarterly Reports Technical Conference, 73 FR 2477 (Jan. 15, 2008) (announcing a technical conference to discuss changes associated with the EQR Data Dictionary). 13 Order No. 2001-G, 120 FERC ¶ 61,270. 14 Preventing Undue Discrimination and Preference in Transmission Service, Order No. 890, 72 FR 12266 (Mar. 15, 2007), FERC Stats. & Regs. ¶ 31,241, at P 817, order on reh'g, Order No. 890-A, 73 FR 2984 (Jan. 16, 2008), FERC Stats. & Regs. ¶ 31,261 (2007), order on reh'g and clarification, Order No. 890-B, 73 FR 39092 (July 8, 2008), 123 FERC ¶ 61,299 (2008), order on reh'g, Order No. 890-C, 74 FR 12540 (Mar. 25, 2009), 126 FERC ¶ 61,228 (2009), order on clarification, Order No. 890-D, 74 FR 61511 (Nov. 25, 2009), 129 FERC ¶ 61,126. B. EPAct 2005 7. In EPAct 2005, Congress added section 220 to the FPA, 15 directing the Commission to “facilitate price transparency in markets for the sale and transmission of electric energy in interstate commerce” with “due regard for the public interest, the integrity of those markets, fair competition, and the protection of consumers.” 16 FPA section 220 grants the Commission authority to obtain and disseminate “information about the availability and prices of wholesale electric energy and transmission service to the Commission, State commissions, buyers and sellers of wholesale electric energy, users of transmission services, and the public.” 17 The statute specifies that the Commission may obtain this information from “any market participant,” 18 except for entities with a de minimis market presence. 19 EPAct 2005 added a similar transparency provision in the Natural Gas Act, 20 which led to additional filing and posting requirements for the sale or transportation of physical natural gas in interstate commerce in Order Nos. 704 and 720. 21 15 16 U.S.C. 824t. 16 In addition, FPA section 220(b)(1-2) directs the Commission to exempt from disclosure information that is “detrimental to the operation of an effective market or [that would] jeopardize system security,” and “to ensure that consumers and competitive markets are protected from the adverse effects of potential collusion or other anticompetitive behaviors that can be facilitated by untimely public disclosure of proprietary trading information.” 16 U.S.C. 824t(b)(1-2). 17 Id. 824t(a)(2). 18 Id. 824t(a)(3)(A). 19 Id. 824t(d). 20 15 U.S.C. 717t-2. 21 See Transparency Provisions of Section 23 of the Natural Gas Act, Order No. 704, 73 FR 1014 (Jan. 4, 2008), FERC Stats. & Regs. ¶ 31,260 (2007), order on reh'g, Order No. 704-A, 73 FR 55726 (Sept. 26, 2008), FERC Stats. & Regs. ¶ 31,275, order dismissing reh'g and clarification, Order No. 704-B, 125 FERC ¶ 61,302 (2008), order granting clarification, Order No. 704-C, 75 FR 35632 (June 23, 2010), 131 FERC ¶ 61,246 (2010); see also, Pipeline Posting Requirements under Section 23 of the Natural Gas Act, Order No. 720, 73 FR 73494 (Dec. 2, 2008), FERC Stats. & Regs. ¶ 31,283 (2008), order on reh'g, Order No. 720-A,75 FR 5178 (Jan. 21, 2010), FERC Stats. & Regs. ¶ 31,302, order on reh'g and clarification, Order No. 720-B, 75 FR 44893 (July 30, 2010), FERC Stats. & Regs. ¶ 31,314 (2010), vacated, Texas Pipeline Ass'n v. FERC, 661 F.3d 258 (2011). 8. The Commission did not previously extend transparency requirements under FPA section 220 to wholesale electricity markets because the Commission was considering other reforms to its regulation of electricity markets. 22 In particular, the Commission was undertaking open access transmission service reforms and the more general review of competition in wholesale electricity markets. 23 As a result of these efforts, the Commission issued two final rules. In Order No. 890, the Commission exercised its remedial authority “to limit further opportunities for undue discrimination, by minimizing areas of discretion, addressing ambiguities and clarifying various aspects of the pro forma [Open Access Transmission Tariff].” 24 Moreover, in Order No. 719, the Commission made reforms “to improve the operation [and competitiveness] of organized wholesale electric power markets” in connection with “fulfilling its statutory mandate to ensure supplies of electric energy at just, reasonable and not unduly discriminatory or preferential rates.” 25 Although these final rules improved transparency in wholesale markets in a number of ways, the Commission believes the revisions required in this Final Rule are necessary to facilitate price transparency in wholesale electricity markets. 22 See Transparency Provisions of Section 23 of the Natural Gas Act; Transparency Provisions of the Energy Policy Act, Notice of Proposed Rulemaking, 72 FR 20791 (April 26, 2007), FERC Stats. & Regs. ¶ 32,614, at PP 9-11 (2007) (Natural Gas Transparency NOPR) (“The Commission does not propose action with respect to electric markets at this time. The Commission has recently addressed and is currently addressing electric market transparency in other proceedings.”). 23 Id. 24 Order No. 890, FERC Stats. & Regs. ¶ 31,241 at P 40. 25 Wholesale Competition in Regions with Organized Electric Markets, Order No. 719, 73 FR 64100 (Oct. 28, 2008), FERC Stats. & Regs. ¶ 31,281 (2008), order on reh'g, Order No. 719-A, 74 FR 37776 (July 29, 2009), FERC Stats. & Regs. ¶ 31,292, order on reh'g and clarification, Order No. 719-B, 129 FERC ¶ 61,252 (2009). C. Procedural History 9. On January 21, 2010, the Commission issued a Notice of Inquiry 26 seeking comments on whether the Commission should apply the EQR filing requirements to non-public utilities and whether the Commission should consider other refinements to the existing EQR filing requirements. Based on comments received in response to the Transparency NOI, the Commission drafted the proposals in the NOPR. The Commission issued the NOPR in this proceeding on April 21, 2011. In response, the Commission received 28 comments. 27 26 Electricity Market Transparency Provisions of Section 220 of the Federal Power Act, Notice of Inquiry, 75 FR 4805 (Jan. 29, 2010), FERC Stats. & Regs. ¶ 35,565 (2010) (Transparency NOI). 27 See Attachment B for a list of commenters and their abbreviated names as used here. II. Discussion A. Extending the EQR Filing Requirements to Non-Public Utilities 1. Need for Information From Non-Public Utilities and Commission's Legal Authority a. Value of Information From Non-Public Utilities i. NOPR 10. In the NOPR, the Commission stated that the market transparency provisions in section 220 of the FPA authorize the Commission to “prescribe such rules as the Commission determines necessary and appropriate” for the dissemination of “information about the availability and prices of wholesale electric energy and transmission service.” 28 The Commission explained that the transparency provisions expand the Commission's authority to collect such information not only from jurisdictional utilities, but also “from any market participant” 29 with more than a de minimis market presence. 30 The Commission also stated that the phrase “any market participant” is not defined in section 220 and is not limited to public utilities subject to the Commission's jurisdiction under section 205 of the FPA. The Commission interpreted “any market participant” to include non-public utilities that fall under FPA section 201(f). 31 The Commission stated that such an interpretation of “any market participant” is consistent with the broad mandate in section 220 to “facilitate price transparency in the markets for the sale and transmission of electric energy in interstate commerce, having due regard for the public interest, the integrity of those markets, fair competition, and the protection of consumers.” Furthermore, the Commission stated that, in EPAct 2005, Congress amended section 201(b)(2) of the FPA to provide that, “[n]otwithstanding section 201(f),” the entities described in section 201(f) shall be subject to the Commission's jurisdiction for purposes of carrying out certain provisions, including FPA section 220. Thus, the Commission concluded that reading FPA section 201(b)(2) in conjunction with section 220, EPAct 2005 granted the Commission authority to collect information concerning the availability and prices of wholesale electric energy and transmission service from entities that are not public utilities. Accordingly, the Commission proposed to fulfill its responsibility under section 220 of the FPA by requiring non-public utilities with more than a de minimis market presence in wholesale markets to comply with the EQR filing requirements. 28 16 U.S.C. 824t(a)(2). 29 Id. 824t(a)(3). This section states, in relevant part, that “[t]he Commission may obtain the information described in paragraph (2) from any market participant.” Id. (emphasis added). 30 Id. 824t(d). 31 See id. at 824t(a)(3)(A). 11. As part of its justification for its proposals in the NOPR, the Commission explained that applying the EQR filing requirements to non-public utilities that fall above the de minimis threshold will increase price transparency to the public and the Commission and aid the Commission in its oversight of wholesale power and transmission markets. The Commission stated that non-public utilities have a significant presence in national and regional wholesale electricity markets 32 so that obtaining information about their sales transactions is important to unmasking how prices are formed in electricity markets. The lack of information from non-public utilities results in an incomplete picture of these markets, and hampers the ability of the public and the Commission to detect and address the potential exercise of market power and manipulation. 32 In the NOPR, the Commission stated that, based on the most recent data available in the 2009 U.S. Energy Information Administration's (EIA's) Form 861, non-public utilities account for significant volumes of the 3.2 billion MWh of total annual wholesale electricity sales made within the 48 contiguous states (excluding ERCOT). The Commission noted that about 29 percent of those wholesale sales were made by non-public utilities, with non-public utilities accounting for 60 and 70 percent of wholesale sales within the Western Electric Coordinating Council (WECC) and SERC Reliability Corporation (SERC) regions, respectively, and about 80 percent of all wholesale sales that occur within the Florida Reliability Coordinating Council (FRCC). See NOPR, FERC Stats. & Regs. ¶ 32,676 at P 23. ii. Comments 12. Several commenters argue that extending the EQR filing requirements to non-public utilities will not increase transparency in wholesale electric markets regulated by the Commission. 33 NYMPA/MEUA argue that, contrary to the Commission's contention in the NOPR, reporting information about the limited wholesale sales made by municipal utilities will add little to the Commission's oversight of the markets it regulates. 34 Southwestern Power Administration states that it makes cost-based sales pursuant to statute; therefore, its sales play no role in price formation in wholesale markets and do not materially affect wholesale prices or rates paid to jurisdictional entities. 35 NRECA states that the majority of wholesale sales by non-public utilities are sales to their members pursuant to long-term bilateral contracts, which do not take place within wholesale electricity markets and have no impact on wholesale market prices. APPA, Public Systems, and TAPS argue that requiring Regional Transmission Operators (RTOs) and Independent System Operators (ISO) to make bid information publicly available with a shorter time lag is the most effective way to improve market transparency and oversight of RTO and ISO markets. 36 33 See, e.g., California DWR at 1-2; NRECA at 4; NYMPA/MEUA at 3; Southwestern Power Administration at 3. 34 NYMPA/MEUA at 3. 35 Southwestern Power Administration at 3. 36 APPA at 4; Public Systems at 2; TAPS at 17-20. 13. APPA, supported by NRECA, asserts that the Commission's estimate of sales by non-public utilities overstates the percentage of sales made by non-public utilities. 37 For instance, APPA argues that not all wholesale sales are reported in EIA Form 861, and that wholesale power sales in Alaska, Hawaii, and ERCOT cannot be excluded from the percentage of nationwide wholesale sales made by non-public utilities because EIA data are not reported in sufficient detail to accurately determine which sales should be excluded. 38 In particular, APPA states that its analysis of EIA data indicates that non-public utilities accounted for only 19.4 percent of wholesale sales in the United States in 2009 rather than 29 percent, as stated in the NOPR. In addition, APPA argues that the NOPR's estimates of non-public utility wholesale sales by region, i.e., 80 percent in FRCC, 70 percent in SERC, and 60 percent in WECC, are overstated because EIA reports a power marketer's sales as being from a single region even though it may make sales in several regions. APPA also argues that the EQR data supports its contention that the Commission overstated in the NOPR the percentage of wholesale sales attributable to non-public utilities. 39 37 APPA at 9-10; NRECA at 8. 38 APPA at 8-9. 39 Id. at 10. For example, APPA states that Morgan Stanley Capital Group's 2009 wholesale sales reported on EIA Form 861 are assigned to the ReliabilityFirst Corporation (RFC) region of North American Electric Reliability Corporation (NERC), but that the company's fourth quarter 2009 EQR shows that not all of those sales were in the RFC region. Morgan Stanley reported energy sales and bookouts of 27.5 million MWhs in WECC and 5.1 million MWhs in SERC. APPA concludes that for that quarter, “Morgan Stanley sold more in the WECC region than any public power utility or cooperative sold in WECC for all of 2009, but the Morgan Stanley sales were not part of FERC's analysis of the WECC region.” APPA makes a similar observation regarding sales by Constellation Energy Commodities Group for fourth quarter 2009 and notes that Calpine Energy Services and Dynegy Power Marketing both report large amounts of wholesale sales on the 2009 EIA Form 861, but leave the NERC region blank. EQRs for the fourth quarter show that Calpine sold 22.2 million MWhs in WECC, 3.1 million MWhs in SERC, and 136,000 MWhs in FRCC; Dynegy sold 1.1 million MWhs in WECC. APPA claims that regional calculations based on EIA Form 861 data would not include those sales in the appropriate regions, thus overstating the percentage of non-public utilities' sales in those regions. 14. NRECA also argues that the NOPR overestimated the number of wholesale sales made by non-public utilities in regional markets because the EIA data used to calculate those numbers do not distinguish between non-public utility sales made to members and non-members and appear to omit certain large power marketers as they do not report sales by NERC Reliability Region. 40 In particular, NRECA states that the percentage of non-public utility wholesale sales in FRCC was less than 80 percent of all wholesale sales in FRCC, with only two non-public utilities in FRCC selling above 4,000,000 MWh of wholesale energy in 2009, primarily to their own members. NRECA contends that the Commission made a similar mistake in its analyses of non-public utility sales in the Western Electricity Coordinating Council. 41 40 NRECA at 7-8. 41 Id. 15. Other commenters, such as EEI and Joint Market Monitors, not only argue that the Commission has the authority to require non-public utilities to submit EQRs, but also that this information will increase transparency. Moreover, Joint Market Monitors argue that the Commission's jurisdiction over market manipulation constitutes a standalone basis for requiring all market participants to file EQRs. Joint Market Monitors state that the Commission's market-based rate program is based on a theory of regulation through competition, which relies on a lack of market power or adequate mitigation to ensure just and reasonable pricing. 42 42 Joint Market Monitors at 3. 16. Moreover, certain commenters agree with the Commission that information from non-public utilities will increase transparency in interstate wholesale electric power and transmission markets. 43 Joint Market Monitors assert that the jurisdictional status of a market participant has no bearing on the impact of its participation and conduct on electricity markets. Furthermore, Joint Market Monitors agree that the Commission must have an understanding of what transpires in a market as a whole to fully understand any particular part of it. Given that all market participants participate in price formation, Joint Market Monitors argue that all market participants should be required to provide data adequate to ensure that the Commission is able to fulfill its basic regulatory duties. 44 43 See, e.g., DC Energy at 3; EEI at 3-6; Joint Market Monitors at 3; NYMPA/MEUA at 3; Pacific Northwest IOUs at 2; Pennsylvania Commission at 6; Powerex at 4; Ronald Rattey at 10; Shell Energy at 2. 44 Joint Market Monitors at 3-4. 17. Pennsylvania Commission states that cooperatives and municipalities play a significant role in serving Pennsylvania residents; thus, expanding EQR requirements to include them will strengthen the Commission's ability to monitor wholesale markets and Pennsylvania Commission's ability to monitor its retail markets for anti-competitive and manipulative behavior. 45 45 Pennsylvania Commission at 7. 18. EEI states that public utilities would benefit from access to EQR information from non-public utilities in undertaking analyses used for market-based rate applications. 46 In contrast, LPPC asserts that information regarding long-term agreements would not assist the Commission in conducting a delivered price test (DPT) for market-based rate authorizations and mergers. LPPC asserts that the delivered price test measures concentration in short-term markets and focuses on the ability of suppliers to deliver energy to relevant markets as measured by their short-term variable costs. LPPC therefore contends that disclosure of the prices reflected in long-term wholesale contracts between non-public utilities would do nothing to improve the accuracy of determining either short-term destination market prices or the short-term variable costs of potential suppliers. 47 46 EEI at 3-4. 47 LPPC at 9-10. iii. Commission Determination 19. We conclude that FPA section 201(b)(2), read in conjunction with section 220, grants the Commission authority to collect information about the availability and prices of wholesale electric energy and transmission service from non-public utilities notwithstanding section 201(f) . 48 We further conclude, for the reasons discussed in the NOPR and based on our review of the record, that it is appropriate to adopt the NOPR proposal to extend EQR filing requirements to non-public utilities above the de minimis threshold under FPA section 220 with the following modifications. In the NOPR, the Commission proposed to require non-public utilities above the de minimis threshold to report all of their wholesale sales in the EQR to increase price transparency to the public and the Commission. The Commission modifies its NOPR proposal by excluding the following types of wholesale sales from the EQR reporting requirement for non-public utilities above the de minimis threshold: (1) Sales by a non-public utility, such as a cooperative or joint action agency, to its members; and (2) sales by a non-public utility under a long-term, cost-based agreement required to be made to certain customers under a Federal or state statute. 48 FPA section 201(b)(2) explicitly applies certain FPA provisions, including the transparency provision under FPA section 220, to entities covered by FPA section 201(f). This contrasts with the Natural Gas Act (NGA), which does not contain a similar provision setting forth the applicability of the transparency provision under NGA section 23 to natural gas pipelines that are exempted from the Commission's NGA jurisdiction under NGA section 1(b). On appeal of Order Nos. 720 and 720-A, whereby the Commission required major intrastate natural gas pipelines to post certain information under NGA section 23, the Fifth Circuit Court of Appeals concluded that the Commission's authority under NGA section 23 does not extend to intrastate pipelines because they are exempted from the Commission's NGA jurisdiction by NGA section 1(b). See Texas Pipeline Ass'n v. FERC, 661 F.3d at 262. 20. The NOPR explained that transactions made by both public utility and non-public utility market participants provide critical pricing information that market participants can use to make better-informed decisions about, among other things, sales, purchases, and infrastructure investments. Moreover, access to reliable data reduces differences in available information among various market participants, results in greater market confidence, lowers transaction costs, and ultimately supports competitive markets, which helps lower electricity costs for consumers. 21. The NOPR also pointed out that non-public utilities have a significant presence in national and regional wholesale electric markets so that obtaining information about their sales transactions is important to unmasking how prices are formed in electric markets. Therefore, the lack of information from non-public utilities results in an incomplete picture of these markets, and hampers the ability of the public and the Commission to detect and address the potential exercise of market power and manipulation. 49 49 NOPR, FERC Stats. & Regs. ¶ 32,676 at P 11. 22. In addition, as stated in the NOPR, obtaining EQR information from non-public utilities would strengthen the Commission's oversight of its market-based rate program under FPA section 205 and provide a better basis for considering whether to approve merger and acquisition proposals under FPA section 203. 50 The Commission's market-based rate program is grounded in an ex ante analysis of whether to grant a seller market-based rate authority and an ex post analysis of whether a seller with market-based rate authority has obtained the ability to exercise market power since it was granted authorization to transact at market-based rates or since its last updated market power analysis. 51 As stated in the NOPR, one tool used to conduct an ex ante analysis is the DPT, which is used if a seller fails one of the indicative screens of market power. The NOPR stated that obtaining more complete price and volume information for sales of electricity by non-public utilities would more accurately reflect market prices, improve the quality of the DPT results and assist the Commission in identifying whether sellers can exercise market power. 52 After consideration of various comments and careful balancing of the need to facilitate price transparency against the burden on non-public utilities associated with filing the EQR, the Commission modifies its NOPR proposal, as discussed above, by excluding certain non-public utility wholesale sales from the EQR reporting requirement. In particular, the Commission modifies its NOPR proposal by excluding the following types of wholesale sales from the EQR reporting requirement for non-public utilities above the de minimis threshold: (1) Sales by a non-public utility, such as a cooperative or joint action agency, to its members; and (2) sales by a non-public utility under a long-term, cost-based agreement required to be made to certain customers under a Federal or state statute. For purposes of this rulemaking, the Commission refers to non-public utility wholesale sales not subject to either of these two exclusions as “surplus” market sales. The Commission finds that information about a non-public utility's sales to its members, or by a non-public utility under a long-term, cost-based agreement required to be made to certain customers under statute, will not materially contribute to additional price transparency. These types of sales do not significantly impact wholesale price formation in electric markets because these sales generally take place between a non-public utility and a pre-determined customer without arm's-length negotiations. In addition, the benefit of obtaining information about such sales by non-public utilities may not outweigh the burden imposed on the non-public utilities that would need to report such sales in the EQR. 50 Id. P 27. 51 The Ninth Circuit Court of Appeals has upheld the Commission's market-based rate program because it relies on a “system [that] consists of a finding that the applicant lacks market power (or has taken sufficient steps to mitigate market power), coupled with strict reporting requirements to ensure that the rate is `just and reasonable' and that markets are not subject to manipulation.” State of California, ex rel. Bill Lockyer v. FERC, 383 F.3d 1006, 1013 (9th Cir. 2004), cert. denied (S. Ct. Nos. 06-888 and 06-1100, June 18, 2007)). 52 NOPR, FERC Stats. & Regs. ¶ 32,676 at P 27. 23. The Commission adopts the NOPR proposal to exempt utilities located entirely in Alaska and Hawaii from the EQR filing requirements because they are electrically isolated from the contiguous United States. In addition, this Final Rule does not apply to a transaction for the purchase or sale of wholesale electric energy or transmission services within ERCOT as it is described in section 212(k)(2)(A) of the FPA. 53 53 16 U.S.C. 824t(f). 24. APPA and NRECA argue that the NOPR overestimated the amount of nationwide wholesale sales made by non-public utilities. APPA contends that its calculations indicate that non-public utilities account for 19.4 percent of nationwide wholesale sales rather than 29 percent, as stated in the NOPR. APPA also points out that its calculation of non-public utility sales does not exclude certain sales in Alaska, Hawaii and ERCOT due to the lack of sufficient detail in EIA data. 54 Even if non-public utilities account for approximately 19.4 percent of nationwide wholesale sales, as APPA contends, the Commission finds this percentage of sales in the nationwide wholesale electricity market to be significant. APPA and NRECA also argue that the Commission's analysis using EIA Form 861 data overstated the number of non-public utility wholesale sales in regional markets. Although EIA data is not sufficiently detailed to provide a complete and precise estimate of wholesale sales made by non-public utilities, the Commission's market analysis using EIA data nevertheless indicates that non-public utilities account for a significant portion of sales in certain regional markets. The lack of publicly available data regarding non-public utility sales challenges the ability of the public and the Commission to rely on existing information sources to form an accurate picture of wholesale electricity markets and does not provide the level of price transparency that this Final Rule seeks to achieve. 54 APPA at 8-9. 25. As noted in the NOPR, the Commission believes its effort to increase transparency broadly across all wholesale markets subject to the Commission's jurisdiction by requiring additional information in the EQR is just as important as efforts the Commission has taken to improve transparency in RTO and ISO markets. 55 Obtaining information about sales in markets outside of RTO and ISO regions will enable the Commission and the public to better understand non-public utilities' effect on market dynamics. For example, in the Pacific Northwest, the supply of power from non-public utilities ebbs and flows with the water levels powering hydroelectric facilities. During times of high flows, power prices may fall and public utilities' fossil fuel and wind-fired generation can become less competitive. During times of drought or dry seasons, power prices may rise. 55 See NOPR, FERC Stats. & Regs. ¶ 32,676 at P 25. 26. With respect to the suggestion by certain commenters that the Commission should require shorter time lags for RTO and ISO postings of bid and offer data, we note that the Commission has previously addressed the time lag for such data and we will not address that issue again here. Specifically, in Order No. 719, the Commission shortened the release period for bid and offer data and provided RTOs and ISOs with the flexibility to propose a different lag period. 56 Furthermore, the EQR provides a level of transparency that RTO or ISO postings of bid and offer data do not, because it informs the public which market participants are involved across markets and at what level. 56 Order No. 719, FERC Stats. & Regs. ¶ 31,281 at P 421, order on reh'g, Order No. 719-A, FERC Stats. & Regs. ¶ 31,292 at P 156. 27. We disagree with LPPC's statements that information about long-term agreements between non-public utilities would not assist the Commission in conducting a DPT analysis for market-based rate authorizations and mergers. The DPT measures market concentration by identifying the sellers that could compete to sell electricity in a relevant market. In defining the relevant market, the DPT identifies potential suppliers based on market prices, input costs, and transmission availability, and calculates each supplier's economic capacity and available economic capacity for each season/load condition. 57 A supplier's economic capacity measures the amount of generating capacity owned or controlled by a potential supplier with variable costs low enough that energy from such capacity could be economically delivered to the destination market. 58 To determine the total supply in the relevant market, the DPT adds the total amount of economic or available economic capacity located in the relevant market (including capacity owned by the seller and competing suppliers) with that of economic or available economic capacity that can be imported into the relevant market. 59 Economic capacity is based on total nameplate or seasonal capacity of generation owned or controlled through contract and firm purchases, reduced by operating reserves, and long-term firm sales. Available economic capacity is calculated by deducting long-term obligations including native load obligations from the economic capacity value. Therefore, information about long-term sales agreements between non-public utilities can be used to help determine the total supply in the relevant market. In addition, information about sales made by non-public utilities, including under long-term agreements, can assist the Commission in performing ex post analyses to determine whether a seller with market-based rate authority has obtained the ability to exercise market power since the original authorization to transact at market-based rates or since its last updated market power analysis. 57 See Market-Based Rates for Wholesale Sales of Electric Energy, Capacity and Ancillary Services by Public Utilities, Order No. 697, FERC Stats. & Regs. ¶ 31,252, at P 106, clarified, 121 FERC ¶ 61,260 (2007), order on reh'g, Order No. 697-A, 73 FR 25832 (May 7, 2008), FERC Stats. & Regs. ¶ 31,268, order on reh'g, Order No. 697-B, 73 FR 79610 (Dec. 30, 2008), FERC Stats. & Regs. ¶ 31,285 (2008), order on reh'g, Order No. 697-C, 74 FR 30924 (June 29, 2009), FERC Stats. & Regs. ¶ 31,291 (2009), aff'd sub nom. Montana Consumer Counsel v. FERC, No. 08-71827, 2011 U.S. App. LEXIS 20724 (9th Cir. Oct. 13, 2011). 58 See id. P 96. 59 See id. P 37. b. Existing Sources of Information i. NOPR 28. In the NOPR, the Commission concluded that existing sources of information regarding non-public utility wholesale electricity market transactions did not provide sufficient price transparency. The Commission considered the information made publicly available by the Energy Information Administration (EIA) Form 861, Rural Utilities Service (RUS) Form 12, RTO or ISO postings related to wholesale market prices and market participant bid/offer data, daily index publications, organized exchanges, commercial data providers, and through the Open Access Same-Time Information System (OASIS). Thus, the Commission proposed to expand EQR filing requirements to non-public utilities to provide price transparency that is not available through these existing sources of information. ii. Comments 29. Certain commenters agree with the Commission that information available from existing price publishers and trade processing services is incomplete and, thus, inadequate. 60 However, other commenters argue that the Commission's NOPR is overly broad and proposes to collect duplicative information. 61 They further argue that the Commission must tailor its request to collect information that it currently lacks. California DWR asserts that the Paperwork Reduction Act requires the Commission to certify that a new reporting requirement such as this one is not unnecessarily duplicative of information otherwise reasonably accessible to the Commission. In addition, California DWR asserts that FPA section 220(a)(4) similarly requires that, before additional reporting to ensure price transparency in electric markets may be ordered, the Commission must make a determination that existing data sources are insufficient. California DWR states that in this respect, the NOPR disregards redundant requirements, and requires governmental entities to reformat and re-report already existing data. 62 60 See, e.g., DC Energy at 3; EEI at 3-6; Joint Market Monitors at 3; NYMPA/MEUA at 3; Pacific Northwest IOUs at 2; Pennsylvania Commission at 6; Powerex at 4; Ronald Rattey at 10; Shell Energy at 2. 61 California DWR at 3-5; NRECA at 4-5; Public Systems at 13-16. 62 California DWR at 3, 5-6. 30. Numerous commenters argue that sufficient information is already publicly available to meet the objectives of FPA section 220 to “ensure that consumers and competitive markets are protected from the adverse effects of potential collusion or other anticompetitive behaviors” without requiring non-public utilities to file EQRs. 63 NRECA argues that the additional information that would be available in the EQR does not justify the increased burden on non-public utilities. 64 For instance, NRECA states that, as recognized in the NOPR, non-public utilities annually file Form EIA-861 “Annual Electric Power Industry Report” and that cooperatives receiving RUS financing also are required to file RUS Form 12. 65 California DWR adds that the NOPR concedes that data is available from EIA as well as from RTOs and ISOs. 66 63 See, e.g. California DWR at 4-5; NRECA at 2, 5; Transmission Dependent Utility Systems at 3. 64 NRECA at 5-6. Allegheny, Associated Electric Cooperative, and South Mississippi Electric each support NRECA's comments. 65 NRECA at 4-6 (“This form [EIA-861] includes information regarding peak load, generation, electric purchases, sales, revenues, customer counts and demand-side management programs, green pricing and net metering programs, and distributed generation capacity.” RUS Form 12 “includes information regarding electric purchases, sales and revenues.”). 66 California DWR at 3. 31. NRECA states that a substantial amount of information is available from these sources and others. For example, it asserts that EIA provides access to the daily volumes, high and low prices, and weighted average prices from hubs around the country and that Energy Management Institute provides results of a daily survey of wholesale transactions that it conducts in all the major trading regions of the country. NRECA further submits that forward market prices are available through the New York Mercantile Exchange and the Intercontinental Exchange (ICE). NRECA argues that it is inappropriate to increase reporting burdens on consumer-owned entities merely to avoid some effort on the part of the government to collect this information from various sources. NRECA concludes that the increased burden on non-public utilities that would be imposed by the EQR filing requirement is not justified by the information that would be obtained. 67 67 NRECA at 5. 32. California DWR, Public Systems, and TAPS also note that significant amounts of data also are available from RTOs and ISOs. 68 California DWR states that most of the desired information may be obtained from existing sources such as RTOs, ISOs or Commission-jurisdictional counterparties of governmental entities. 69 EEI and Public Systems argue that the Commission should collect EQR information directly from RTOs and ISOs because, as the Commission recognized in the NOPR, RTOs, and ISOs already make information publicly available. 70 Public Systems state that ISO-NE., the Commission, and others publish reams of data that facilitate price transparency in the New England markets. They note that ISO-NE's “Markets” page provides links to numerous data compilations and descriptions, including a real-time “LMP Price Ticker” and a link to its real-time “LMP Map.” 71 Public Systems further state that the NOPR would require non-public utilities to repackage the voluminous market-settlement data that they receive from the RTO and to file that data in EQRs. 68 California DWR at 3; Public Systems at 14; TAPS at 18. 69 California DWR at 2-3. 70 EEI at 21; Public Systems at 13. 71 Public Systems at 14-15. Public Systems explains that the “LMP Map” shows: (1) Day-ahead market locational marginal prices (LMP) for the current hour, by load zone, along with the relevant binding constraints; (2) corresponding LMPs and constraints for the real-time energy market; and (3) real-time reserve-market clearing prices and regulation prices. 33. Public Systems state that the NOPR does not rely on data that RTOs already publish “to the maximum extent possible” under FPA section 220. Rather, argues Public Systems, the NOPR identifies certain information gaps in existing sources, such as information about bilateral transactions in the RTO market or sales outside of the RTO markets, and then uses those gaps to justify requiring non-public utilities to file EQRs covering all of their wholesale transactions, including those settled in the RTO markets. Public Systems state that, as a result, the NOPR would require a non-public utility with more than a de minimis presence in organized markets to file data about bilateral transactions and sales outside the RTO markets in its EQR along with voluminous market-settlement data that they receive from the RTO. 72 72 Id. at 15. 34. California DWR states its wholesale transactions already are captured in EIA reports and California ISO postings, with the exception of non-California ISO bilateral transactions that California DWR may engage in. Thus, argues California DWR, the NOPR would require extensive duplication through a full EQR filing to collect a relatively small amount of data. California DWR states that in this respect, the NOPR disregards redundant requirements, and requires governmental entities to reformat and re-report already existing data. 73 Similarly, EEI also encourages the Commission to ensure that the EQR only requires reporting of information that is truly necessary, though it states that it agrees with the Commission that available information from existing price publishers and trade processing services is incomplete and thus inadequate. 74 73 California DWR at 4-5. 74 EEI at 6. iii. Commission Determination 35. The Commission finds that the degree of price transparency provided by existing sources of information about wholesale markets is insufficient for the Commission to fulfill Congress' directive in FPA section 220 to facilitate price transparency in interstate markets for the sale and transmission of electric energy. As discussed in the NOPR, 75 the Commission has considered the degree of price transparency provided by a number of sources of publicly available information, including EIA Form 861 and RUS Form 12, 76 RTO and ISO postings, index publications, organized exchanges, commercial data providers, and through OASIS, and concludes that the degree of price transparency provided by these existing information sources is not sufficient to help ensure an adequate level of transparency in jurisdictional markets. 75 NOPR, FERC Stats. & Regs. ¶ 32,676 at PP 34-39. 76 RUS Form 12 was recently renamed the RUS Financial and Operating Report Electric Power Supply. 36. In general, the Commission and the public need a more compete picture of markets across the country, including smaller markets, even if a significant part of those markets is served by non-public utilities. Market dynamics, including markets dominated by non-public utilities, can change throughout the year through a host of factors including weather conditions, outages, and contract expirations. 37. Annual data collections from two of the most significant publicly available forms that capture information about non-public utility power sales, the EIA Form 861 and the RUS Form 12, do not provide sufficiently detailed or timely information to assess those market dynamics. As stated in the NOPR, EIA Form 861 does not detail individual wholesale transactions, including the counterparty, location, price, and delivery timeframe as well as other transaction details combined in the EQR. 77 Instead, EIA Form 861 filers report their aggregated annual volume of sales for resale and corresponding revenues. In addition, cooperatives that fall under 7 U.S.C. 901 provide accounting details, including the energy purchaser and other contract details for individual energy sales in RUS Form 12. However, as stated in the NOPR, RUS Form 12 provides only limited price transparency because the form does not contain information on delivery location and timing, which are critical elements for gaining insight into price formation. 78 77 See NOPR, FERC Stats. & Regs. ¶ 32,676 at P 35. 78 Id. 38. As recognized by certain commenters, and in the NOPR, 79 RTOs, and ISOs make available a significant amount of information about the availability and prices for wholesale sales and transmission service within these markets. However, as stated in the NOPR, the Commission believes that it is equally important to increase transparency broadly across all markets subject to the Commission's jurisdiction by requiring market participants, including non-public utilities with more than a de minimis presence in those markets, to provide information through EQRs. 80 The Commission finds that this information should include not only non-public utilities' bilateral transactions in an RTO or ISO market or sales outside of the RTO or ISO markets, but also sales made by non-public utilities to the RTO or ISO markets. The EQR provides a level of transparency that RTO or ISO postings do not because it informs the public which market participants were involved across markets and at what level. Obtaining information about such sales will improve transparency by providing the public and the Commission with the ability to view a broader universe of non-public utility sales. Specifically, the EQR provides a greater level of transparency by providing information in one place about a filer's wholesale transactions, including the counterparty, delivery location, price, and delivery timeframe as well as other transaction details. Furthermore, in response to Public Systems' concern that non-public utilities would be required to repackage voluminous market-settlement data that they receive from the RTO and to file that data in EQRs, we note that Order No. 2001 permitted RTOs and ISOs to file power sales transaction information on behalf of members or market participants as an agent, if authorized to do so by the member or market participant. 81 The Commission has also encouraged efforts that allow market participants to request EQR-ready settlement reports from RTOs and ISOs and will continue to do so. 82 79 Id. P 25. 80 Id. 81 Order No. 2001, FERC Stats. & Regs. ¶ 31,127 at P 336. 82 Order No. 2001-E, 105 FERC ¶ 61,352 at P 12. 39. Moreover, the Commission finds that the information collected through the EQR filing requirements in this Final Rule will not result in unnecessary duplication of information accessible to the Commission and the public. Market transparency is not served if market participants are required to piece together various sources with disparate, inconsistent, or potentially incomplete data. The EQR will facilitate price transparency by providing a uniform electronic information system with filers timely reporting data under a consistent set of rules for a specific period of time. c. De Minimis Threshold i. NOPR 40. In the NOPR, the Commission proposed that a non-public utility would be exempt under the de minimis market presence threshold from filing EQRs if it makes 4,000,000 MWh or less of annual wholesale sales (based on an average of the wholesale sales it made in the preceding three years), unless the non-public utility is a Balancing Authority that makes 1,000,000 MWh or more of annual wholesale sales (based on an average of wholesale sales it made in the preceding three years). Furthermore, the Commission concluded that FPA section 220 focuses on the availability and prices of “wholesale electric energy and transmission service,” and therefore proposed to use only the wholesale electricity sales made by non-public utilities for purposes of calculating the de minimis market presence threshold. The Commission proposed that a non-public utility use the annual wholesale sales volume it currently reports to EIA as “Sales for Resale” to calculate whether it meets the de minimis threshold. ii. Comments (a) Setting the Threshold 41. Many commenters support the Commission's proposal in the NOPR to set a de minimis threshold of 4,000,000 MWh of annual wholesale sales for non-public utilities. 83 LPPC asserts that EQR information from non-public utilities with relatively small roles in the marketplace would be of minimal value to the Commission and the public, and contribute little to transparency goals. 84 83 See, e.g., Allegheny at 4; APPA at 4; Cities/M-S-R at 8-9; LPPC at 3; NRECA at 2; NYMPA/MEUSA at 1; Pennsylvania Commission at 8; Powerex at 3; Public Systems at 7; TAPS at 4. 84 LPPC at 1. 42. However, other commenters suggest lowering the de minimis threshold to 1,000,000 MWh for all non-public utilities. 85 EEI and Pacific Northwest IOUs state that this would more accurately and fairly honor the statutory exception for de minimis participants, and would provide a clearer picture of transactions occurring in the nation's electricity markets and the operation of those markets. 86 DC Energy states that the threshold should be lowered to 1,000,000 MWh to ensure that all entities that may have an impact on wholesale market prices are required to submit EQR data and to provide for complete price transparency across the wholesale electricity markets. 87 85 See, e.g., DC Energy at 5; EEI at 7; Pacific Northwest IOUs at 2. 86 EEI at 7; Pacific Northwest IOUs at 2. 87 DC Energy at 5. 43. EEI submits that setting the threshold at 4,000,000 MWh would still leave a significant portion of the market unreported. EEI states that by setting the threshold at 1,000,000 MWh, the Commission would gain substantial additional information while inconveniencing a modest number of non-public utilities. EEI explains that, according to the EIA, of the 3,265 entities (including both public and non-public utilities) that filed the Form EIA-861 in 2009, 138 had sales over 4,000,000 MWh representing 91.8 percent of total U.S. wholesale sales, whereas 254 had sales over 1,000,000 MWh representing 98.7 percent of total U.S. wholesale sales. Of the 116 entities with sales between 1,000,000 and 4,000,000 MWh, EEI asserts that 67 were public power agencies and cooperatives representing approximately 3.9 percent of total U.S. wholesale sales, and the remaining 49 were investor-owned utilities and private power marketers representing 3.0 percent of such sales. 88 EEI further states that according to the NOPR's burden statement, only five non-public utility Balancing Authorities are picked up if the threshold for Balancing Authorities is reduced from 4,000,000 to 1,000,000 MWh. 89 88 EEI at 8 (citing NOPR, FERC Stats. & Regs. ¶ 32,676 at P 125). 89 Id. 44. Conversely, other commenters suggest that the Commission should increase the 1,000,000 MWh annual wholesale sale threshold for Balancing Authorities to 4,000,000 MWh or less. 90 NRECA suggests that a threshold of at least 4,000,000 MWh annual wholesale sales, akin to that used for non-Balancing Authorities, would still capture sales by non-public utility Balancing Authorities with a significant market presence without exposing small Balancing Authorities to a reporting requirement that would place a significant burden on them with no corresponding benefit to the Commission or to the market. NRECA states that the proposed 1,000,000 MWh threshold reflects an approximately 114 MW baseload energy sale, which is too small to have more than a de minimis impact on any market. Therefore, NRECA asserts that the requirement places the burden of filing EQRs on Balancing Authorities that do not have more than a de minimis market presence. 91 90 See, e.g., NRECA at 16; TAPS at 6. 91 NRECA at 16-17. 45. Similarly, TAPS requests that the Commission apply the 4,000,000 MWh wholesale sales de minimis threshold uniformly, regardless of whether the non-public utility is a Balancing Authority. TAPS asserts that applying a lower de minimis threshold to non-public utilities that are Balancing Authorities is insufficiently explained, unduly discriminatory, and inconsistent with the statute. TAPS argues that the Commission's authority to require reporting by non-public utilities turns on whether the non-public utility at issue has a de minimis market presence. TAPS states that being a Balancing Authority does not magnify the market impact of a non-public utility's sales. TAPS states that nothing in the NOPR justifies a finding that a Balancing Authority that sells 1,000,000 MWh at wholesale annually has more than a de minimis market presence, and that there is nothing about being a Balancing Authority that should lead to such a conclusion. 92 92 TAPS at 6. 46. Finally, Shell Energy supports adopting a de minimis level below which specific transactions would not be required to be reported in the EQRs. Shell Energy states that a minimum threshold for reporting by all EQR filers could be either a volume cut-off or a capacity cut-off, and that a reasonable threshold would be transactions below 10 MWh or under $1,000. Alternatively, Shell Energy asserts that the Commission should exclude from EQR reporting any transactions that are under 10 MWh or $1000 and are undertaken simply for balancing energy with an RTO or ISO. Shell Energy explains that it is involved in large numbers of such balancing transactions, each of a very small volume and the reporting of such transactions is onerous while not providing very helpful information to the Commission. 93 93 Shell at 12. (b) Applying the Threshold 47. Several commenters suggest that the Commission should exclude intra-familial sales by non-public utilities for purposes of the annual sales threshold. 94 NRECA notes that FPA section 220(d) provides that, “[t]he Commission shall not require entities who have a de minimis market presence to comply with the reporting requirement of this section.” 95 Allegheny, NRECA, and Public Systems state that intra-familial sales transactions do not result in any “market presence” because they take place entirely outside of the markets. 96 NRECA argues, as such, intra-familial sales are outside the scope of transactions in section 220 of the FPA. 97 94 See, e.g., Allegheny at 4; Associated Electric Cooperative at 3; NRECA at 10; Public Systems at 2; Transmission Dependent Utility Systems at 3. 95 NRECA at 12. 96 Additionally, TAPS states that the fact that joint action agencies and G&T cooperatives cost-based inter-familial sales are not market sales justify excluding those transactions. TAPS at 10. 97 NRECA at 12. 48. According to NRECA, member cooperatives enter into long-term, cost-based, pass-through power contracts. NRECA states that the prices and volumes of such power sales are not influenced by market prices, and have no influence on market prices because they are established without regard to wholesale markets. 98 Allegheny submits that such sales are essentially the distribution cooperative members supplying themselves. Allegheny further states that these G&T cooperative sales are not market sales and do not affect the general marketplace for electricity because: (1) The sales are available only to the member-owners; (2) the member-owners are required to purchase the amounts covered by the contract and therefore they cannot purchase these amounts in the market; and (3) the G&T cooperatives cannot elect to sell these resources to third parties instead of to their members. Therefore, Allegheny asserts that such sales should be excluded from the 4,000,000 MWh threshold. 99 98 Id. at 10-11. 99 Allegheny at 4-5. 49. Allegheny, NRECA, Public Systems, and Transmission Dependent Utility Systems submit that intra-familial transactions by non-public utilities are functionally equivalent to the operation of vertically-integrated public utilities. 100 NRECA states that it would be unjust and unreasonable for the Commission to require non-public utilities to include intra-familial transactions in calculating the 4,000,000 MWh sales threshold and in reporting data in EQRs when it does not require investor-owned utilities to report transfers between their bulk power and distribution functions, because those contracts do not have any relationship to markets for the wholesale sale of power. 101 100 NRECA at 11-12; Allegheny at 5; Transmission Dependent Utility Systems at 5; Public Systems at 11. 101 NRECA at 11-12. 50. NRECA further alleges that the Commission's justification for including intra-familial transactions in calculating the 4,000,000 MWh threshold is not valid; the inclusion of such transactions in EQRs will not assist the Commission or the public in understanding RTO or ISO market price formation because these transactions do not impact the market price. 102 Transmission Dependent Utility Systems suggest that the Commission should restrict any EQR filing obligations imposed on G&T cooperatives that are non-public utilities to wholesale sales to parties other than their distribution cooperative members where those wholesale sales to third parties equal or exceed the 4,000,000 MWh threshold. 103 102 Id. at 12. 103 Transmission Dependent Utility Systems at 8. 51. TAPS suggests that if the Commission adopts a final rule providing that G&T cooperatives' cost-based sales to their members do not count toward determining where the cooperative has more than a de minimis wholesale market presence, comparability requires that joint action agency sales to members be treated in the same fashion. 104 Associated Electric Cooperative and NRECA comment that if the Commission does not exclude intra-familial transactions, it should at least not require both tiers of G&T cooperatives in a three-tier system to report their sales on their EQRs, because this would result in double reporting. 105 104 TAPS at 10. 105 NRECA at 17; Associated Electric Cooperative at 3-4. 52. Cities/M-S-R state that the proposal that EIA data should be used by the joint action agency to determine whether it meets the de minimis threshold for filing EQRs is reasonable and should be included in the final rule. However, Cities/M-S-R request that sales by joint action agencies to the joint action agencies' members should be excluded from reporting because the EIA data currently posted from 2009 do not appear to include in the “Sales for Resale” figure the sales from joint action agencies to their members. Accordingly, Cities/M-S-R state that it is not clear how the Commission plans to compile data regarding sales by joint action agencies to their own members. If the Commission does not exclude transactions between joint action agencies and their members, then Cities/M-S-R request that the Commission clarify how joint action agencies should determine their volume of sales for purposes of determining whether or not they exceed the threshold. 106 106 Cities/M-S-R at 10-11. 53. Southwestern Power Administration states that the Commission's proposal of a de minimis threshold with no procedure for waiver is unreasonable for entities largely reliant upon recent weather patterns to determine sales volumes. Southwestern Power Administration explains that its annual sales from Corps Hydropower facilities are dependent upon annual inflows, which vary greatly from year-to-year. Establishing a threshold based on a one- to three-year timeframe may require utilities such as Southwestern Power Administration, which are dependent upon inflow in order to make sales, subject to the filing requirements simply because of a period of above average rainfall and may not truly reflect the utility's presence in the region. 107 107 Southwestern Power Administration at 4-5. iii. Commission Determination 54. The Commission will uniformly adopt a 4,000,000 MWh de minimis threshold for all non-public utilities, including for non-public utilities that are Balancing Authorities. Specifically, the Commission will exempt under the de minimis market presence threshold non-public utilities that make 4,000,000 MWh or less of annual wholesale sales (based on an average of the wholesale sales it made in the preceding three years). To ensure the uniform application of the de minimis threshold, the Commission will not adopt the NOPR proposal to require a non-public utility that is a Balancing Authority making 1,000,000 MWh or more of annual wholesale sales to file EQRs. Instead, the Commission will apply the 4,000,000 MWh threshold to these non-public utility Balancing Authorities. As set forth in the NOPR, the Commission will use wholesale sales, as reported in EIA Form 861, “Sales for Resale,” to calculate the de minimis market presence threshold. 55. In response to commenters that suggest a 1,000,000 MWh de minimis threshold, we note that the 4,000,000 MWh threshold adopted by this Final Rule will significantly increase transparency, particularly in certain markets with large non-public utility concentrations. In requiring non-public utilities to report EQR information, we must balance transparency benefits associated with the data collection with any burdens it may create. EEI comments that EIA Form 861 data indicates that setting the threshold at 1,000,000 MWh instead of 4,000,000 MWh would capture sales from an additional 67 public power agencies and cooperatives representing approximately 3.9 percent of the nation's wholesale sales. However, the Commission finds that the value of collecting information from non-public utilities making between 1,000,000 and 4,000,000 MWh of annual wholesale sales does not outweigh the burden that would be imposed on these small non-public utilities. This determination is consistent with the definition of a small utility under the Regulatory Flexibility Act 108 and Small Business Act. 109 The Small Business Administration's implementing regulations at 13 CFR 121.201 define a utility as small “if, including its affiliates, it is primarily engaged in the generation, transmission, and/or distribution of electric energy for sale and its total electric output for the preceding fiscal year did not exceed 4 million megawatt hours.” This 4,000,000 MWh threshold is also consistent with the threshold used in FPA section 201(f) to exclude certain electric cooperatives from the Commission's jurisdiction. 110 Therefore, the Commission will not lower the de minimis threshold to 1,000,000 MWh of annual wholesale sales for non-public utilities, as suggested by certain commenters. 108 See 5 U.S.C. 601. 109 See 15 U.S.C. 632. 110 FPA section 201(f) provides, in relevant part: “[n]o provision in this subchapter shall apply to, or be deemed to include * * * an electric cooperative that receives financing under the Rural Electrification Act of 1936 (7 U.S.C. 901 et seq. ) or that sells less than 4,000,000 megawatt hours of electricity per year.” 16 U.S.C. 824(f). 56. We will not adopt Shell Energy's suggestion to establish a de minimis reporting threshold for EQR filers based on their transactional volumes or capacity or exclude from reporting certain transactions undertaken for balancing energy with an RTO or ISO. As set forth in Order No. 2001, public utilities are required to file information in the EQR to comply with the requirement under FPA section 205(c) to show all rates, terms, and conditions of jurisdictional services. 111 The Commission has granted waiver of the EQR filing requirements for certain small public utility entities based on a number of factors. 112 Based on the statutory requirement for all public utility rates, terms and conditions to be on file with the Commission and the ability for small public utility entities to apply for waiver from the EQR filing requirement, the Commission concludes it is not necessary to establish a minimum reporting threshold based on the volume or nature of transactions undertaken by public utilities. The Commission also finds that this Final Rule appropriately sets the de minimis threshold for non-public utility filers based on their annual wholesale sales rather than on the volume or nature of their transactions. 111 Order No. 2001, FERC Stats. & Regs. ¶ 31,127 at PP 11, 44. 112 See Bridger Valley Elect. Assoc., Inc., 101 FERC ¶ 61,146 (2002). 57. Consistent with the NOPR proposal, the Commission finds it appropriate to use the total annual wholesale sales volumes reported as “Sales for Resale” in EIA Form 861 for purposes of calculating the de minimis threshold. 113 Basing the threshold calculation on the total annual wholesale sales figure already reported by non-public utilities in EIA Form 861 will avoid the need for them to make a separate calculation of annual wholesale sales for EQR purposes and ensure a consistent method for calculating the threshold. Therefore, in response to Cities/M-S-R's request for clarification of how joint action agencies should determine whether they exceed the de minimis threshold, we clarify that they should use the wholesale sales volumes reported as their “Sales for Resale” figure in EIA Form 861. However, as explained below, the Commission will not require non-public utilities to report sales made to members, or intra-familial sales, in the EQR. 114 In light of the determination to exclude from the EQR reporting requirement sales by cooperatives or joint action agencies to their members, we will not address comments concerning how to report such member sales. 113 EIA Form 861 instructions for Line 12, define “Sales for Resale” as the amount of electricity sold for resale purposes, including “sales for resale to power marketers (reported separately in previous years), full and partial requirements customers, firm power customers and nonfirm customers.” See EIA, Annual Electric Power Industry Report Instructions, available at http://www.eia.gov/survey/form/eia_861/instructions.pdf. 114 We note that while the threshold calculation is based on total wholesale sales, entities may not have to report all of their wholesale sales. For additional discussion, see supra § II.A.1.a. and infra § II.A.2.a. 58. In response to Southwestern Power Administration's comments that its annual sales vary greatly from year-to-year due to rainfall rates, the Commission finds that using a three-year average of total wholesale sales to calculate an entity's filing status helps moderate possible fluctuations in an entity's filing status. Moreover, information capturing fluctuations in wholesale sales can provide valuable details on the competitiveness of electricity markets. 115 115 See discussion at supra P 18. 2. Filing Requirements for Non-Public Utilities a. Scope of EQR Filing Requirements for Non-Public Utilities i. NOPR 59. The Commission proposed to require a non-public utility with more than a de minimis market presence to report the same contractual and transactional information about its wholesale sales and transmission service, including cost-based and market-based sales, transmission service, and transmission capacity reassignments, that public utilities currently report. The Commission also proposed to include sales made by G&T cooperatives, joint action agencies, state agencies, and power or water districts to their own members. The Commission proposed to exclude, however, certain fields that it concluded may not be applicable to filings made by non-public utilities. As an example, the Commission noted that non-public utilities may not possess an appropriate FERC Tariff Reference to include in contract data Field Number 19 (FERC Tariff Reference) and transaction data Field Number 50 (FERC Tariff Reference) and would mark “Not Required” or “n/r” in these fields. ii. Comments 60. EEI agrees that the Commission should require all parties to file the same basic EQR information. However, EEI also encourages the Commission to ensure that the EQR only requires reporting of information that is necessary and useful for the Commission to collect and that market participants can provide in the normal course of business. 116 116 EEI at 6-7. 61. Several commenters argue that the Commission should not require entities such as joint action agencies, state agencies, power districts, and G&T cooperatives to report sales made to their own member utilities or long-term distribution customers under long-term agreements. 117 TAPS asserts that requiring joint action agencies and G&T cooperatives to report their cost-based sales to members is contrary to FPA section 220 because it imposes reporting requirements that do not advance the section's objective of enhancing market transparency. TAPS contends that reporting such sales would provide no information regarding the rates, terms or conditions under which a joint action agency would be willing to sell power to a non-member, nor would it provide information about the alternative rates, terms, and conditions under which the members could obtain power from other sources. 118 117 See, e.g., APPA at 4; Cities/M-S-R at 9; Public Systems at 9; TAPS at 11. 118 TAPS at 11. 62. APPA similarly argues that such sales play no role in price formation. According to APPA, sales by a joint action agency to its members are cost-based sales under long-term contracts that do not reflect current commercial conditions or market supply and demand. 119 Cities/M-S-R state that such sales typically reflect only the cost of production of the energy and the repayment of bond financing and are not arm's-length transactions that reflect market conditions; thus, such transactions should not be reported. 120 119 APPA at 4-5. 120 Cities/M-S-R at 10. 63. While Public Systems agree that such sales are technically wholesale sales, they argue that such sales are not market sales and therefore do not reflect the rates, terms, or conditions on which a joint action agency would be able or willing to sell energy at wholesale to any other entities. 121 Transmission Dependent Utility Systems state that distribution cooperatives form G&T cooperatives to obtain cost efficiencies and that they enter into long-term contracts with their members to serve as security to finance generation and transmission facilities. Transmission Dependent Utility Systems argue that even though sales by a G&T cooperative to its members are wholesale sales, these sales are not the type of arm's-length sales between two wholesale market participants that determine market prices. Instead, Transmission Dependent Utility Systems argue that the initial purchase of power by the G&T cooperative is the significant transaction. According to Transmission Dependent Utility Systems, such sales are already reported in the EQR by the selling market participant. Thus, Transmission Dependent Utility Systems argue that there is no additional price information to be gleaned from the flow-through of purchased power from a G&T cooperative to its distribution member cooperative. 122 121 Public Systems at 9. 122 Transmission Dependent Utility Systems at 5-6. 64. A number of commenters argue that joint action agencies and G&T cooperatives are analogous to vertically-integrated utilities. 123 APPA states that joint action agencies are virtually vertically integrated with their member distribution systems, and argues that if they were literally vertically integrated, then there would be no wholesale sale to report. APPA argues that the same is true of sales by state agencies and power districts to neighboring distribution utilities through full requirement or other types of firm, long-term contracts. 124 TAPS argues that transactions involving G&T cooperatives and joint action agencies are wholesale sales in name only, and arise only because the individual members were too small to conduct such activities on their own and had to create a distinct legal entity to perform them on a joint basis. 125 Public Systems also assert that joint action agencies and G&T cooperatives use contracts to accomplish what vertically-integrated utilities accomplish through their corporate structure and thus sales to their members should not be considered wholesale sales. 126 123 See, e.g., APPA at 5; Public Systems at 12; TAPS at 9. 124 APPA at 5. 125 TAPS at 9. 126 Public Systems at 10. 65. Public Systems and TAPS argue that requiring joint action agencies and G&T cooperatives to report sales to their members is unduly discriminatory because the Commission does not require other non-market transactions that affect the amount of demand served through the market. 127 For instance, TAPS states that the Commission does not require a load-serving entity to report when it engages in demand response, installs energy efficiency measures, or relies on its own generation to serve its load even though such activities reduce the load-serving entity's need for market purchases. 128 127 Public Systems at 12; TAPS at 12. 128 TAPS at 12. 66. TAPS also argues that it may be difficult to fit joint action agency sales to members into the categories the Commission has developed to describe other types of transactions. TAPS contends that this is evidence that such sales are not market transactions and cannot be compared to them meaningfully. 129 129 Id. 14. 67. Transmission Dependent Utility Systems argue that there is no potential in the transaction between the G&T cooperative and its member for exploitation of the kind that the FPA is intended to prevent. In support, Transmission Dependent Utility Systems state that the Commission has recognized in a number of orders that affiliate abuse is not a concern for cooperatives owned by other cooperatives. 130 APPA also cites to a Commission order that reasoned that “sales of power by G&T cooperatives to their member G&T cooperatives or their member distribution cooperatives do not constitute marketing functions under the Standards of Conduct.” 131 Thus, APPA contends that there is no need for a joint action agency to report sales to members in its EQR. 130 Transmission Dependent Utility Systems at 7-8 (citing Desert Generation & Transmission, Inc., 115 FERC ¶ 61,306, at P 14 (2006)). 131 APPA at 5-6 (citing Standards of Conduct for Transmission Providers, Order No. 717, FERC Stats. & Regs. ¶ 31,280 (2008), order on reh'g and clarification, Order No. 717-A, FERC Stats. & Regs. ¶ 31,297 (2009), order on reh'g and clarification, Order No. 717-B, 129 FERC ¶ 61,123, order on reh'g and clarification, Order No. 717-C, 131 FERC ¶ 61,045, at P 21 (2010)). 68. Cities/M-S-R disagree with the Commission's assertion that if a joint action agency, state agency, or power or water district did not supply its members then its members would have to purchase supply from other sources in the market. Instead, Cities/M-S-R assert that without the joint action agency, a member would likely develop its own resource. 132 132 Cities/M-S-R at 9-10. 69. TAPS asserts that if a member makes a sale of excess power into the market, then it would be required to report that sale in the EQR, assuming that the selling member had more than a de minimis market presence. Thus, TAPS argues that a potential resale at wholesale of power supplied by a joint action agency or G&T cooperative to its members does not justify requiring joint action agencies and G&T cooperatives to report sales to their members. 133 133 TAPS at 13. 70. If the Commission does not exclude a G&T cooperative's sales to its members from reporting requirements, then NRECA argues that the Commission should not require cooperatives with multiple tiers of G&T cooperatives to report their sales. For example, NRECA states that Basin Electric Power Cooperative, a G&T cooperative, sells electric power and energy at wholesale to its `Class A' members, which are also G&T cooperatives. NRECA further states that the Class A members, acting as middlemen, then sell power and energy at wholesale to their distribution cooperative members at essentially the same price as they paid. Given that the price is essentially identical, NRECA argues that the Commission should not require both tiers of these G&T cooperatives to report; otherwise it will lead to double counting. 134 134 NRECA at 17-18. 71. APPA states that a more reasonable alternative would be for the Commission to require state agencies and power districts to report such transactions in their EQRs only to the extent that the applicable firm, long-term contract expires in less than three years. 135 Similarly, LPPC encourages the Commission to exempt from reporting agreements of longer than three years between non-public utilities. 136 In support, LPPC states that much of the power sold pursuant to these long-term arrangements is not available to private entities purchasing power in Commission-jurisdictional markets due to Internal Revenue Service Code restrictions. According to LPPC, these restrictions generally prohibit non-public utilities from selling more than a minimal amount of electricity to private entities; power sold in excess of this limit jeopardizes the nonpublic utility's tax-exempt financing. 137 135 APPA at 7, n.11. 136 LPPC at 4. 137 Id. at 6. 72. In contrast, EEI asserts that non-public utilities should report transaction and contract information on sales between non-jurisdictional entities as well as between non-jurisdictional and jurisdictional entities to provide a more complete picture of energy markets. 138 138 EEI at 6. iii. Commission Determination 73. The Commission adopts the NOPR proposal to require non-public utilities to report the same information about wholesale sales, transmission service, and transmission capacity reassignments that are currently reported by public utilities, with modifications. Expanding the same EQR data elements to non-public utilities will help ensure comparability and consistency with filings by public utilities, which will make it easier for the public and the Commission to use the information. In addition, requiring the same sales and transmission-related information from non-public utilities will allow the Commission to better evaluate the performance of wholesale markets as a whole and make it easier to determine whether jurisdictional prices are just and reasonable. 139 139 See NOPR, FERC Stats. & Regs. ¶ 32,676 at P 45. 74. Many commenters argue that the Commission should not require non-public utilities to report wholesale sales made to their own members or made under long-term, cost-based agreements. As mentioned above, the Commission will modify its NOPR proposal to exclude the following types of wholesale sales from the EQR reporting requirement for non-public utilities above the de minimis threshold: (1) sales by a non-public utility, such as a cooperative or joint action agency, to its members; and (2) sales by a non-public utility under a long-term, cost-based agreement required to be made to certain customers under Federal or state statute. 140 To the extent wholesale sales made by a non-public utility do not meet either of these criteria, the non-public utility must report those sales in the EQR. 140 See discussion at supra § II.A.1.a. 75. The Commission recognizes that certain data fields in the EQR may not be applicable to filings made by non-public utilities. As stated in the NOPR, non-public utilities may not possess a FERC Tariff Reference (Field Numbers 19 and 50) for certain wholesale contracts and transactions. In cases where a FERC Tariff Reference is not applicable, the Commission will require that a filer mark “NPU,” (to indicate “Non-Public Utility”) in those fields. If a non-public utility has a previously filed reciprocity open access transmission tariff (OATT), it should refer to that reciprocity OATT in Field Number 19 under FERC Tariff Reference. In addition, non-public utilities should mark “NPU” with respect to the “cost-based” or “market-based” options available under “Product Type Information” captured in Field Number 30, because these options are defined based on types of Commission-approved tariffs. If transmission capacity is reassigned under a non-public utility's reciprocity OATT, the non-public utility should follow the existing conventions for transmission providers reporting transmission capacity reassignments in the EQR. b. Burden i. NOPR 76. In the NOPR, the Commission recognized that extending the EQR filing requirements to non-public utility market participants will impose a new burden on those market participants. The Commission agreed that it would make every effort to provide guidance and technical assistance prior to implementation of the EQR filing requirements for non-public utilities. ii. Comments 77. Some commenters question whether the Commission has adequately considered the burden imposed on non-public utilities. For example, Southwestern Power Administration asserts that section 220 of the FPA provides the Commission with limited authority to seek information from certain non-public utilities and requires the Commission to weigh the value of the information against the regulatory burden it would impose on those entities. Southwestern Power Administration argues that requiring it to report information about its sales will serve no useful purpose that would justify the burden of reporting this information and that the Commission has not shown otherwise. 141 141 Southwestern Power Administration at 2-3. 78. California DWR argues that the NOPR fails to comply with Federal statutes that require the Commission to carefully consider the costs and benefits of imposing burdens on governmental entities. For instance, California DWR states that the Paperwork Reduction Act requires agencies to certify that a new reporting requirement is not unnecessarily duplicative and that the Unfunded Mandates Reform Act of 1995 requires agencies to prepare a written statement of intergovernmental mandates that describe the analyses and consultations on the unfunded mandate. 142 California DWR also states that Executive Order 12866 requires agencies to propose or adopt regulations after it determines that the benefits of the intended regulation justify the costs and that the Regulatory Right to Know Act requires agencies to conduct cost-benefit analysis of their regulatory initiatives and report their findings to the Office of Management and Budget. 143 142 California DWR at 6-7 (citing Paperwork Reduction Act, 44 U.S.C. 3506(c)(3) (2006); Unfunded Mandates Reform Act of 1995, 2 U.S.C. 1531, et seq. (2006)). 143 Id. at 5-6 (citing Executive Order 12866, 58 FR 51735 (Oct. 4, 1993); Regulatory Right to Know Act, 31 U.S.C. 1105 (2006)). 79. Southwestern Power Administration states that it does not have the staffing needed to track and report EQR data, and that hiring additional staff to comply would pose increased costs with no commensurate benefit to its customers or incremental improvement to market transparency. 144 California DWR argues that the NOPR as written would give non-public utilities an incentive to self-supply to avoid wholesale power sales in order to reduce reporting burdens, which appears contrary to business requirements. 145 144 Southwestern Power Administration at 4. 145 California DWR at 7. 80. If the Commission requires non-public utilities to submit EQRs, then NRECA argues that the Commission could reduce the burden on non-public utilities by simplifying the filing requirements as it relates to billing adjustments. NRECA states that it is common practice for a cooperative to bill its members under long-term contracts on the basis of budgets and that these charges are later trued-up to reflect the actual costs associated with the sale. NRECA states that EQR regulations require entities to file either revised EQRs or new transactions with the class name “Billing Adjustments” to report changes in billing data after the initial EQR filing deadlines. NRECA asserts that it would be very burdensome for cooperatives that use budget-based billing to submit revised EQRs or Billing Adjustments to reflect true-ups to actual costs. Thus, NRECA argues that the Commission should simplify the filing requirements for cooperatives that use budget-based billing by specifying that true-ups associated with budget-based billing do not trigger the requirement to submit revised EQRs or Billing Adjustments. 146 146 NRECA at 18-19. 81. LPPC encourages the Commission to provide sufficient lead time to enable non-public utilities to comply, and suggests a period of six months from the date of the final rule. LPPC also requests that the Commission have staff assist in training programs that will facilitate compliance. 147 147 LPPC at 10. iii. Commission Determination 82. The Commission has carefully weighed, in developing this Final Rule, the burden associated with an entity filing the EQR against the benefits associated with greater transparency in the nation's wholesale electric markets. The Commission concludes that the burden of reporting information in the EQR is outweighed by the benefits of greater transparency provided by the EQR. 83. The burden of preparing an EQR filing varies, depending on the complexity of a company's transactions. If a company has a few long-term contracts of limited complexity, its EQR filing is simple: an unchanging description of its contracts from quarter to quarter with monthly or quarterly reports of the transactions under that contract. As the company's sales activities become more complex, with more frequent adjustments to price and a greater variety of counterparties and sales locations, its technological capabilities for tracking its transactions tend to become more sophisticated. As a result, complex, detailed EQRs tend to be associated with companies more capable of generating such a filing. Filers whose participation in the electric wholesale markets occurs under long-term, cost-based contracts with a limited number of counterparties will expend relatively little effort in complying with the EQR filing requirement. In addition, we believe that excluding from the reporting requirement sales by non-public utilities under long-term, cost-based agreements required to be made to certain customers under Federal or state statute will help lessen the burden on non-public utilities. Therefore, we believe that non-public utilities would not be encouraged to self-supply to avoid the reporting requirements, as suggested by California DWR. 84. In response to NRECA's concern about the difficulty for non-public utility cooperatives that use budget-based billing to submit revised EQRs or billing adjustments to reflect true-ups or actual costs, the Commission will not require true-ups by non-public utility cooperatives with budget-based billing in the EQR. The Commission's policy regarding refilings or billing adjustments stems from the statutory requirement under FPA section 205(c) to have a public utility's rates on file. Specifically, in recognition of the fact that public utilities may not have complete, final data for the full quarter by EQR filing deadlines, the Commission requires that any additions or changes to an EQR filing must be made by the end of the following quarter, when the filer is expected to file the best available new data. 148 Filers are required to file material changes, either as a full refiling or as a transaction with the class name “Billing Adjustment.” 149 It is worth emphasizing that refiling EQRs, with a billing adjustment to reflect the receipt of new information, is only necessary if the filer considers the change to previous EQR totals to be material. 150 The Commission has found that this policy balances the need for timely, accurate EQR data, while reducing the burden on filing entities by identifying price changes on a transaction-by-transaction basis due to some after-the-fact billing transaction long after the EQR was due. 151 In the case of budget-based billing, non-public utility cooperatives are not covered by FPA section 205 and the true-up process will likely have little effect on the market dynamics the Commission is trying to capture with this Final Rule. For these reasons, the Commission will exclude true-ups by non-public utility cooperatives associated with budget-based billing from the EQR's refiling or billing adjustment policy. 148 Order No. 2001-E, 105 FERC ¶ 61,352 at PP 9-10. According to the EQR Data Dictionary, a Billing Adjustment (BA) designates an incremental material change to one or more transactions due to a change in settlement results. BA may be used in a refiling after the next quarter's filing is due to reflect the receipt of new information. It may not be used to correct an inaccurate filing. See Order No. 2001-G, 120 FERC ¶ 61,270 at P 33. 149 Order No. 2001-E, 105 FERC ¶ 61,352 at PP 9-10. 150 Order No. 2001-G, 120 FERC ¶ 61,270 at PP 33-34. 151 Id. 85. We agree with LPPC that the Commission should provide sufficient lead time to enable non-public utilities to comply. Over the past ten years, the Commission has been proactive in its outreach on many aspects of the EQR; in issuing this Final Rule, the Commission acknowledges that new filers will need the opportunity to learn about the filing. Accordingly, non-public utility filers are required to file EQRs beginning with the third quarter (Q3) of 2013, covering the period July through September 2013. The Commission directs staff to assist filers with compliance. For example, the Commission intends to convene a staff-led technical conference, to be announced at a future date, to assist non-public utilities in collecting and filing EQR data. B. Refinements to the Existing EQR Requirements 1. General Refinements a. Trade Date & Time and Type of Rate i. NOPR 86. In the NOPR, the Commission proposed to require any market participant that is required to file an EQR to report in the EQR the date on which parties to a reported transaction agreed upon a price (trade date) and the type of rate by which the price was set. The Commission stated in the NOPR that the term “trade date” means “the date upon which the parties agree upon the price of a transaction.” The Commission also proposed four types of rates: “fixed,” “formula,” “index,” and “RTO/ISO price.” A fixed rate would be defined as a fixed charge per unit of consumption. A formula rate would be defined as a calculation of a rate based upon a formula that does not contain an index component. An index rate would be defined as a calculation of a rate based upon an index or a formula that contains an index component. An “RTO/ISO price” would be defined as a rate that is based on an RTO/ISO published price or formula that contains an RTO/ISO price component. The Commission also proposed to require market participants to report the time of trade, defined as “the time upon which the parties agree upon the price of a transaction.” ii. Comments 87. DC Energy, Joint Market Monitors, and Pennsylvania Commission support the Commission's proposal to require the trade date and time and type of rate in EQR. 152 However, as discussed further below, many commenters are opposed to parts of the proposal. 152 See, e.g., DC Energy at 4-5; Joint Market Monitors at 4-5; and Pennsylvania Commission at 4. (a) Trade Date 88. With respect to the proposed requirement to report the trade date, Powerex states it should not be onerous to report such data because market participants likely already track it. 153 However, some commenters question the need for trade data and note some difficulty in ascertaining the appropriate date to report. EEI questions the need for trade date information, arguing that contracts negotiated to cover specific transactions will include trade-specific details so that transactions can be distinguished based on the associated contract information in the EQR. In addition, EEI suggests that, if the Commission requires reporting of trade dates, it should clarify that the trade date is the effective date of the legally binding agreement between parties with respect to the transaction. In this vein, EEI contends that the “official” trade date agreed to by market participants for each transaction and documented in trade capture systems and related transaction documentation is the appropriate date to use. EEI states that its members and other market participants document the “official” date in their trade capture systems and related transaction documentation. EEI also recommends that the requirement for trade date apply only to transactions entered into after the Commission adopts a final rule. 154 153 Powerex at 14. 154 EEI at 12-13. 89. EPSA asks the Commission to clarify whether RTO or ISO sales are included in the date/time reporting requirement as these transactions do not meet the Commission's proposed definition of agreement of the parties upon a price because RTO or ISO mitigation schemes may alter awarded prices, which are not known to the market participant and are not received until after the flow data. EPSA notes that in its NOI comments it expressed concern that the date parties agree to a price is not synonymous with the transaction date. EPSA adds that there are several elements apart from price, including volume, point of delivery, nature of firmness, credit terms, duration, enabling agreement status, upon which the parties must reach agreement before they execute that trade. EPSA states that “[i]f the final rule makes time and date determinations based on the setting of price there will be a need to clearly explain how that is done for the many scenarios in the power business; only with this additional explanation can complying entities ensure that EQR data is not only transparent but useful.” 155 Entergy questions the usefulness of the trade date and notes examples of situations where the price in effect when the transaction was entered would not be the rate when the transaction began. 156 Entergy adds that, for hourly market sales, a trade date would be difficult to determine because it may be subject to review and agreement at a later date. 157 155 EPSA at 7. 156 Entergy at 2 (“while a rate may be arranged at the outset, changes in tariff rates and other circumstances may affect the rate between the time the transaction was made and the date the transaction flows”). 157 Id. at 2-3. Entergy provides the example of a price for an hourly market sale being agreed upon during the day ahead or on an hourly basis, but the final prices being subject to review and agreement at a later date. Id. at 3. (1) Commission Determination 90. The Commission adopts, with modification, the NOPR proposal to require reporting of the trade date in the EQR. The NOPR proposed to define the trade date as the date on which parties to a reported transaction agreed upon a price. We will clarify this definition of trade date, as suggested by EEI, to state that it is “the date upon which the parties made the legally binding agreement on the price of the transaction.” 91. As stated in the NOPR, the trade date for transactions currently is not provided or collected publicly. 158 The trade date is essential to assessing the significance of prices in relation to market conditions in effect at that time. The EQR only collects the start and end date of physical transactions as well as other data details for contracts. In current EQR filings, trades entered into months before the transaction start and end dates are indistinguishable from trades entered into minutes before the transaction occurs, making it difficult to determine whether pricing is appropriate given market conditions. In addition, many of the prices reported in the EQR result from confirmation made under master agreements and the prices are not set in the contracts themselves, so the Commission is not able to determine from EQR data when the price was set. The Commission concludes that requiring market participants to report the date on which parties to a reported transaction agreed upon a price (trade date) is necessary to improve market transparency. The trade date should be reported in the EQR transaction section accompanied by each specific sales transaction. 158 NOPR, FERC Stats. & Regs. ¶ 32,676 at P 91. 92. We further clarify that, in cases where pricing detail is provided in the contract description, the Contract Execution Date should be considered the trade date. Where applicable, this clarification will virtually eliminate any additional burden associated with this field by allowing the filer to complete the trade date field for each transaction by using a date (Contract Execution Date in the contracts section) already provided in the filing. It also will obviate the need to identify whether this requirement applies to transactions with trade dates before the initial filing that includes this field. It is unlikely that a transaction will occur during or after the first filing under these new rules that both became legally binding before the effective date of this Final Rule and does not have an appropriate Contract Execution Date already reported. 93. In response to EPSA, we clarify that RTO and ISO transactions do, in fact, reflect an agreement of the parties upon a price. Parties are legally bound by the terms of the relevant RTO or ISO tariff and sellers agree to sell a product at the price at which their offer is awarded. Although the price may be altered after it is awarded due to the application of mitigation or other RTO or ISO market rules, we clarify that the trade date should reflect the price at the time of the initial award. RTOs and ISOs operate a number of different markets where similar products are offered. For example, energy can be offered day-ahead or real-time. Capacity is offered monthly, annually and several years in advance. In each of these cases, the addition of a trade date will help the Commission and the public gain a better understanding of the market environment in which a given transaction was consummated. 94. In response to Entergy's concern about hourly transactions being changed at a later date, we clarify that filers are expected to identify the price associated with the transaction as it was agreed to. If there is some disagreement or uncertainty between the parties regarding the terms of the transaction on the “trade date,” the Commission has promulgated a refiling policy to allow the selling party to correct those terms when the disagreement is settled or the uncertainty is eliminated. Correcting the reporting, however, does not change the fact that the reported transaction occurred because the parties to the transaction had agreed to something on a given date. That date would not change even if the parties' understanding of what they agreed to evolves. 95. In addition, in response to EEI's suggestion that the Commission should hold a technical conference to discuss the requirement for trade date data, the Commission notes that it intends to convene a staff-led technical conference following issuance of this Final Rule, to be announced at a future date, to discuss the additional fields required under this Final Rule, including the field for trade date. (b) Time of Trade 96. Several commenters indicate concerns about the NOPR's proposal to require market participants to report the time of trade. Some commenters contend that the time of trade, defined in the NOPR as the time upon which parties agree upon the price of a transaction, can be difficult to identify definitively. 159 Certain commenters argue that the time parties agree on price may not be the time the trade occurred or was finalized. 160 For example, EDF Trading states that parties may agree to the price or pricing mechanism hours or even days before they come to an agreement regarding other material terms of the transaction, meaning that the time upon which parties agree upon the price of a transaction frequently will not correspond to the time at which parties execute or confirm that transaction. 161 159 See, e.g., EDF Trading at 7; EEI at 10-11; Entergy at 2-3; EPSA at 6-7; Pacific Northwest IOUs at 2; Westar at 2. 160 See, e.g., EDF Trading at 7; EEI at 10-11; Entergy at 2-3; EPSA at 7. 161 EDF Trading at 7. 97. Several commenters also state that the actual price of a transaction may be subject to revision even after parties have reached agreement on the price. 162 For example, Westar asserts that if a market participant is party to a liquidated damages contract and the transaction is curtailed, the party will not know the price of the contract until weeks after the power is delivered. 163 Entergy states that rates for future transactions may be affected by changes in tariff rates and other circumstances between the time when the transaction was made and the date the transaction flows. Further, Entergy states that some hourly market sales may have final prices that are subject to review and agreement at a later date. 164 Finally, EPSA states that the Commission needs to clarify whether RTO or ISO sales are included in the date/time reporting requirement as these transactions do not meet the Commission's proposed definition of agreement of the parties upon a price. 165 162 See, e.g., Entergy at 2-3; EPSA at 6-7; Westar at 3. 163 Westar at 3. 164 Entergy at 2-3. 165 EPSA at 6 (“ISO/RTO mitigation schemes sometimes alter awarded prices, which are unknown to the market participant and are not received until substantially after the flow date.”). 98. Some commenters also indicate that existing trade capture systems are not set up to capture the time of trade. 166 For example, Powerex states that the time of trade is not currently recorded and significant work would be required to record time of trade, which would need to account for trades made verbally. 167 EDF Trading states that under its existing systems and procedures, a trader gathers information regarding each transaction as he or she completes it, but does not enter the details of each transaction until later in the day when the trader has completed most trading activities. EDF Trading states that its electronic system creates a time stamp as soon as a trader enters a transaction and this system generates information reported in EDF Trading's EQRs. EDF Trading asserts that, if the Commission requires market participants to report time of trade information, traders will be forced to interrupt their trading activities to enter each trade into the system electronically as soon as parties agree on pricing. According to EDF Trading, such a requirement would eliminate flexibility, reduce trading opportunities, potentially increase the bid/ask spreads, and impose additional time burden on traders during the trading day, the time of day when the markets are at their most active. 168 Similarly, EPSA states that a new requirement to log times will inhibit desk personnel and frustrate liquid markets. 169 166 See, e.g., EDF Trading at 7-8; EEI at 9; Entergy at 1-2; EPSA at 5; Financial Institutions Energy Group at 7; Pacific Northwest IOUs at 2; Powerex at 14; Shell Energy at 8; Westar at 3. 167 Powerex at 14. 168 EDF Trading at 7-8. 169 EPSA at 5. 99. Financial Institutions Energy Group states that time of trade data may be prone to inaccuracies, noting that errors may arise from such factors as clocks that run slow or fast, clocks that are not synched, traders forgetting to look at the time or write it down, time zone confusions, and illegible handwriting. Financial Institutions Energy Group adds that the time on a time-stamped trade confirmation from a third party entity, such as a broker, cannot be independently verified. 170 170 Financial Institutions Energy Group at 8. 100. EEI and Powerex urge the Commission not to apply the proposal to report time of trade to existing transactions. Powerex states that it has some transactions that will continue to be reported to the Commission for years to come and it is not sure how to identify the time of trade for these long-term transactions. 171 Likewise, EEI suggests that the requirement should only apply prospectively for transactions entered into after the Commission adopts the final rule in this proceeding. 172 171 Powerex at 14. 172 EEI at 13. 101. EEI also suggests that the Commission hold a technical conference to: (1) Explore the need for time of trade or trade date data; (2) gain a better understanding of impacts on EQR filers and affected systems; and (3) ensure that any such reporting requirement is carefully tailored to maximize benefits while minimizing the burden on reporting entities. 173 173 Id. at 14. (1) Commission Determination 102. The Commission will not require the time of trade, as proposed in the NOPR. As noted in many comments, it may be difficult to specify definitively the time at which parties agreed upon the price of a transaction and the actual price of the transaction may be revised after parties have agreed on the price. In addition, certain commenters expressed concern that existing trade capture systems are not set up to capture the time of trade and such a requirement may impose additional time burden on market participants. In light of these comments, the Commission has determined not to require reporting of the time of trade. (c) Type of Rate 103. EEI questions the need for information regarding the type of rate for each transaction and contends that the specific nature of the rate involved in a transaction can already easily be determined using the Contract Service Agreement ID information provided in the EQR contract data. In addition, EEI argues that the burden of providing rate type information separately will outweigh its value and asserts that rate type information may be difficult to specify, will be of little use, could be misleading, and will cause errors. 174 EEI states that, if the Commission requires rate type information, the Commission should allow substantial flexibility, recognizing the wide variety of rates currently in use. 175 174 In particular, EEI notes that reporting rate type will require EQR filers to determine: whether a formula rate with a gas or fuel index (or any other index that is not an energy or capacity price index) is an “index” or “formula” rate; what rate type to use for an exchange agreement; and what to report if a trade is a combination of types. Id. at 15. 175 Id. at 14-15. 104. Finally, EEI asks for clarification as to what type of rate would apply to the following examples: (1) A formula rate with a gas or fuel index (or any other index that is not an energy or capacity index); (2) a rate used for an exchange agreement where one party pays an additional charge in addition to supplying return energy; (3) a rate structure that goes up (and/or down) a stated amount each year; and (4) a formula that is tied to an RTO price, i.e., the greater of the RTO price or the contract price. 176 176 Id. at 15. (1) Commission Determination 105. The Commission adopts the NOPR proposal to require the type of rate by which the price was set for each transaction to be reported in EQR, with slight modifications to the terms used to describe the types of rates. Specifically, the names proposed in the NOPR, “fixed price,” “formula,” “index,” and “RTO/ISO price” will be changed to “fixed,” “formula,” “electric index,” and “RTO/ISO,” as discussed below. For many of the same reasons discussed above in relation to trade date, the Commission disagrees with EEI's assertion that the information provided in the EQR contract data is sufficient for the Commission to discern which transactions belong to which of the following four types of rates proposed: “fixed,” “formula,” “electric index,” and “RTO/ISO.” The contract section of the EQR is incomplete in terms of identifying the manner in which the rate on a given transaction is calculated. Further, where a rate is detailed, the rate descriptions are entered as free-form text providing no opportunity to compare across similar transactions. For the many transactions without detailed rate descriptions, on the other hand, rate ty [Text truncated at 120,000 characters. The full text is on the page linked above.] --- Source: Frix Law Library, https://www.frixlaw.com/law-library/documents/fr%3A2012-23746. Public record. Not legal advice.