# Proposed Order and Request for Comment on a Petition From Certain Independent System Operators and Regional Transmission Organizations To Exempt Specified Transactions Authorized by a Tariff or Protocol Approved by the Federal Energy Commission or the Public Utility Commission of Texas From Certain Provisions of the Commodity Exchange Act > Briefs, arguments, decisions, and more. URL: https://www.frixlaw.com/law-library/documents/fr%3A2012-20965 ## Record - **Collection:** Federal Register - **Document type:** Notice - **Published:** August 28, 2012 - **Citation:** 77 FR 52138 ## Text COMMODITY FUTURES TRADING COMMISSION Proposed Order and Request for Comment on a Petition From Certain Independent System Operators and Regional Transmission Organizations To Exempt Specified Transactions Authorized by a Tariff or Protocol Approved by the Federal Energy Commission or the Public Utility Commission of Texas From Certain Provisions of the Commodity Exchange Act AGENCY: Commodity Futures Trading Commission. ACTION: Notice of Proposed Order and Request for Comment. SUMMARY: The Commodity Futures Trading Commission (“CFTC” or “Commission”) is requesting comment on a proposed exemption (the “Proposed Exemption”) issued in response to a consolidated petition (“Petition”) 1 from certain regional transmission organizations (“RTOs”) and independent system operators (“ISOs”) (collectively, “Petitioners”) to exempt specified transactions from the provisions of the Commodity Exchange Act (“CEA” or “Act”) 2 and Commission regulations. The Proposed Exemption would exempt the contracts, agreements and transactions for the purchase or sale of the limited electricity-related products that are specifically described within the proposed order from the provisions of the CEA and Commission regulations, with the exception of sections 2(a)(1)(B), 4b, 4c(b), 4 o, 4s(h)(1)(A), 4s(h)(4)(A), 6(c), 6(d), 6(e), 6c, 6d, 8, 9 and 13 of the Act and any implementing regulations promulgated thereunder including, but not limited to Commission regulations 23.410(a) and (b), 32.4 and part 180. To be eligible for the Proposed Exemption, the contract, agreement or transaction would be required to be offered or entered into in a market administered by a Petitioner pursuant to that Petitioner's tariff or protocol for the purposes of allocating such Petitioner's physical resources; the relevant tariff or protocol would be required to have been approved or permitted to have taken effect by either the Federal Energy Commission (“FERC”) or the Public Utility Commission of Texas (“PUCT”), as applicable; and the contract, agreement or transaction would be required to be entered into by persons who are “appropriate persons,” as defined in section 4(c)(3)(A) through (J) of the Act 3 or “eligible contract participants,” as defined in section 1a(18) of the Act and Commission regulations. 4 The exemption as proposed also would extend to any person or class of persons offering, entering into, rendering advice or rendering other services with respect to such transactions. Finally, the exemption would be subject to other conditions set forth therein. Authority for issuing the exemption is found in section 4(c)(6) of the Act. 5 1 In the Matter of the Petition for an Exemptive Order Under Section 4(c) of the Commodity Exchange Act by California Independent Service Operator Corporation; In the Matter of the Petition for an Exemptive Order Under Section 4(c) of the Commodity Exchange Act by the Electric Reliability Council of Texas, Inc.; In the matter of the Petition for an Exemptive Order Under Section 4(c) of the Commodity Exchange Act by ISO New England Inc.; In the Matter of the Petition for an Exemptive Order Under Section 4(c) of the Commodity Exchange Act by Midwest Independent Transmission System Operator, Inc.; In the Matter of the Petition for an Exemptive Order Under Section 4(c) of the Commodity Exchange Act by New York Independent System Operator, Inc.; and In the Matter of the Petition for an Exemptive Order Under Section 4(c) of the Commodity Exchange Act by PJM Interconnection, L.L.C. (Feb. 7, 2012, as amended June 11, 2012). 2 7 U.S.C. 1 et seq. 3 7 U.S.C. 6(c)(3)(A)-(J). 4 7 U.S.C. 1a(18). “Further Definition of `Swap Dealer,' `Security-Based Swap Dealer,' `Major Swap Participant,' `Major Security-Based Swap Participant' and `Eligible Contract Participant,' ” 77 FR 30596, May 23, 2012. 5 7 U.S.C. 6(c)(6). The Commission seeks comment on the Petition, the Proposed Exemption and related questions. A copy of the Petition requesting the exemption is available on the Commission's Web site at http://www.cftc.gov/stellent/groups/public/@requestsandactions/documents/ifdocs/isorto4capplication.pdf, with Petition Attachments posted at http://www.cftc.gov/stellent/groups/public/@requestsandactions/documents/ifdocs/isorto4cappattach.pdf and an Order 741 Implementation Chart posted at http://www.cftc.gov/stellent/groups/public/@requestsandactions/documents/ifdocs/isorto4cappfercchart.pdf. DATES: Comments must be received on or before September 27, 2012. ADDRESSES: You may submit comments by any of the following methods: • The agency's Web site, at http://comments.cftc.gov. Follow the instructions for submitting comments through the Web site. • Mail: David A. Stawick, Secretary of the Commission, Commodity Futures Trading Commission, Three Lafayette Centre, 1155 21st Street NW., Washington, DC 20581. • Hand Delivery/Courier: Same as mail above. • Federal eRulemaking Portal: http://www.regulations.gov. Follow the instructions for submitting comments. Please submit your comments using only one method. All comments must be submitted in English, or if not, accompanied by an English translation. Comments may be posted as received to http://www.cftc.gov. You should submit only information that you wish to make available publicly. If you wish the Commission to consider information that may be exempt from disclosure under the Freedom of Information Act, a petition for confidential treatment of the exempt information may be submitted according to the established procedures in CFTC Regulation 145.9 (17 CFR 145.9). The Commission reserves the right, but shall have no obligation, to review, pre-screen, filter, redact, refuse or remove any or all of your submission from www.cftc.gov that it may deem to be inappropriate for publication, such as obscene language. All submissions that have been redacted or removed that contain comments on the merits of the rulemaking will be retained in the public comment file and will be considered as required under the Administrative Procedure Act and other applicable laws, and may be accessible under the Freedom of Information Act. FOR FURTHER INFORMATION CONTACT: Robert B. Wasserman, Chief Counsel, 202-418-5092, rwasserman@cftc.gov, or Laura Astrada, Associate Chief Counsel, 202-418-7622, lastrada@cftc.gov, or Jocelyn Partridge, Special Counsel, 202-418-5926, jpartridge@cftc.gov, Division of Clearing and Intermediary Oversight; Eve Gutman, Attorney-Advisor, 202-418-5141, egutman@cftc.gov, Division of Market Oversight; Gloria P. Clement, Assistant General Counsel, 202-418-5122, gclement@cftc.gov or Thuy Dinh, Counsel, 202-418-5128, tdinh@cftc.gov, Office of the General Counsel; or Robert Pease, 202-418-5863, rpease@cftc.gov, Division of Enforcement; Commodity Futures Trading Commission, Three Lafayette Centre, 1151 21st Street NW., Washington, DC 20581. SUPPLEMENTARY INFORMATION: Table of Contents I. The Petition II. Statutory Background III. Background—FERC and PUCT A. Introduction B. FERC C. PUCT D. FERC & PUCT Oversight IV. Scope of the Exemption A. Transactions Subject to the Exemption B. Conditions C. Additional Limitations V. Section 4(c) Analysis A. Overview of CEA Section 4(c) B. Proposed CEA Section 4(c) Determinations C. FERC Credit Reform Policy D. DCO Core Principle Analysis E. SEF Core Principle Analysis VIII. Proposed Exemption A. Discussion of Proposed Exemption B. Proposed Exemption IX. Related Matters A. Regulatory Flexibility Act B. Paperwork Reduction Act C. Cost-Benefit Considerations X. Request for Comment I. The Petition On February 7, 2012, Petitioners collectively filed a Petition with the Commission requesting that the Commission exercise its authority under section 4(c)(6) of the CEA 6 and section 712(f) of the Dodd-Frank Wall Street Reform and Consumer Protection Act (“Dodd-Frank Act”) 7 to exempt contracts, agreements and transactions for the purchase or sale of specified electricity products, that are offered pursuant to a FERC- or PUCT-approved tariff, from most provisions of the Act. 8 Petitioners include three RTOs (Midwest Independent Transmission System Operator Inc. (“MISO”); ISO New England, Inc. (“ISO NE”); and PJM Interconnection, L.L.C. (“PJM”)), and two ISOs (California Independent System Operator (“CAISO”) and New York Independent System Operator (“NYISO”)), whose central role as transmission utilities is subject to regulation by FERC; and the Electric Reliability Council of Texas, Inc. (“ERCOT”), an entity that performs the role of an ISO but whose central role as a transmission utility in the electric energy market is subject to regulation by PUCT, the authority with jurisdiction to regulate rates and charges for the sale of electric energy within the state of Texas. 9 Petitioners represent that the roles, responsibilities and services of ISOs and RTOs are substantially similar. 10 As described in greater detail below, FERC encouraged the formation of ISOs to consolidate and manage the operation of electricity transmission facilities in order to provide open, non-discriminatory transmission service for generators and transmission customers. 11 FERC also encouraged the formation of RTOs to administer the transmission grid on a regional basis. 12 6 7 U.S.C. 6(c)(6). 7 See Dodd-Frank Act, Public Law 111-203, 124 Stat. 1376 (2010). The text of the Dodd-Frank Act may be accessed at http://www.cftc.gov./LawRegulation/OTCDERIVATIVES/index.htm. 8 See Petition at 2-3, 6. 9 See Petition at 2-4. See 16 Tex. Admin. Code 25.1 (1998). 10 See Petition at 2 n. 2. 11 See FERC Order 888 Promoting Wholesale Competition Through Open Access Non-Discriminatory Transmission Facilities (“FERC Order 888”), 61 FR 21540, April 24, 1996; See Petition at 2 n.2, 3. 12 See Petition at 3. Petitioners specifically request that the Commission exempt from most provisions of the CEA certain “financial transmission rights,” “energy transactions,” “forward capacity transactions,” and “reserve or regulation transactions,” as those terms are defined in the Petition, if such transactions are offered or entered into pursuant to a tariff under which a Petitioner operates that has been approved by FERC or PUCT, as applicable, as well as any persons (including Petitioners, their members and their market participants) offering, entering into, rendering advice, or rendering other services with respect to such transactions. 13 Petitioners assert that each of the transactions for which an exemption is requested is (a) subject to a long-standing, comprehensive regulatory framework for the offer and sale of such transactions established by FERC, or in the case of ERCOT, the PUCT, and (b) part of, and inextricably linked to, the organized wholesale electricity markets that are subject to regulation and oversight of FERC or PUCT, as applicable. 14 Petitioners expressly exclude from the Petition a request for relief from sections 4b, 4 o, 6(c) and 9(a)(2) of the Act 15 and such provisions explicitly have been carved out of the exemption that would be provided by the Proposed Exemption. Petitioners assert that they are seeking the requested exemption in order to provide greater legal certainty with respect to the regulatory requirements that apply to the transactions that are the subject of the Petition. 16 Petitioners request that, due to the commonalities in the Petitioners' markets, the exemption apply to all Petitioners and their respective market participants with respect to each category of electricity-related products described in the Petition, regardless of whether such products are offered or entered into at the current time pursuant to an individual Petitioner's tariff. 17 Petitioners' assert that this uniformity would avoid an individual Petitioner being required to seek future amendments to the exemption in order to offer or enter into the same type of transactions currently offered by another Petitioner. 18 13 See id. at 2-3. 14 See id. at 11. 15 See id. at 3. 16 See id. at 3, 5-6. 17 See id. at 6. 18 See id. II. Statutory background On July 21, 2010, President Obama signed the Dodd-Frank Act. Title VII of the Dodd-Frank Act amended the CEA 19 and altered the scope of the Commission's exclusive jurisdiction. 20 In particular, it expanded the Commission's exclusive jurisdiction, which had included futures traded, executed and cleared on CFTC-regulated exchanges and clearinghouses, to also cover swaps traded, executed, or cleared on CFTC-regulated exchanges or clearinghouses. 21 As a result, the Commission's exclusive jurisdiction now includes swaps as well as futures, and is clearly expressed in CEA section 2(a)(1)(A), which reads: 19 7 U.S.C. 1 et seq. 20 Section 722(e) of the Dodd-Frank Act. 21 See 7 U.S.C. 2(a)(1)(A). The Dodd-Frank Act also added section 2(h)(1)(A), which requires swaps to be cleared if required to be cleared and not subject to a clearing exception or exemption. See 7 U.S.C. 2(h)(1)(A). The Commission shall have exclusive jurisdiction, except to the extent otherwise provided in the Wall Street Transparency and Accountability Act of 2010 (including an amendment made by that Act) and subparagraphs (C), (D), and (I) of this paragraph and subsections (c) and (f), with respect to accounts, agreements (including any transaction which is of the character of * * * an “option”), and transactions involving swaps or contracts of sale of a commodity for future delivery (including significant price discovery contracts) traded or executed on a contract market * * * or a swap execution facility * * * or any other board of trade, exchange, or market * * *. 22 22 7 U.S.C. 2(a)(1)(A). The Dodd-Frank Act also added a savings clause that addresses the roles of the Commission, FERC, and state agencies as they relate to certain agreements, contracts, or transactions traded pursuant to the tariff of an RTO and ISO. 23 Toward that end, paragraph (I) of CEA section 2(a)(1) repeats the Commission's exclusive jurisdiction and clarifies that the Commission retains its authorities over agreements, contracts or transactions traded pursuant to FERC- or state-approved tariff or rate schedules. 24 The same paragraph (I) also explains that the FERC and state agencies preserve their existing authorities over agreements, contracts, or transactions “entered into pursuant to a tariff or rate schedule approved by [FERC] or a State regulatory agency,” that are: “(I) not “executed, traded, or cleared on” an entity or trading facility subject to registration or “(II) executed, traded, or cleared on a registered entity or trading facility owned or operated by a [RTO] or [ISO].” 25 23 See 7 U.S.C. 2(a)(1)(I). 24 See 7 U.S.C. 2(a)(1)(I)(i) and (ii). 25 7 U.S.C. 2(a)(1)(I)(i)(II). The savings clause in CEA section 2(a)(1)(I) provides that: (I)(i) Nothing in this Act shall limit or affect any statutory authority of the Federal Energy Regulatory Commission or a State regulatory authority (as defined in section 3(21) of the Federal Power Act (16 U.S.C. 796(21)) with respect to an agreement, contract, or transaction that is entered into pursuant to a tariff or rate schedule approved by the Federal Energy Regulatory Commission or a State regulatory authority and is— (I) Not executed, traded, or cleared on a registered entity or trading facility; or (II) Executed, traded, or cleared on a registered entity or trading facility owned or operated by a regional transmission organization or independent system operator. (ii) In addition to the authority of the Federal Energy Regulatory Commission or a State regulatory authority described in clause (i), nothing in this subparagraph shall limit or affect— (I) Any statutory authority of the Commission with respect to an agreement, contract, or transaction described in clause (i); or (II) The jurisdiction of the Commission under subparagraph (A) with respect to an agreement, contract, or transaction that is executed, traded, or cleared on a registered entity or trading facility that is not owned or operated by a regional transmission organization or independent system operator (as defined by sections 3(27) and (28) of the Federal Power Act (16 U.S.C. 796(27), 796(28)). In addition, Dodd-Frank Act section 722(g) (not codified in the United States Code) expressly states that FERC's pre-existing statutory enforcement authority is not limited or affected by amendments to the CEA. Section 722(g) states: (g) AUTHORITY OF FERC.—Nothing in the Wall Street Transparency and Accountability Act of 2010 or the amendments to the Commodity Exchange Act made by such Act shall limit or affect any statutory enforcement authority of the Federal Energy Regulatory Commission pursuant to section 222 of the Federal Power Act and section 4A of the Natural Gas Act that existed prior to the date of enactment of the Wall Street Transparency and Accountability Act of 2010. While the Dodd-Frank Act sets forth a clear statement of the Commission's exclusive jurisdiction and authorities as related to FERC and state regulatory authorities, the Dodd-Frank Act also granted the Commission specific powers to exempt certain contracts, agreements or transactions from duties otherwise required by statute or Commission regulation by adding a new section to the CEA, section 4(c)(6), that permits the Commission to exempt from its regulatory oversight, among other things, agreements, contracts, or transactions traded pursuant to an RTO or ISO tariff that has been approved or permitted to take effect by FERC or a State regulatory authority, as applicable. 26 The Commission's charge, however, is not rote; the Commission must initially determine whether the exemption would be consistent with the public interest and the purposes of the CEA. 27 26 See 7 U.S.C. 6(c)(6). 27 See 7 U.S.C. 6(c)(6)(A) and (B). The Commission must act “in accordance with” section 4(c)(1) and (2) of the CEA, when issuing an electricity exemption under section 4(c)(6). 28 Section 4(c)(1) authorizes the Commission, by rule, regulation, or order, to exempt any agreement, contract or transaction, or class thereof, from the exchange-trading requirements of section 4(a) or any other requirements of the Act other than section 2(a)(1)(C)(ii) and (D). The Commission may attach terms and conditions to any exemption it provides. 28 Section 4(c) was added to the CEA by the Futures Trading Practices Act of 1992, Public Law 102-564. The Commission's authority under section 4(c) was explained by the Conferees: In granting exemptive authority to the Commission under new section 4(c), the Conferees recognize the need to create legal certainty for a number of existing categories of instruments which trade today outside of the forum of a designated contract market. The provision included in the Conference substitute is designed to give the Commission broad flexibility in addressing these products * * * * * In this respect, the Conferees expect and strongly encourage the Commission to use its new exemptive power promptly upon enactment of this legislation in four areas where significant concerns of legal uncertainty have arisen: (1) Hybrids, (2) swaps, (3) forwards, and (4) bank deposits and accounts. The Commission is not required to ascertain whether a particular transaction would fall within its jurisdiction prior to exercising its exemptive authority under section 4(c). The Conferees stated that they did: not intend that the exercise of exemptive authority by the Commission would require any determination before hand that the agreement, instrument, or transaction for which an exemption is sought is subject to the Act. Rather, this provision provides flexibility for the Commission to provide legal certainty to novel instruments where the determination as to jurisdiction is not straightforward * * * H.R. Rep. No. 978, 102d Cong. 2d Sess., (1992) at 82-83. Section 4(c)(2) of the CEA 29 provides that the Commission may not approve an exemption from the execution requirements of the Act, as noted in section 4(a), 30 unless the agreement, contract or transaction will be entered into solely between “appropriate persons,” as that term is defined in section 4(c)(3), which does not include retail customers (such as small businesses or individuals). In addition, the Commission must determine that the agreement, contract or transaction in question will not have a material adverse effect on the ability of the Commission or any contract market to discharge its regulatory or self-regulatory duties. 31 29 Section 4(c)(2), 7 U.S.C. 6(c)(2), states: The Commission shall not grant any exemption * * * from any of the requirements of subsection (a) unless the Commission determines that (A) the requirement should not be applied to the agreement, contract, or transaction for which the exemption is sought and that the exemption would be consistent with the public interest and the purposes of this Act; and (B) the agreement, contract, or transaction— (i) Will be entered into solely between appropriate persons; and (ii) Will not have a material adverse effect on the ability of the Commission or any contract market to discharge its regulatory or self-regulatory duties under this Act. 30 7 U.S.C. 6(a). 31 See 7 U.S.C. 6(c)(2). III. Background—FERC and PUCT A. Introduction Each Petitioner is subject to regulation by FERC, with the exception of ERCOT, which is regulated by PUCT. 32 Petitioners assert that the regulatory frameworks administered by FERC or PUCT, as applicable to each particular RTO or ISO market, would apply to the transactions for which an exemption has been requested. 33 32 See Petition at 4. 33 See id. at 11. B. FERC In 1920, Congress established the Federal Power Commission (“FPC”). 34 The FPC was reorganized into FERC in 1977. 35 FERC is an independent agency that regulates the interstate transmission of electricity, natural gas and oil. 36 FERC's mission is to “assist consumers in obtaining reliable, efficient and sustainable energy services at a reasonable cost through appropriate regulatory and market means.” 37 This mission is accomplished by pursuing two primary goals. First, FERC seeks to ensure that rates, terms and conditions for wholesale transactions and transmission of electricity and natural gas are just, reasonable and not unduly discriminatory or preferential. 38 Second, FERC seeks to promote the development of safe, reliable and efficient energy infrastructure that serves the public interest. 39 Both Congress and FERC, through a series of legislative acts and Commission orders, have sought to establish a system whereby wholesale electricity generation and transmission in the United States is governed by two guiding principles; regulation with respect to wholesale electricity transmission, 40 and competition when dealing with wholesale generation. 41 34 Federal Power Act, 16 U.S.C. 791a et seq. 35 The Department of Energy Organization Act, Public Law 95-91, section 401, 91 Stat. 565, 582 (1977) (codified as amended at 42 U.S.C. 7171 (1988)). 36 See 42 U.S.C. 7172. 37 See FERC Strategic Plan for Fiscal Years 2009-2014, 3 (Feb. 2012), http://www.ferc.gov/about/strat-docs/FY-09-14-strat-plan-print.pdf . 38 Id. 39 Id. 40 The term “`wholesale transmission services' means the transmission of electric energy sold, or to be sold, at wholesale in interstate commerce.” See 16 U.S.C. 796 (24)). 41 See generally FERC Order 888. See also FERC's discussion of electric competition, available at http://www.ferc.gov/industries/electric/indus-act/competition.asp (stating that “[FERC]'s core responsibility is to `guard the consumer from exploitation by non-competitive electric power companies.' ”). In 1996, FERC issued FERC Order 888, which promoted competition in the generation market by ensuring fair access and market treatment by transmission customers. 42 Specifically, FERC Order 888 sought to “remedy both existing and future undue discrimination in the industry and realize the significant customer benefits that will come with open access.” 43 FERC Order 888 encouraged the formation of ISOs as a potentially effective means for accomplishing non-discriminatory open access to the transmission of electrical power. 44 42 See FERC Order 888. 43 FERC Order 888 at 21541. 44 FERC Order 888 at 21594. Under the old system, one party could own both generation and transmission resources, giving preferential treatment to its own and affiliated entities. See generally FERC Order 888 . In addition, FERC has issued orders that address areas such as increased RTO and ISO participation by transmission utilities, increased use of long-term firm transmission rights, increased investment in transmission infrastructure, reduced transmission congestion and the use of demand-response. 45 The end result of this series of FERC orders is that a regulatory system has been established that requires ISOs and RTOs to comply with numerous FERC rules designed to improve both the reliability of the physical operations of electric transmission systems as well as the competitiveness of electricity markets. The requirements imposed by the various FERC Orders seek to ensure that FERC is able to accomplish its two main goals; ensuring that rates, terms and conditions are just, reasonable and not unduly discriminatory or preferential, while promoting the development of safe, reliable and efficient energy infrastructure that serves the public interest. 45 See, e.g., FERC Order 2000, 65 FR 809 (2000)(encouraging transmission utilities to join RTOs); FERC Order No. 681, 71 FR 43294 (2006), FERC Stats. & Regs. ¶ 31,222 (2006), order on reh'g, Order No. 679-A, 72 FR 1152, Jan. 10, 2007, FERC Stats. & Regs. ¶ 31,236, order on reh'g, 119 FERC ¶ 61,062 (2007) (finalizing guidelines for ISOs to follow in developing proposals to provide long-term firm transmission rights in organized electricity markets); FERC Order No. 679, 71 FR 43294 (2006) (finalizing rules to increase investment in the nation's aging transmission infrastructure, and to promote electric power reliability and lower costs for consumers, by reducing transmission congestion); FERC Order No. 890, 72 FR 12266 (2007)(modifying existing rules to promote the nondiscriminatory and just operation of transmission systems); and FERC Order No. 719-A, 74 FR 37776 (2009) (implementing the use of demand-response (the process of requiring electricity consumers to reduce their electricity use during times of heightened demand), encouraging the use of long-term power contracts and strengthening the role of market monitors). C. PUCT In 1975, the Texas Legislature enacted the Public Utility Regulatory Act (“PURA”) and created PUCT to provide statewide regulation of the rates and services of electric and telecommunications utilities. 46 PUCT's stated mission is to assure the availability of safe, reliable, high quality services that meet the needs of all Texans at just and reasonable rates. 47 To this end, PUCT regulates electric and telecommunications utilities while facilitating competition, operation of the free market, and customer choice. 48 Subchapter S of TAC § 25 (“Wholesale Markets”) sets out the rules applicable to ERCOT, which operates a wholesale electricity market in Texas similar to the electricity markets run by the other Petitioners. As with the RTOs and ISOs regulated by FERC, ERCOT is required to have rules that address the regulatory requirements imposed by PUCT. 49 These rules address issues similar to those rules imposed by FERC on RTOs and ISOs, 50 including matters such as market design, pricing safeguards, market monitoring, monitoring for wholesale market power, resource adequacy and ERCOT emergency response services, 51 and are aimed at developing electricity markets that are able to provide reliable, safe and efficient electric service to the people of Texas, while also maintaining rates at an affordable level through the operation of fair competition. 52 46 Public Utility Regulatory Act, TEX. UTIL. CODE ANN. 11.001 et seq. (Vernon 1998 & Supp. 2005). 47 16 Texas Admin. Code (“TAC”) 25.1 (1998). 48 Id. 49 See generally 16 TAC 25.501-25.507. 50 See generally id. 51 See generally id. 52 See generally 16 TAC 25.503. D. FERC & PUCT Oversight As discussed above, both FERC and PUCT assert that their primary goal in regulating their respective electricity markets is to ensure that consumers are able to purchase electricity on a safe, reliable and affordable basis. 53 53 See generally 16 TAC 25.1. See also FERC Strategic Plan for Fiscal Years 2009-2014, 3 (Feb. 2012), http://www.ferc.gov/about/strat-docs/FY-09-14-strat-plan-print.pdf . IV. Scope of the Exemption A. Transactions Subject to the Exemption After due consideration, the Commission proposes to exempt certain Financial Transmission Rights (“FTRs”), Energy Transactions, Forward Capacity Transactions, and Reserve or Regulation Transactions (collectively, the “Transactions”), each as defined below, pursuant to section 4(c)(6) of the Act. An FTR is a transaction, however named, that entitles one party to receive, and obligates another party to pay, an amount based solely on the difference between the price for electricity, established on an electricity market administered by a Petitioner, at a specified source ( i.e., where electricity is deemed injected into the grid of a Petitioner) and a specified sink ( i.e., where electricity is deemed withdrawn from the grid of a Petitioner). 54 The term “FTR” includes Financial Transmission Rights, and Financial Transmission Rights in the form of options ( i.e., where one party has only the obligation to pay, and the other party only the right to receive, an amount as described above). As more fully described below, the Proposed Exemption applies only to FTRs where each FTR is linked to, and the aggregate volume of FTRs for any period of time is limited by, the physical capability (after accounting for counterflow) of the electricity transmission system operated by the Petitioner offering the contract for such period: a Petitioner serves as the market administrator for the market on which the FTR is transacted; each party to the Transaction is a member of the particular Petitioner (or is the Petitioner itself) and the Transaction is executed on a market administered by that Petitioner; and the Transaction does not require any party to make or take physical delivery of electricity. 55 54 Petition at 6. 55 Each FTR specifies a direction along a path from a specified source to a specified sink. Counterflow FTRs specify a path where congestion in the physical market is in the opposite direction from the prevailing flow. Holders of counterflow FTRs generally pay congestion revenues to the RTO or ISO. Because counterflow FTRs are expected to result in payment liability to the FTR holder, the price of counterflow FTRS are typically negative. That is, the RTO or ISO pays market participants to acquire them. However, counterflow FTRs may be profitable (and prevailing flow FTRs may result in a payment liability) where congestion in the physical market occurs in direction opposite to that expected. See generally PJM Interconnection, L.L.C., 122 FERC ¶ 61,279 (2008); see also PJM Interconnection, L.L.C, 121 FERC ¶ 61,089 (2007). “Energy Transactions” are transactions in a “Day-Ahead Market” or “Real-Time Market,” as those terms are defined in the Proposed Exemption, for the purchase or sale of a specified quantity of electricity at a specified location where the price of electricity is established at the time the transaction is executed. 56 Performance occurs in the Real-Time Market by either the physical delivery or receipt of the specified electricity or a cash payment or receipt at the price established in the Real-Time Market; and the aggregate cleared volume of both physical and cash-settled energy transactions for any period of time is limited by the physical capability of the electricity transmission system operated by a Petitioner for that period of time. 57 Energy Transactions are also referred to as Virtual Bids or Convergence Bids. 58 56 See Petition at 7. See also section VIII. below. 57 See id. at 7. See also section VIII. below. 58 See id. at 6. “Forward Capacity Transactions” fall into three distinct categories, Generation Capacity (“GC”), Demand Response (“DR”), and Energy Efficiency. 59 GC refers to the right of a Petitioner to require certain sellers to maintain the interconnection of electric generation facilities to specific physical locations in the electric power transmission system during a future time period as specified in the Petitioner's Tariff. 60 Furthermore, a GC contract requires a seller to offer specified amounts of electric energy into the Day-Ahead or Real-Time Markets for electricity transactions. A GC contract also requires a seller, subject to the terms and conditions of a Petitioner's Tariff, to inject electric energy into the electric power transmission system operated by the Petitioner. 61 A DR Right gives Petitioners the right to require that certain sellers of such rights curtail their consumption of electricity from Petitioner's electricity transmission system during a future period of time as specified in the Petitioners' Tariffs. 62 Energy Efficiency Rights (“EER”) provides Petitioners with the right to require specific performance of an action or actions on the part of the other party that will reduce the need for GC or DR capacity over the duration of a future period of time as specified in the Petitioner's Tariffs. 63 Moreover, for a Forward Capacity Transaction to be eligible for exemption hereunder, the aggregate cleared volume of all such transactions for any period of time must be limited to the physical capability of the electric transmission system operated by the applicable Petitioner for that period of time. 59 See id. at 7-8. 60 See id. at 7. 61 See id. 62 See id. at 7. 63 See id. at 8. Another example of an EER would be requiring an RTO or ISO member to change equipment in order to improve the efficiency of the system, and in turn, reduce the amount of electricity drawn from the system. See also section VIII. below. “Reserve Regulation Transactions” allow a Petitioner to purchase through auction, for the benefit of load serving entities (“LSEs”) and resources, the right, during a period of time specified in the Petitioner's Tariff, to require the seller to operate electric facilities in a physical state such that the facilities can increase or decrease the rate of injection or withdrawal of electricity to the electric power transmission system operated by the Petitioner with physical performance by the seller's facilities within a response interval specified in the Petitioner's tariff (Reserve Transaction), or prompt physical performance by the seller's facilities (Area Control Error Regulation Transaction). 64 In consideration for such delivery, or withholding of delivery, the seller receives compensation of the type specified in section VIII below. 65 In all cases, the quantity and specifications for such Transactions for a Petitioner for any period of time are limited by the physical capability of the electric transmission system operated by Petitioners. 66 These Transactions are typically used to address unforeseen fluctuations in the level of electricity demand experienced on the electric transmission system. 64 See id. at 8-9. See also section VIII. below. 65 See id. at 8. 66 See id. at 8-9. B. Conditions The Proposed Exemption would be subject to certain conditions. First, all parties to the agreements, contracts or transactions that are covered by the Proposed Exemption must be either “appropriate persons,” as such term is defined in sections 4(c)(3)(A) through (J) of the Act, or “eligible contract participants,” as such term is defined in section 1a(18)(A) of the Act and in Commission regulation 1.3(m). 67 67 That is, the Commission is proposing to use its authority pursuant to CEA 4(c)(3)(K) to include eligible contract participants as appropriate persons for the purposes of this Order. See infra n. 80 and accompanying text. Second, the agreements, contracts or transactions that are covered by the Proposed Exemption must be offered or sold pursuant to a Petitioner's tariff, which has been approved or permitted to take effect by: (1) In the case of ERCOT, the PUCT or (2) In the case of all other Petitioners, FERC. Third, none of a Petitioner's tariffs or other governing documents may include any requirement that the Petitioner notify a member prior to providing information to the Commission in response to a subpoena or other request for information or documentation. Finally, information sharing arrangements that are satisfactory to the Commission between the Commission and FERC and between the Commission and PUCT must be in full force and effect. 68 68 As discussed in section VIII.A. below, the Commission and FERC have already entered into a Memorandum of Understanding, a copy of which is available at http://www.ferc.gov/legal/maj-ord-reg/mou/mou-33.pdf . In addition, the Commission intends on working with the PUCT on an MOU that is mutually satisfactory. C. Additional Limitations As discussed above, the Commission proposes to exempt the Transactions pursuant to section 4(c)(6) of the Act based, in part, on certain representations made by Petitioners as well as the additional limitations that are noted below. As represented in the Petition, the exemption requested by Petitioners relate to Transactions that are primarily entered into by commercial participants that are in the business of generating, transmitting and distributing electricity. 69 In addition, the Commission notes that it appears that Petitioners were established for the purpose of providing affordable, reliable electricity to consumers within their geographic region. 70 Critically, these Transactions are an essential means, designed by FERC and PUCT as an integral part of their statutory responsibilities, to enable the reliable delivery of affordable electricity. 71 The Commission also notes that each of the Transactions taking place on Petitioners' markets is monitored by Market Monitoring Units (“MMU”) responsible to either FERC or, in the case of ERCOT, PUCT. 72 Finally, as discussed above, each Transaction is directly tied to the physical capabilities of Petitioners' electricity grids. 73 As more fully described below, 74 and on the basis of the aforementioned representations, the Commission finds that the Proposed Exemption would be in the public interest for the specified Transactions. To be clear, however, financial transactions that are not tied to the allocation of the physical capabilities of an electric transmission grid would not be suitable for exemption because such activity would not be inextricably linked to the physical delivery of electricity. 69 See generally Petition at 20. 70 See id. at 3-4. 71 See generally FERC Order 888; FERC Order 2000; 18 CFR 35.34(k)(2); and TAC 25.1. See also Petition at 11, 13-14. 72 Petition at 15-18. 73 See id. at 6-9. 74 See the discussions in sections V.B., V.D., and V.E. below. V. Section 4(c)Analysis A. Overview of CEA Section 4(c) 1. Sections 4(c)(6)(A) and (B) The Dodd-Frank Act amended CEA section 4(c) to add sections 4(c)(6)(A) and (B), which provide for exemptions for certain transactions entered into (a) pursuant to a tariff or rate schedule approved or permitted to take effect by FERC, or (b) pursuant to a tariff or rate schedule establishing rates or charges for, or protocols governing, the sale of electric energy approved or permitted to take effect by the regulatory authority of the State or municipality having jurisdiction to regulate rates and charges for the sale of electric energy within the State or municipality, as eligible for exemption pursuant to the Commission's 4(c) exemptive authority. 75 Indeed, 4(c)(6) provides that “[i]f the Commission determines that the exemption would be consistent with the public interest and the purposes of this chapter, the Commission shall” issue such an exemption. However, any exemption considered under 4(c)(6)(A) and/or (B) must be done “in accordance with [CEA section 4(c)(1) and (2)].” 76 75 The exemption language in section 4(c)(6) reads: (6) If the Commission determines that the exemption would be consistent with the public interest and the purposes of this Act, the Commission shall, in accordance with paragraphs (1) and (2), exempt from the requirements of this Act an agreement, contract, or transaction that is entered into— (A) Pursuant to a tariff or rate schedule approved or permitted to take effect by the Federal Energy Regulatory Commission; (B) Pursuant to a tariff or rate schedule establishing rates or charges for, or protocols governing, the sale of electric energy approved or permitted to take effect by the regulatory authority of the State or municipality having jurisdiction to regulate rates and charges for the sale of electric energy within the State or municipality; or (C) Between entities described in section 201(f) of the Federal Power Act (16 U.S.C. 824(f)). 76 CEA section 4(c)(6) explicitly directs the Commission to consider any exemption proposed under 4(c)(6) “in accordance with [CEA section 4(c)(1) and (2)].” 2. Section 4(c)(1) CEA section 4(c)(1) requires that the Commission act “by rule, regulation or order, after notice and opportunity for hearing.” It also provides that the Commission may act “either unconditionally or on stated terms or conditions or for stated periods and either retroactively or prospectively or both” and that the Commission may provide exemption from any provisions of the CEA except subparagraphs (C)(ii) and (D) of section 2(a)(1). 77 77 Section 4(c)(1), 7 U.S.C. 6(c)(1), states: (c)(1) In order to promote responsible economic or financial innovation and fair competition, the Commission by rule, regulation, or order, after notice and opportunity for hearing, may (on its own initiative or on application of any person, including any board of trade designated or registered as a contract market or derivatives transaction execution facility for transactions for future delivery in any commodity under section 5 of this Act) exempt any agreement, contract, or transaction (or class thereof) that is otherwise subject to subsection (a) (including any person or class of persons offering, entering into, rendering advice or rendering other services with respect to, the agreement, contract, or transaction), either unconditionally or on stated terms or conditions or for stated periods and either retroactively or prospectively, or both, from any of the requirements of subsection (a), or from any other provision of this Act (except subparagraphs (C)(ii) and (D) of section 2(a)(1), except that— (A) Unless the Commission is expressly authorized by any provision described in this subparagraph to grant exemptions, with respect to amendments made by subtitle A of the Wall Street Transparency and Accountability Act of 2010— (i) With respect to— (I) Paragraphs (2), (3), (4), (5), and (7), paragraph (18)(A)(vii)(III), paragraphs (23), (24), (31), (32), (38), (39), (41), (42), (46), (47), (48), and (49) of section 1a, and sections 2(a)(13), 2(c)(1)(D), 4a(a), 4a(b), 4d(c), 4d(d), 4r, 4s, 5b(a), 5b(b), 5(d), 5(g), 5(h), 5b(c), 5b(i), 8e, and 21; and (II) Section 206(e) of the Gramm-Leach-Bliley Act (Pub. L. 106-102; 15 U.S.C. 78c note); and (ii) in sections 721(c) and 742 of the Dodd-Frank Wall Street Reform and Consumer Protection Act; and (B) The Commission and the Securities and Exchange Commission may by rule, regulation, or order jointly exclude any agreement, contract, or transaction from section 2(a)(1)(D)) if the Commissions determine that the exemption would be consistent with the public interest. 3. Section 4(c)(2) CEA section 4(c)(2) requires the Commission to determine that: To the extent an exemption provides relief from any of the requirements of CEA section 4(a), the requirement should not be applied to the agreement, contract or transaction; the exempted agreement, contract, or transactions will be entered into solely between appropriate persons; 78 and the exemption will not have a material adverse effect on the ability of the Commission or any contract market to discharge its regulatory or self-regulatory duties under the CEA. 79 78 See CEA 4(c)(2)(B)(i) and the discussion of CEA section 4(c)(3) below. 79 CEA section 4(c)(2)(A) also requires that the exemption would be consistent with the public interest and the purposes of the CEA, but that requirement duplicates the requirement of section 4(c)(6). 4. Section 4(c)(3) CEA section 4(c)(3) outlines who may constitute an appropriate person for the purpose of a 4(c) exemption, including as relevant to this Notice: (a) Any person that fits in one of ten defined categories of appropriate persons; or (b) such other persons that the Commission determines to be appropriate in light of their financial or other qualifications, or the applicability of appropriate regulatory protections. 80 80 Section 4(c)(3), 7 U.S.C. 6(c)(3), provides that: the term “appropriate person” shall be limited to the following persons or classes thereof: (A) A bank or trust company (acting in an individual or fiduciary capacity). (B) A savings association. (C) An insurance company. (D) An investment company subject to regulation under the Investment Company Act of 1940 (15 U.S.C. 80a-1 et seq.). (E) A commodity pool formed or operated by a person subject to regulation under this Act. (F) A corporation, partnership, proprietorship, organization, trust, or other business entity with a net worth exceeding $1,000,000 or total assets exceeding $5,000,000, or the obligations of which under the agreement, contract or transaction are guaranteed or otherwise supported by a letter of credit or keepwell, support, or other agreement by any such entity or by an entity referred to in subparagraph (A), (B), (C), (H), (I), or (K) of this paragraph. (G) An employee benefit plan with assets exceeding $1,000,000, or whose investment decisions are made by a bank, trust company, insurance company, investment adviser registered under the Investment Advisers Act of 1940 (15 U.S.C. 80a-1 et seq.), or a commodity trading advisor subject to regulation under this Act. (H) Any governmental entity (including the United States, any state, 4-1 or any foreign government) or political subdivision thereof, or any multinational or supranational entity or any instrumentality, agency, or department of any of the foregoing. (I) A broker-dealer subject to regulation under the Securities Exchange Act of 1934 (15 U.S.C. 78a et seq.) acting on its own behalf or on behalf of another appropriate person. (J) A futures commission merchant, floor broker, or floor trader subject to regulation under this Act acting on its own behalf or on behalf of another appropriate person. (K) Such other persons that the Commission determines to be appropriate in light of their financial or other qualifications, or the applicability of appropriate regulatory protections. B. Proposed CEA Section 4(c) Determinations In connection with the Proposed Exemption, the Commission has considered and proposes to determine that: (i) The Proposed Exemption is consistent with the public interest and the purposes of the CEA; (ii) CEA section 4(a) should not apply to the transactions or entities eligible for the Proposed Exemption, (iii) the persons eligible to rely on the Proposed Exemption are appropriate persons pursuant to CEA section 4(c)(3); and (iv) the Proposed Exemption will not have a material adverse effect on the ability of the Commission or any contract market to discharge its regulatory or self-regulatory duties under the CEA. 1. Consistent with the Public Interest and the Purposes of the CEA As required by CEA section 4(c)(2)(A), as well as section 4(c)(6), the Commission proposes to determine that the Proposed Exemption is consistent with the public interest and the purposes of the CEA. Section 3(a) of the CEA provides that transactions subject to the CEA affect the national public interest by providing a means for managing and assuming price risk, discovering prices, or disseminating pricing information through trading in liquid, fair and financially secure trading facilities. Section 3(b) of the CEA identifies the purposes of the CEA: It is the purpose of this Act to serve the public interests described in subsection (a) through a system of effective self-regulation of trading facilities, clearing systems, market participants and market professionals under the oversight of the Commission. To foster these public interests, it is further the purpose of this Act to deter and prevent price manipulation or any other disruptions to market integrity; to ensure the financial integrity of all transactions subject to this Act and the avoidance of systemic risk; to protect all market participants from fraudulent or other abusive sales practices and misuses of customer assets; and to promote responsible innovation and fair competition among boards of trade, other markets and market participants. The Petitioners assert that the Proposed Exemption would be consistent with the public interest and purposes of the CEA, 81 stating generally that: (a) The Transactions have been, and are, subject to a long-standing, comprehensive regulatory framework for the offer and sale of the Transactions established by FERC or PUCT; and (b) the Transactions administered by the RTOs/ISOs or ERCOT are part of, and inextricably linked to, the organized wholesale electricity markets that are subject to FERC and PUCT regulation and oversight. 82 For example, Petitioners explain that FERC Order No. 2000 (which, along with FERC Order No. 888, encouraged the formation of RTOs/ISOs to operate the electronic transmission grid and to create organized wholesale electric markets) requires an RTO/ISO to demonstrate that it has four minimum characteristics: (1) Independence from any market participant; (2) a scope and regional configuration which enables the ISO/RTO to maintain reliability and effectively perform its required functions; (3) operational authority for its activities, including being the security coordinator for the facilities that it controls; and (4) short-term reliability. 83 Petitioners highlight that an RTO/ISO must demonstrate to FERC that it performs certain self-regulatory and/or market monitoring functions, 84 and the Petition describes the analogous requirements applicable to ERCOT under PUCT and the PURA. 85 81 See Petition at 11. 82 See id. 83 See id. at 13. 84 See id. at 13-14 (explaining that each RTO/ISO must employ a transmission pricing system that promotes efficient use and expansion of transmission and generation facilities; develop and implement procedures to address parallel path flow issues within its region and with other regions; serve as a provider of last resort of all ancillary services required by FERC Order No. 888 including ensuring that its transmission customers have access to a real-time balancing market; be the single OASIS (Open-Access Same-Time Information System) site administrator for all transmission facilities under its control and independently calculate Total Transmission Capacity and Available Transmission Capability; provide reliable, efficient and not unduly discriminatory transmission service, it must provide for objective monitoring of markets it operates or administers to identify market design flaws, market power abuses and opportunities for efficiency improvements; be responsible for planning, and for directing or arranging, necessary transmission expansions, additions, and upgrades; and ensure the integration of reliability practices within an interconnection and market interface practices among regions). 85 See id. at 14-15. Pursuant to PURA 39.151(a), ERCOT's roles and duties are to provide access to the transmission and distribution systems for all buyers and sellers of electricity on nondiscriminatory terms; ensure the reliability and adequacy of the regional electrical network; ensure that information relating to a customer's choice of retail electric provider is conveyed in a timely manner to the persons who need that information; and ensure that electricity production and delivery are accurately accounted for among the generators and wholesale buyers and sellers in the region. Of single importance, Petitioners are responsible for “ensur[ing] the development and operation of market mechanisms to manage transmission congestion. * * * The market mechanisms must accommodate broad participation by all market participants, and must provide all transmission customers with efficient price signals that show the consequences of their transmission usage decisions.” 86 86 See Petition at 14. See also 18 CFR 35.34(k)(2). Petitioners also explain that the Transactions are primarily entered into by commercial participants that are in the business of generating, transmitting, and distributing electricity, 87 and that Petitioners were established for the purpose of providing affordable, reliable electricity to consumers within their geographic region. 88 Furthermore, the Transactions that take place on Petitioners' markets are overseen by a market monitoring function, required by FERC for each Petitioner, and by PUCT in the case of ERCOT, to identify manipulation of electricity on Petitioners' markets. 89 87 See generally Petition at 20. 88 See id. at 3-4. 89 See id. at 15-18. Fundamental to the Commission's “public interest” and “purposes of the [Act]” analysis is the fact that the Transactions are inextricably tied to the Petitioners' physical delivery of electricity, as represented in the Petition. 90 An equally important factor is that the Proposed Exemption is explicitly limited to Transactions taking place on markets that are monitored by either an independent market monitor, a market administrator (the RTO/ISO, or ERCOT), or both, and a government regulator (FERC or PUCT). In contrast, an exemption for financial transactions that are not so monitored, or not related to the physical capacity of an electric transmission grid, or not directly linked to the physical generation and transmission of electricity, or not limited to appropriate persons, 91 is unlikely to be in the public interest or consistent with the purposes of the CEA and would not be subject to this exemption. 90 See id. at 6-9 (describing the Transactions and noting that each of them “is part of, and inextricably linked to, the organized wholesale electricity markets that are subject to FERC and PUCT regulation and oversight”). 91 See appropriate persons discussion, below, section V.B.3. Finally, and as discussed in detail below, the extent to which the Proposed Exemption is consistent with the public interest and the purposes of the Act can, in major part, be measured by the extent to which the tariffs and activities of the Petitioners, and supervision by FERC and PUCT, are congruent with, and sufficiently accomplish, the regulatory objectives of the relevant core principles set forth in the CEA for derivatives clearing organizations (“DCOs”) and swap execution facilities (“SEFs”). Specifically, providing a means for managing or assuming price risk and discovering prices, as well as prevention of price manipulation and other disruptions to market integrity, are addressed by the core principles for SEFs. Ensuring the financial integrity of the transactions and the avoidance of systemic risk, as well as protection from the misuse of participant assets, are addressed by the core principles for DCOs. Deterrence of price manipulation (or other disruptions to market integrity) and protection of market participants from fraudulent sales practices is achieved by the Commission retaining and exercising its jurisdiction over these matters. Therefore, the Commission has incorporated its DCO/SEF core principle analysis, set forth below, into its consideration of the Proposed Exemption's consistency with the public interest and the purposes of the Act. In the same way, the Commission has considered how the public interest and the purposes of the CEA are also addressed by the manner in which Petitioners comply with FERC's Credit Reform Policy. 92 92 See FERC Credit Reform Policy discussion, below, at section V.C. Based on this review, the Commission proposes to determine that the Proposed Exemption is consistent with the public interest and the purposes of the CEA, and the Commission is specifically requesting comment on whether the Proposed Exemption is consistent with the public interest and the purposes of the Act. 2. CEA Section 4(a) Should Not Apply to the Transactions or Entities Eligible for the Proposed Exemption CEA section 4(c)(2)(A) requires, in part, that the Commission determine that the Transactions covered under the Proposed Exemption should not be subject to CEA section 4(a)—generally, the Commission's exchange trading requirement for a contract for the purchase or sale of a commodity for future delivery. Based in major part on the Petitioners' representations, the Commission has examined the Transactions, the Petitioners, and their markets in the context of the CEA core principle requirements applicable to a DCO and to a SEF. 93 As further support for this determination, the Commission is also relying on the public interest and the purposes of the Act analysis in subsection 3 below. In so doing, the Commission can determine that, due to the FERC or PUCT regulatory scheme and the RTO/ISO or ERCOT market structure already applicable to the Transactions, the linkage between the Transactions and those regulatory schemes, and the unique nature of the market participants that would be eligible to rely on the Proposed Exemption, 94 CEA section 4(a) should not apply to the Transactions under the Proposed Exemption. 93 See DCO core principle analysis below, at section V.D.; see also SEF core principle analysis below, at section V.E. 94 See appropriate persons analysis, below, at section V.B.3. The Commission is requesting comment on whether its Proposed Exemption of the Transactions from CEA section 4(a) is appropriate. 3. Appropriate Persons CEA section 4a(c)(2)(B)(i) requires that the Commission determine that the Proposed Exemption is properly limited to transactions entered into between appropriate persons as described in CEA section 4(c)(3). The Petitioners assert that each Petitioner's market participants fit within the “appropriate person” requirement under CEA section 4(c)(3), relying primarily on two categories of appropriate persons. The first category includes those entities that have a net worth exceeding $1,000,000 or total assets exceeding $5,000,000, as identified in CEA section 4(c)(3)(F). 95 The second group of appropriate persons would fall within a grouping under CEA section 4(c)(3)(K), which includes persons deemed appropriate by the Commission “in light of their financial or other qualifications, or the applicability of appropriate regulatory protection.” 96 95 CEA section 4(c)(3)(F) provides that the following entities are “appropriate persons” that the Commission may exempt under CEA section 4(a). The relevant text of 4(c)(3)(F) provides: “A corporation, partnership, proprietorship, organization, trust, or other business entity with a net worth exceeding $1,000,000 or total assets exceeding $5,000,000, or the obligations of which under the agreement, contract or transaction are guaranteed or otherwise supported by a letter of credit or keepwell, support, or other agreement by any such entity or by an entity referred to in subparagraph (A), (B), (C), (H), (I), or (K) of this paragraph.” 96 CEA 4(c)(3)(K). The Petitioners explain that FERC has instructed all RTOs and ISOs subject to FERC supervision 97 to create minimum standards for market participants. The Petitioners state that: 97 According to the Petition, ERCOT is reviewing its “participants eligibility standards to ensure that they are consistent with the requirements of [CEA] Section 4(c).” Petition at 27. See also Attachment C to Petition, beginning at Attachments at 27 (“Through its stakeholder process, ERCOT is in the process of developing new eligibility requirements that are comparable to those required by FERC Order No. 741.”). In Order No. 741, FERC directed each of the ISOs/RTOs to establish minimum criteria for market participants. FERC did not specify the criteria the ISOs/RTOs should apply, but rather directed them to establish criteria through their stakeholder processes. Accordingly, each of the FERC jurisdictional ISOs/RTOs submitted to FERC proposals to establish minimum criteria for participation in their markets. Although ERCOT is not subject to the requirements FERC's Credit Reform Orders, ERCOT is reviewing its participant eligibility standards to ensure that they are consistent with the requirements of Section 4(c). These proposals were accepted by FERC subject to a supplemental compliance filing to provide for verification of risk management policies and procedures. Although there is some variation among the minimum participation criteria adopted by each ISO/RTO, included in each is a baseline capitalization requirement that participants have net worth of at least $1 million or total assets of at least $10 million. 98 98 Petition at 26-27 (citations omitted). However, the Petitioners acknowledge that there are exceptions to this “baseline capitalization requirement,” that is, market participants who do not meet the minimum net worth or total assets criteria under the CEA who pursuant to Petitioners' Tariffs must post financial security because they are under-capitalized. Nonetheless, as the Petitioners explain, there is an exception to the posting requirement for market participants with small positions. The Petitioners provide the following explanation for the exception: The criteria of some ISOs/RTOs also reduce the financial security posting requirement for certain entities that maintain only small positions on the markets of the ISO/RTO and therefore expose the ISOs/RTOs to minimal risk. These entities are instead required to post additional financial security with the ISO/RTO in an amount that would depend on the size of their positions. In this regard, a notable number of participants in the markets of some ISOs/RTOs include cooperatives, municipalities or other forms of public corporate entities which are authorized to own, lease and operate electric generation, transmission or distribution facilities. [ 99 ] Such entities' participation in the ISO/RTO may be necessary to make electricity available within the entire grid for a region. Nevertheless, they are “appropriate persons” because of their active participation in the generation, transmission or distribution of electricity and the knowledge of the wholesale energy market that they have as a consequence of their participation in the physical markets. Moreover, the municipal entities are entitled to recover their costs for native load service through governmentally established retail rates and, accordingly, are able to provide a form of financial security ( i.e., the ability to request a retail rate increase to cover increased costs) that is unavailable to other participants in the energy markets. As such, the risk of default by such entities is materially lower than it is for other Market Participants. 100 99 The Commission notes here that CEA 4(c)(3)(H) includes as eligible appropriate persons “Any governmental entity (including the United States, any state, or any foreign government) or political subdivision thereof, or any multinational or supranational entity or any instrumentality, agency, or department of any of the foregoing.” This appropriate persons category would cover the municipalities and other government owned market participants. 100 Petition at 27 (citations omitted). The Commission is proposing to limit the Proposed Exemption to entities that meet one of the appropriate persons categories in CEA section 4(c)(3)(A) through (J), or, pursuant to CEA section 4(c)(3)(K), that otherwise qualify as an eligible contract participant (“ECP”), as that term has been defined. 101 In this connection, the Commission notes that the municipal entities discussed above appear to qualify as “appropriate persons” pursuant to CEA section 4(c)(3)(H). 102 101 See CEA 1(a)(12). See also “Further Definition of `Swap Dealer,' `Security-Based Swap Dealer,' `Major Swap Participant,' `Major Security-Based Swap Participant' and `Eligible Contract Participant,' ” 77 FR 30596, May 23, 2012. 102 See 7 U.S.C. 6(c)(3)(H) (“Any governmental entity * * * including * * * any state * * * or political subdivision thereof * * * or any instrumentality, agency or department of any of the foregoing.”) Based on representations contained in the Petition, the Commission can determine the Proposed Exemption is limited to appropriate persons for those market participants meeting the categories described defined in CEA section 4(c)(3)(A) through (J). The CFTC is requesting comment as to whether the entities defined in CEA section 4(c)(3)(A) through (J) are appropriate persons for the purpose of the Proposed Exemption. For those ECPs engaging in Transactions in markets administered by the Petitioner that do not fit within 4(c)(3)(A) through (J), the Commission is proposing to determine that they are appropriate persons pursuant to section 4c(3)(K), “in light of their financial or other qualifications, or the applicability of appropriate regulatory protections” to the extent that such persons are otherwise ECPs. The Commission can base this determination on the financial security posting schemes, described by the Petitioners, applicable to the entities engaging in the Transactions, as well as the market based protections applicable to the Transactions regardless of participant, as described in the Commission's public interest and purposes of the Act analysis, above. In addition, CEA section 2(e) permits all ECPs to engage in swaps transactions other than on a designated contract market (“DCM”), and so such entities should similarly be appropriate persons for the purpose of the Proposed Exemption. The Commission is requesting comment on whether the market participants entering into the Transactions in markets administered by the Petitioners, particularly those that do not fit within 4(c)(3)(A) through (J), but that are ECPs, may nonetheless be appropriate persons pursuant to CEA section 4(c)(3)(K), in light of the financial posting scheme that applies to such participants, and in light of the regulatory and market oversight programs that apply to the Transactions in the Petitioners' markets. The Commission also requests comment as to whether there are currently entities engaging in the Transactions that are neither entities that fall within CEA section 4(c)(3)(A) through (J) entities nor ECPs. If there are such entities, on what basis may the Commission similarly conclude that such entities are, pursuant to CEA section 4(c)(3)(K), appropriate persons for the purpose of the Proposed Exemption? In particular, the Commission seeks comment as to whether there any other of the Petitioners' market participants that “active[ly] participat[e] in the generation, transmission or distribution of electricity” that are not ECPs and do not fall within CEA section 4(c)(3)(A) through (J), who should nonetheless be included as appropriate persons pursuant to CEA section 4(c)(3)(K). 4. Will Not Have a Material Adverse Effect on the Ability of the Commission or Any Contract Market To Discharge Its Regulatory or Self-Regulatory Duties Under the CEA CEA section 4(c)(2)(B)(ii) requires the Commission to determine that the Transactions subject to the Proposed Exemption will not have a material adverse effect on the ability of the Commission or any contract markets to perform regulatory or self-regulatory duties. 103 In making this determination, Congress indicated that the Commission is to consider such regulatory concerns as “market surveillance, financial integrity of participants, protection of customers and trade practice enforcement.” 104 These considerations are similar to the purposes of the Act as defined in CEA section 3, initially addressed in the public interest discussion, above. 103 CEA 4(c)(2)(B). 104 See H.R. No. 978, 102d Cong. 2d Sess. 79 (1992). Petitioners contend that the Proposed Exemption will not have a material adverse effect on the Commission's or any contract market's ability to discharge its regulatory function, 105 asserting that: 105 See Petition at 28. Under Section 4(d) of the Act, the Commission will retain authority to conduct investigations to determine whether [Petitioners] are in compliance with any exemption granted in response to this request. * * * [T]he requested exemptions would also preserve the Commission's existing enforcement jurisdiction over fraud and manipulation. This is consistent with section 722 of the Dodd-Frank Act, the existing MOU between the FERC and the Commission and other protocols for inter-agency cooperation. The [Petitioners] will continue to retain records related to the Transactions, consistent with existing obligations under FERC and PUCT regulations. The regulation of exchange-traded futures contracts and significant price discovery contracts (“SPDCs”) will be unaffected by the requested exemptions. Futures contracts based on electricity prices set in the Petitioners' markets that are traded on a designated contract market and SPDCs will continue to be regulated by and subject to the requirements of the Commission. No current requirement or practice of the ISOs/RTOs or of a contract market will be affected by the Commission's granting the requested exemptions. 106 106 See id. at 28. These factors appear to support the Proposed Exemption. In addition, the limitation of the exemption to Transactions between certain “appropriate persons” as discussed above, avoids potential issues regarding financial integrity and customer protection. That is, this approach would appear to ensure that Transactions subject to this Proposed Exemption would be limited to sophisticated entities that are able to, from a financial standpoint, understand and manage risks associated with such Transactions. Moreover, the Proposed Exemption does not exempt Petitioners from CEA sections 2(a)(1)(B), 4b, 4c(b), 4 o, 4s(h)(1)(A), 4s(h)(4)(A), 6(c), 6(d), 6(e), 6c, 6d, 8, 9, and 13, to the extent that those sections prohibit fraud or manipulation of the price of any swap, contract for the sale of a commodity in interstate commerce, or for future delivery on or subject to the rules of any contract market. Therefore, the Commission retains authority to pursue fraudulent or manipulative conduct. 107 107 Nor did the Petitioners seek an exemption from these provisions. See id. at 2-3. In addition, it appears that granting the exemption for the Transactions will not have a material adverse effect on the ability of any contract market to discharge its self-regulatory duties under the Act. With respect to FTRs, Forward Capacity Transactions, and Reserve or Regulation Transactions, these transactions do not appear to be used for price discovery or as settlement prices for other transactions in Commission regulated markets. Therefore, the Proposed Exemption should not have a material adverse effect on any contract market carrying out its self-regulatory function. With respect to Energy Transactions, these transactions do have a relationship to Commission regulated markets because they can serve as a source of settlement prices for other transactions within Commission jurisdiction. Granting the Proposed Exemption, however, should not pose regulatory burdens on a contract market because, as discussed in more detail below, Petitioners have market monitoring systems in place to detect and deter manipulation that takes place on their markets. Also, as a condition of the Proposed Exemption, the Commission would be able to obtain data from FERC and PUCT with respect to activity on Petitioners' markets that may impact trading on Commission regulated markets. Finally, the Commission notes that if the Transactions ever could be used in combination with trading activity or a position in a DCM contract to work some market abuse, both the Commission and DCMs have sufficient independent authority over DCM market participants to monitor for such activity. 108 Typically, cross-market abuse schemes will involve a reportable position in the DCM contract involved. In which case, Commission Regulation 18.05 requires the reportable trader to keep books and records evidencing all details concerning cash and over-the-counter positions and transactions in the underlying commodity and to provide such data to the Commission upon demand. Likewise, recently-adopted Commission regulation 38.254(a) requires that DCMs have rules that require traders to keep records of their trading, including records of their activity in the underlying commodity and related derivatives markets, and make such records available, upon request, to the DCM. 109 108 The Commission notes that its authority to prosecute market abuses involving Transactions would not be limited to instances where Transactions were part of some cross-market scheme involving DCM trading activity. 109 Final Rulemaking—Core Principles and Other Requirements for Designated Contract Markets, 72 FR 36612 (June 19, 2012). The CFTC is requesting comment as to whether the Proposed Exemption will have a material adverse effect on the ability of the Commission or any contract market to discharge its regulatory or self-regulatory duties under the Act, and, if so, what conditions can or should be imposed on the Order to mitigate such effects. C. FERC Credit Reform Policy On October 21, 2010, FERC amended its regulations to encourage clear and consistent risk and credit practices in the organized wholesale electric markets to, inter alia, “ensure that all rates charged for the transmission or sale of electric energy in interstate commerce are just, reasonable, and not unduly discriminatory or preferential.” 110 110 75 FR 65942, 65942, Oct. 21, 2010 (the “FERC Original Order 741”). These requirements were later slightly amended and clarified in an order on rehearing. See 76 FR 10492, Feb. 25, 2011 (“FERC Revised Order 741”, and together with Original Order 741, “FERC Order 741”). In effect, Order 741 requires those RTOs and ISOs that are subject to FERC supervision to implement the following reforms: “shortened settlement timeframes, restrictions on the use of unsecured credit, elimination of unsecured credit in all [FTRs] or equivalent markets, adoption of steps to address the risk that RTOs and ISOs may not be allowed to use netting and set-offs, establishment of minimum criteria for market participation, clarification regarding the organized markets' administrators' ability to invoke `material adverse change' clauses to demand additional collateral from participants, and adoption of a two-day grace period for `curing' collateral calls.” 111 Unlike the other Petitioners, ERCOT is regulated by the PUCT, not FERC. As a result, ERCOT is not subject to the particular stringent credit and risk management standards set forth in Order 741. As discussed below regarding conditions precedent starting on page 103 infra , the Commission is proposing to require compliance with the standards of Order 741 by all Petitioners, including ERCOT, as a condition to issuing the Proposed Exemption. 111 FERC Revised Order 741 at 10492-10493. As discussed in more detail below, particularly in section V.C., the requirements set forth in Order 741 appear to achieve goals similar to the regulatory objectives of the Commission's DCO Core Principles. FERC regulation 35.47(c) calls for the elimination of unsecured credit in the financial transmission rights markets and equivalent markets. 112 This requirement appears to be congruent with Core Principle D's requirement that each DCO limit its exposure to potential losses from defaults by clearing members. Because, according to FERC, risks arising out of the FTR markets are “difficult to quantify,” 113 eliminating the use of unsecured credit in these markets may help avoid the unforeseen and substantial costs for an RTO or ISO in the event of a default. 114 Thus, the requirement set forth in regulation 35.47(c) appears to advance the objectives of Core Principle D by reducing risk and minimizing the effect of defaults through the elimination of unsecured credit in the FTR and equivalent markets. 112 18 CFR 35.47(c). 113 Specifically, FERC stated that “the risk associated with the potentially rapidly changing value of FTRs warrants adoption of risk management measures, including the elimination of unsecured credit. Because financial transmission rights have a longer-dated obligation to perform which can run from a month to a year or more, they have unique risks that distinguish them from other wholesale electric markets, and the value of a financial transmission right depends on unforeseeable events, including unplanned outages and unanticipated weather conditions. Moreover, financial transmission rights are relatively illiquid, adding to the inherent risk in their valuation.” FERC Original Order 741 at 65950. 114 Id. at 65949. In addition, FERC regulation 35.47(a) requires RTOs and ISOs to have tariff provisions that “[l]imit the amount of unsecured credit extended by [an RTO or ISO] to no more than $50 million for each market participant.” 115 This requirement appears to be congruent with one of the regulatory objectives of Core Principle D, as implemented by Commission Regulation 39.13, specifically the requirement that each DCO limit its exposure to potential losses from defaults by clearing members. In capping the use of unsecured credit at $50 million, FERC stated its belief that RTOs and ISOs “could withstand a default of this magnitude by a single market participant,” 116 thereby limiting an RTO's or ISO's exposure to potential losses from defaults by its market participants. Thus, it seems both Core Principle D and FERC regulation 35.47(a) help protect the markets and their participants from unacceptable disruptions, albeit in different ways and to a different extent. 115 In addition, FERC regulation 35.47(a) states that “where a corporate family includes more than one market participant participating in the same [RTO or ISO], the limit on the amount of unsecured credit extended by that [RTO or ISO] shall be no more than $50 million for the corporate family.” 18 CFR 35.47(a). 116 FERC Original Order 741 at 65948. FERC regulation 35.47(b) mandates that RTOs and ISOs have billing periods and settlement periods of no more than seven days. 117 While this mandate does not meet the standards applicable to registered DCOs, 118 it supports Core Principle D's requirement that each DCO have appropriate tools and procedures to manage the risks associated with discharging its responsibilities. In promulgating FERC regulation 35.47(b), FERC found a shorter cycle necessary to promote market liquidity and a necessary change “to reduce default risk, the costs of which would be socialized across market participants and, in certain events, of market disruptions that could undermine overall market function.” 119 Recognizing the correlation between a reduction in the length of the “settlement cycle” and a reduction in costs attributed to a default, FERC stated that shorter cycles reduce the amount of unpaid debt left outstanding, which, in turn, reduces “the size of any default and therefore reduces the likelihood of the default leading to a disruption in the market such as cascading defaults and dramatically reduced market liquidity.” 120 Thus, FERC regulation 35.47(b) appears to aid RTOs and ISOs in managing the risks associated with their responsibilities, which also appears to support Core Principle D's goals. 117 18 CFR 35.47(b). 118 See 17 CFR 39.14(b) (requiring daily settlements). 119 FERC Original Order 741 at 65946. 120 Id. FERC regulation 35.47(d) requires RTOs and ISOs to ensure the enforceability of their netting arrangements in the event of the insolvency of a member by doing one of the following: (1) Establish a single counterparty to all market participant transactions, (2) require each market participant to grant a security interest in the receivables of its transactions to the relevant RTO or ISO, or (3) provide another method of supporting netting that provides a similar level of protection to the market that is approved by FERC. 121 In the alternative, the RTOs and ISOs would be prohibited from netting market participants' transactions, and required to establish credit based on each market participant's gross obligations. Congruent to the regulatory objectives of Core Principles D and G, FERC regulation 35.47(d) attempts to ensure that, in the event of a bankruptcy of a participant, ISOs/RTOs are not prohibited from offsetting accounts receivable against accounts payable. In effect, this requirement attempts to clarify an ISO's or RTO's legal status to take title to transactions in an effort to establish mutuality in the transactions as legal support for set-off in bankruptcy. 122 This clarification, in turn, would appear to limit an RTO's or ISO's exposure to potential losses from defaults by market participants. 121 18 CFR 35.47(d). 122 See 11 U.S.C. 553; see generally In re SemCrude, L.P., 399 B.R. 388 (Bankr. D. Del. 2009), aff'd, 428 B.R. 590 (D. Del. 2010). FERC regulation 35.47(e) limits the time period within which a market participant must cure a collateral call to no more than two days. 123 This requirement appears to be congruent with Core Principle D's requirement that each DCO limit its exposure to potential losses from defaults by clearing members. In Original Order 741, FERC stated that a two day time period for curing collateral calls balances (1) the need for granting market participants sufficient time to make funding arrangements for collateral calls with (2) the need to minimize uncertainty as to a participant's ability to participate in the market, as well as the risk and costs of a default by a participant. By requiring each ISO and RTO to include this two day cure period in the credit provisions of its tariff language, FERC regulation 35.47(e) appears to both promote the active management of risks associated with the discharge of an RTO's or ISO's responsibilities, while at the same time limiting the potential losses from defaults by market participants. 123 18 CFR 35.47(e). FERC regulation 35.47(f) imposes minimum market participant eligibility requirements that apply consistently to all market participants and, as set forth in the preamble to Original Order 741, requires RTOs and ISOs to engage in periodic verification of market participant risk management policies and procedures. 124 The Commission believes that the requirements set forth in FERC regulation 35.47(f) appear congruent with some of the regulatory objectives of DCO Core Principle C, as implemented by Commission regulation 39.12. In general, DCO Core Principle C requires each DCO to establish appropriate admission and continuing eligibility standards for members of, and participants in, a DCO that are objective, publicly disclosed, and permit fair and open access. 125 In addition, Core Principle C also requires that each DCO establish and implement procedures to verify compliance with each participation and membership requirement, on an ongoing basis. 126 Similarly, while FERC regulation 35.47(f) does not prescribe the particular participation standards that must be implemented, as suggested in the preamble to Original Order 741, these standards should address “adequate capitalization, the ability to respond to ISO/RTO direction and expertise in risk management” 127 and ensure that proposed tariff language “is just and reasonable and not unduly discriminatory.” 128 Moreover, FERC specifically stated that these participation standards “could include the capability to engage in risk management or hedging or to out-source this capability with periodic compliance verification, to make sure that each market participant has adequate risk management capabilities and adequate capital to engage in trading with minimal risk, and related costs, to the market as a whole.” 129 Thus, both DCO Core Principle C and Order 741 appear to promote fair and open access for market participants as well as impose compliance verification requirements. 124 18 CFR 35.47(f). 125 7 U.S.C. 7a-1(c)(2)(C). 126 Id. 127 FERC Original Order 741 at 65956. 128 Id. 129 Id. FERC regulation 35.47(g) requires ISOs and RTOs to specify in their tariffs the conditions under which they will request additional collateral due to a material adverse change. 130 FERC, however, noted that the examples set forth in each ISO's or RTO's tariffs are not exhaustive and that ISOs and RTOs are permitted to use “their discretion to request additional collateral in response to unusual or unforeseen circumstances.” 131 The Commission believes that the requirements set forth in FERC regulation 35.47(g) appear congruent with the following DCO Core Principle D requirements: (1) That DCOs have appropriate tools and procedures to manage the risks associated with discharging its responsibilities, and (2) that DCOs limit their exposure to potential losses from defaults by clearing members. 132 By requiring ISOs and RTOs to actively consider the circumstances that could give rise to a material adverse change, FERC appears to be encouraging RTOs and ISO to actively manage their risks to “avoid any confusion, particularly during times of market duress, as to when such a clause may be invoked.” 133 Moreover, such clarification could prevent a market participant's ability to “exploit ambiguity as to when a market administrator may invoke a `material adverse change,' or a market administrator may be uncertain as to when it may invoke a `material adverse change,' ” 134 thereby avoiding potentially harmful delays or disruptions that could subject the RTOs and ISOs to unnecessary damage. 130 18 CFR 35.47(g). 131 FERC Original Order 741 at 65957. 132 7 U.S.C. 7a 1(c)(2)(D). 133 FERC Original Order 741 at 65958. 134 Id. As such, on the basis of the representations contained in the Petition, including the fact that, as discussed in further detail below, 135 the Commission is considering whether to require each Petitioner, including ERCOT, to comply with, and fully implement, the requirements set forth in Order 741 as a prerequisite to the granting of a limited 4(c)(6) exemption for the Transactions. The Commission seeks comment with respect to this preliminary conclusion. 135 See infra text at n. 398. D. DCO Core Principle Analysis 1. DCO Core Principle A: Compliance With Core Principles Core Principle A requires a DCO to comply with each core principle set forth in section 5b(c)(2) of the CEA, as well as any requirement that the Commission may impose by rule or regulation pursuant to section 8a(5) of the Act for a DCO to be registered and maintain its registration. 136 In addition, Core Principle A states that a DCO shall have reasonable discretion in establishing the manner by which it complies with each core principle subject to any rule or regulation prescribed by the Commission. 137 136 7 U.S.C. 7a-1(c)(2)(A)(i). 137 7 U.S.C. 7a-1(c)(2)(A)(ii). Petitioners represent that, although they are principally regulated by FERC and PUCT and that there are differences between Petitioners and registered DCOs, Petitioners' practices are consistent with the core principles for DCOs. 138 Petitioners represent that, though their methods are different than those employed by a registered DCO, their practices achieve the goals of, and are consistent with, the policies of the Act. 139 Based upon Petitioners' representations and the core principle discussions below, and in the context of the Petitioners' activities with respect to the Transactions within the scope of this Proposed Exemption, Petitioners' practices appear congruent with, and to accomplish sufficiently, the regulatory objectives of each DCO core principle. The Commission seeks comment with respect to this preliminary conclusion. 138 Petition Attachments at 1. 139 Id. 2. DCO Core Principle B: Financial and Operational Resources Core Principle B requires a DCO to have adequate financial, operational, and managerial resources to discharge each of its responsibilities. 140 In addition, a DCO must have financial resources that, at a minimum, exceed the total amount that would: (i) Enable the DCO to meet its financial obligations to its clearing members notwithstanding a default by the clearing member creating the largest financial exposure for the DCO in extreme but plausible market conditions; and (ii) enable the DCO to cover its operating costs for a period of 1 year, as calculated on a rolling basis. 141 140 7 U.S.C. 7a-1(c)(2)(B)(i). 141 7 U.S.C. 7a-1(c)(2)(B)(ii). a. Financial Resources Petitioners represent that they maintain sufficient financial resources to meet their financial obligations to their members notwithstanding a default by the member creating the largest financial exposure for that organization in extreme but plausible market conditions. 142 As an initial matter, Petitioners apply the defaulting market participant's collateral to the outstanding obligation. 143 Further, if the collateral is inadequate to cover the obligation, Petitioners' tariffs permit them to charge the loss to non-defaulting market participants. 144 For some Petitioners, other resources are available. For example, one Petitioner represents that it has the ability to draw upon its working capital fund and/or its revolving credit facility to ensure that market participants are paid in full. 145 Another Petitioner states that defaults are socialized after realizing any collateral specific to the defaulting participant, claims paid by third-party default insurance, funds from accrued collected penalties for Late Payment Accounts, and, for liquidity purposes, third-party financing. 146 142 See Petition Attachments at 3-20. 143 See, e.g., id. at. 4, 8-9, 10, 15, 20. 144 See id. at 4, 8, 10, 13, 15, 20. 145 See id. at 15. The Commission notes Regulation 39.11(b) includes the following as financial resources eligible to satisfy a DCO's requirement to have sufficient financial resources to cover a default by the member creating the largest financial exposure: (a) Margin, (b) the DCO's own capital, (c) guaranty fund deposits, (d) default insurance, (e) potential assessments for additional guaranty fund contributions, if permitted by the DCO's rules, and (f) any other financial resource deemed acceptable by the Commission. See 17 CFR 39.11(b)(1). The Commission notes that the revolving credit facility cited by NYISO would not satisfy the financial resource requirement, but would be considered in determining liquidity. See 17 CFR 39.11(e)(1)(iii). 146 See Petition Attachments at 10-11. In the event that a default occurs and there is inadequate collateral for a particular participant, the Petitioners' represent that the deficiencies would be addressed by mutualization among the non-defaulting participants to whom the Petitioner would otherwise be obligated, allocated pursuant to a pre-determined formula that is included in each Petitioner's tariff. 147 This process is often referred to as “short-paying.” 148 Once the amount of the default is deemed to be uncollectible [by the Petitioner], the short-pay would, in some cases, be “uplifted” or “socialized” across the market, with the losses reallocated among all non-defaulting participants. 149 147 See, e.g., id. at 9, 13. 148 See, e.g., id. at 15. 149 See, e.g., id. at 9, 13. On the basis of these representations, the Commission believes that each Petitioner's financial resource requirements appear to be congruent with, and to accomplish sufficiently, the regulatory objectives of DCO Core Principle B in the context of Petitioners' activities with respect to the Transactions. The Commission seeks comment with respect to this preliminary conclusion. b. Operational Resources Each Petitioner represents that it has sufficient operational resources to cover its operating costs through a charge allocated to its participants and set forth in its Tariffs, which are approved by FERC and PUCT, as applicable. 150 Petitioners represent that the charge is based on expected costs for the following year. 151 Under the regulatory structure in the wholesale electric industry, market participants are obligated to pay the fees required by the Petitioners, 152 and are thus, in a sense, a “captive audience.” Moreover, since market participant defaults are mutualized amongst the non-defaulting participants, 153 Petitioners represent that such defaults would not impair their ability to cover their operating costs, because the Petitioners would continue to collect sufficient funds from all other market participants to pay such operating expenses. 154 Therefore, these policies and procedures appear to be consistent with, and to accomplish sufficiently, the regulatory objectives of DCO Core Principle B in the context of the Transactions. The Commission seeks comment with respect to this preliminary conclusion. 150 See id. at 3-20. Some Petitioners state that the charge is allocated to their market participants based on the level of their usage of the Petitioner's services or on the volume of their market transactions. See, e.g., id. at 4, 13, and 20. 151 See, e.g., id. at 4, 10, 16. 152 See, e.g., id. at 16, 20. 153 See id. at 4-20. 154 See id. at 16. c. Managerial Resources Each of the Petitioners represents that it has adequate managerial resources to discharge its responsibilities as an organized wholesale electricity market. 155 The Commission notes that FERC Order No. 888 sets forth the principles used by FERC to assess ISO proposals and requires that ISOs have appropriate incentives for efficient management and administration. 156 This requirement provides that ISOs should procure the services needed for such management and administration in an open competitive market, similar to how Core Principle B requires a DCO to possess managerial resources necessary to discharge each responsibility of the DCO. Similarly, with respect to ERCOT, PUCT's Substantive Rules require that ERCOT's Enterprise Risk Management Group has adequate resources to perform its functions, which includes assessing market participant creditworthiness. 157 155 See id. at 3-20. 156 See generally FERC Order 888 at 21540. 157 P.U.C. SUBST. R. 25.361(b). See also Petition Attachments at 7-8. In addition, FERC Order No. 2000 requires that RTOs have an open architecture so that the RTO and its members have the flexibility to improve their organizations in the future in terms of structure, geographic scope, market support and operations in order to adapt to an environment that is rapidly changing and meet market needs. 158 158 Id. at 502. Petitioners represent that they maintain the staff and labor necessary to fulfill their obligations and responsibilities, and only employ persons who are appropriately qualified, skilled and experienced in their respective trades or occupations 159 Based on these representations, the Petitioners managerial resources appear to be consistent with, and to accomplish sufficiently, the regulatory objectives of DCO Core Principle B in the context of the Transactions. The Commission seeks comment with respect to this preliminary conclusion. 159 See Petition Attachments at 3-20. 3. DCO Core Principle C: Participant and Product Eligibility DCO Core Principle C requires each DCO to establish appropriate admission and continuing eligibility standards for member and participants (including sufficient financial resources and operational capacity), as well as to establish procedures to verify, on an ongoing basis, member and participant compliance with such requirements. 160 The DCO's participant and membership requirements must also be objective, be publicly disclosed, and permit fair and open access. 161 In addition, Core Principle C obligates each DCO to establish appropriate standards for determining the eligibility of agreements, contracts, or transactions submitted to the DCO for clearing. 162 160 7 U.S.C. 7a-1(c)(2)(C). 161 Id. 162 Id. As set forth above, the exemption that would be provided by the Proposed Exemption would be available only with respect to the transactions specifically delineated therein. Accordingly, the DCO Core Principle C analysis is limited to a discussion of the Petitioners' participant eligibility requirements. a. FERC Credit Policy Requirements As discussed above, the FERC Credit Policy appears to impose participant eligibility requirements that are consistent with regulatory objectives of DCO Core Principle C. 163 In the FERC Credit Policy, FERC notes that “[h]aving minimum criteria in place can help minimize the dangers of mutualized defaults posed by inadequately prepared or under-capitalized participants.” 164 Specifically, FERC regulation 35.47(f) requires organized wholesale electric markets to adopt tariff provisions that require minimum market participant eligibility criteria. 165 Though the regulation does not prescribe the particular participation standards that must be implemented; in the rule's preamble, FERC suggests that such standards should address “adequate capitalization, the ability to respond to ISO/RTO direction and expertise in risk management.” 166 Regarding risk management, FERC further suggests that minimum participant eligibility criteria should “include the capability to engage in risk management or hedging or to out-source this capability with periodic compliance verification.” 167 Although market participant criteria may vary among different types of market participants, all market participants must be subject to some minimum criteria. 168 An RTO or ISO subject to FERC's supervision is obligated to establish market participant criteria, even if the RTO or ISO applies vigorous standards in determining the creditworthiness of its market participants. 169 163 See, supra n. 127 and accompanying text. 164 FERC Original Order 741 at 665955. 165 18 CFR 35.47(f). 166 FERC Original Order 741 at 665956. 167 Id. 168 Although the FERC Credit Policy states that FERC “directs that [the market participation criteria] apply to all market participants rather than only certain participants,” FERC clarified this comment in its Order of Rehearing by stating that its intent “was that there be minimum criteria for all market participants and not that all market participants necessarily be held to the same criteria” based upon, for example, the size of the participant's positions. See FERC Revised Order 741 at n. 43. This approach appears to be consistent with Commission regulation 39.12, which implements Core Principle C and requires that participation requirements for DCO members be risk-based. 169 See FERC Original Order 741 at 665956 (noting that “An ISO or RTO's “ability to accurately assess a market participant's creditworthiness is not infallible” and “[w]hile an analysis of creditworthiness may capture whether the market participant has adequate capital, it may not capture other risks, such as whether the market participant has adequate expertise to transact in an RTO/ISO market.”). Because the minimum participation criteria that will be adopted by Petitioners will be included in their respective tariffs, which are publicly available on each Petitioner's Web site, such criteria will be publicly disclosed. In addition, FERC notes that it reviews proposed tariff language “to ensure that it is just and reasonable and not unduly discriminatory,” 170 which practice would appear to be consistent with DCO Core Principle C's directive that market participation standards permit fair and open access. 170 Id. b. The Petitioners' Representations Each Petitioner represents that it either has adopted minimum participant eligibility criteria or is in the process of establishing minimum participant eligibility criteria 171 that include capitalization requirements (which may provide for the posting of additional collateral by less-well-capitalized members). The capitalization requirements appear to be risk-based in that the requirements may vary by type of market and/or type or size of participant. 172 In addition, some Petitioners require that participants in certain markets satisfy specified credit requirements, 173 as well as standards related to risk management, 174 training and testing, 175 and the disclosure of material litigation or regulatory sanctions, bankruptcies, mergers, acquisitions, and activities in the wholesale electricity market. 176 Petitioners also represent that they impose operational capability requirements, 177 and either maintain tariffs, or have filed proposed amendments to their existing tariffs, that incorporate requirements that would enable Petitioners to periodically verify the risk management standards and procedures of market participants. 178 This verification may be required on either a random basis or based upon identified risks. Furthermore, some Petitioners require attestations of continued compliance with other elements of their participation eligibility criteria. 179 171 See Petition Attachments at 22-54. 172 See id. at 22-54. 173 See, e.g., id. at 22 (CAISO requires CRR holders to have a minimum amount of available credit in order to participate in a CRR auction). 174 See id. at 23, 35, 44-45. 175 See id. at 22, 35, 44. 176 See id. at 33. 177 See id. at 23, 37-38, 39, 48. 178 See id. at 23, 35-36, 38, 44-45, 49. 179 For example, CAISO requires market participants to attest annually that they satisfy CAISO's minimum participation requirements related to capitalization, training and the operational capability to comply with CAISO's direction. See id. at 23. Similarly, ISO NE requires that each market participant annually submit a certificate that attests that the participant has procedures to effectively communicate with ISO NE and that it has trained personnel related to its participation in the relevant markets. See id. at 35. ERCOT asserts that it is in the process of developing new eligibility requirements through its stakeholder process, that, as proposed, would require relevant market participants to (i) satisfy minimum capitalization requirements or post additional security, (ii) have appropriate expertise in the market, (iii) maintain a risk management framework appropriate to the ERCOT markets in which it transacts, (iv) have appropriate operational capability to respond to ERCOT direction, and (v) have the market participant's officer certify, on an annual basis, that the participant eligibility requirements are met. 180 180 See Petition Attachments at 27. See also FERC Order 741 Implementation Chart filed by petitioners as a supplement to the Petition (herein after, “FERC Order 741 Implementation Chart”), available at http://www.cftc.gov/stellent/groups/public/@requestsandactions/documents/ifdocs/iso-rto4cappfercchart.pdf. It appears from the foregoing that Petitioners' arrangements with respect to participant eligibility requirements are (or will be) congruent with, and sufficiently accomplish, the regulatory objectives of Core Principle C in the context of Petitioners' activities with respect to the Transactions. The Commission seeks comment with respect to this preliminary conclusion. 4. DCO Core Principle D: Risk Management DCO Core Principle D requires each DCO to demonstrate the ability to manage the risks associated with discharging the responsibilities of a DCO through the use of appropriate tools and procedures. 181 As amended by the Dodd-Frank Act, Core Principle D also requires a DCO to: (1) Measure and monitor its credit exposures to each clearing member daily; (2) through margin requirements and other risk control mechanisms, limit its exposure to potential losses from a clearing member default; (3) require sufficient margin from its clearing members to cover potential exposures in normal market conditions; and (4) use risk-based models and parameters in setting margin requirements that are reviewed on a regular basis. 182 181 7 U.S.C. 7a-1(c)(2)(D). 182 7 U.S.C. 7a-1(c)(2)(D). a. Risk Management Framework Each Petitioner represents that it has established policies and procedures designed to minimize risk. 183 As part of the tools and procedures that RTOs and ISOs use to manage the risks associated with their activities, FERC regulation 35.47(b) mandates that RTOs and ISOs have billing periods and settlement periods of no more than seven days. 184 As discussed above, FERC found a shorter cycle necessary to promote market liquidity and a necessary change “to reduce default risk, the costs of which would be socialized across market participants and, in certain events, of market disruptions that could undermine overall market function.” 185 Recognizing the correlation between a reduction in the “settlement cycle” and a reduction in costs attributed to a default, FERC stated that shorter cycles reduce the amount of unpaid debt left outstanding, which, in turn, reduces “the size of any default and therefore reduces the likelihood of the default leading to a disruption in the market such as cascading defaults and dramatically reduced market liquidity.” 186 Most of the Petitioners represent that they have, or expect to have, final tariffs in place that limit billing periods and settlement periods to no more than seven days. 187 183 See Petition Attachments at 56-92. 184 18 CFR 35.47(b). 185 FERC Original Order 741 at 65946. 186 Id. 187 See FERC Order 741 Implementation Chart. As stated above, ERCOT is not required, by law, to comply with Order 741. Nonetheless, Petitioners represent that ERCOT will shorten its payment and settlement cycle to no more than 15 days. See infra nn. 212-213 and accompanying text. In addition, an ISO's or RTO's participation standards can include the supervision of a market participant's risk management program. 188 As discussed in section V.C., FERC Order 741 states that an ISO or RTO could include periodic verification of market participant's capability to engage in risk management or hedging or to out-source that capability “to make sure each market participant has adequate risk management capabilities and adequate capital to engage in trading with minimal risk, and related costs, to the market as a whole.” 189 Each Petitioner regulated by FERC represents that it either has a verification program in place or has submitted necessary Tariffs for approval to establish a verification program. 190 ERCOT also has proposed participant eligibility requirements that would subject participants' risk management framework to verification by ERCOT, unless that framework has been deemed sufficient for transacting in another U.S. RTO or ISO market in accordance with a FERC-approved tariff or in accordance with the Federal Reserve Bank Holding Company Supervision Manual. The proposed requirements currently are under review in the ERCOT stakeholder process. 191 On the basis of the representations contained in the Petition, it appears that these policies and procedures, are (or will be, assuming they are implemented) congruent with, and will sufficiently accomplish, the regulatory objectives of DCO Core Principle D. The Commission seeks comment with respect to this conclusion. 188 See n. 126 and accompanying text. 189 See FERC Original Order 741 at 65946. 190 See FERC Order 741 Implementation Chart at 11-12. 191 Id. b. Measurement and Monitoring of Credit Exposure Petitioners represent that their risk management procedures measure, monitor, and mitigate their credit exposure to market participants. 192 In addition, most Petitioners state that they calculate credit exposure daily. 193 It appears that, for the most part, given the unique characteristics of the wholesale electric markets, and particularly those of the FTR and equivalent markets, the practices specified in the Petition appear congruent with, and to accomplish sufficiently, DCO Core Principle D's objective that a DCO measure its credit exposure to each of its clearing members. The Commission seeks comment with respect to this preliminary conclusion, including comment on whether any different or additional practices should be implemented as a condition of issuance of the Proposed Exemption. 192 See Petition Attachments at 56-92. 193 See id. Petitioners further represent that the value of exposure to FTRs is determined by the price of physical electricity during the days and hours for which the FTR is effective. See id. In addition, petitioners represent that CAISO- updates credit exposures for CRR's that are expected to generate a charge to the CRR holder on at least a monthly basis. See id. at 59-60. But see id. at 84-85 (representing that PJM calculates credit exposure for FTRs on a monthly basis because daily measurement and intraday monitoring of credit exposure is not practical for FTRs due to the low liquidity and other unique attributes of the FTR markets). c. Unsecured Credit Petitioners represent that a market participant is required to obtain unsecured credit lines from an RTO or ISO (limited as discussed below) and/or post financial security that is sufficient to meet the participant's estimated aggregate liability 194 or financial obligations. 195 FERC regulation 35.47(a) requires RTOs and ISOs to have tariff provisions that “[l]imit the amount of unsecured credit extended by [an RTO or ISO] to no more than $50 million for each market participant.” As mentioned above, 196 in capping the use of unsecured credit at $50 million, FERC stated its belief that RTOs and ISOs “could withstand a default of this magnitude by a single market participant,” therein limiting an RTO's or ISO's exposure to potential losses from defaults by its market participants. Petitioners represent that they have tariff provisions that comply with FERC regulation 35.47(a). 197 Moreover, FERC regulation 35.47(c) prohibits the use of unsecured credit in the FTR markets and equivalent markets because, according to FERC, risks arising out of the FTR markets are “difficult to quantify,” and eliminating the use of unsecured credit in these markets avoids the unforeseen and substantial costs for an RTO or ISO in the event of a default. Petitioners state that they have in place or have proposed tariff revisions to comply with FERC regulation 35.47(c). 198 194 A participant's estimated credit exposure to an RTO or ISO is called such participant's estimated aggregate liability or “EAL.” The EAL calculation is based on a number of variables, which vary among Petitioners. See id. at 56-92. 195 The Commission notes that NYISO establishes separate credit requirements for each of its product and service categories and requires each Market Participant to maintain financial security ( e.g., cash, letter of credit, or surety bond) that is sufficient at all times to meet each separate credit requirement. See id. at 84. 196 See supra at n. 115. 197 See FERC Order 741 Implementation Chart at 2-3. 198 See id. at 4-5. Since FERC regulations 35.47(a) and 35.47(c) appear to manage risk and limit an RTO's or ISO's exposure to potential losses from a market participant, these requirements would appear to be congruent with, and, assuming Petitioners' proposed tariff revisions are implemented, to accomplish sufficiently, the regulatory objectives of Core Principle D in the context of Petitioners' activities with respect to the Transactions. The Commission seeks comment with respect to this preliminary conclusion. d. Limiting Exposure to Potential Losses Through Use of Risk Control Mechanisms and Grace Period To Cure Each Petitioner represents that it requires a market participant to post additional financial security (collateral) whenever the participant's estimated aggregate liability or credit exposure equals or exceeds that participant's unsecured credit and posted financial security. 199 Moreover, FERC regulation 35.47(e) limits the time period by which a market participant must cure a collateral call to no more than two days. In Original Order 741, FERC stated that a two day time period for curing collateral calls balances the need for granting market participants sufficient time to make funding arrangements for collateral calls with the need to minimize uncertainty as to a participant's ability to participate in the market as well as the risk and costs of a default by a participant. By requiring each RTO and ISO to include this two day cure period in its tariff provisions, FERC regulation 35.47(e) appears to both promote the active management of risks associated with the discharge of an RTO's or ISO's responsibilities, while at the same time limiting the potential losses from defaults by market participants. Petitioners represent that each of them has implemented this requirement. 200 In the event that a market participant fails to post additional financial security in response to a request from an RTO or ISO, or fails to do so within the requisite two day period, Petitioners represent that they have a wide array of remedies available, including bringing an enforcement action and assessing a variety of sanctions against the market participant. 201 On the basis of these representations, it appears that the requirements to post additional financial security and cure collateral calls in no more than two days help Petitioners manage risk and limit their exposure against potential losses from a market participant. These requirements appear to be congruent with, and to accomplish sufficiently, the regulatory objectives of DCO Core Principle D in the context of Petitioners' activities with respect to the Transactions. The Commission seeks comment with respect to this preliminary conclusion. 199 See Petition Attachments at 56-92. 200 See FERC Order 741 Implementation Chart at 7. 201 See, e.g., Petition Attachments at 56-57, 69-70, 76-77. e. Calls for Additional Collateral due to a Material Adverse Change FERC regulation 35.47(g) requires ISOs and RTOs to specify in their tariffs the conditions under which they will request additional collateral due to a material adverse change. However, as stated by FERC, this list of conditions is not meant to be exhaustive, and ISOs and RTOs are permitted to use “their discretion to request additional collateral in response to unusual or unforeseen circumstances.” 202 Petitioners represent that they have tariffs that comply with these requirements. 203 Since Petitioners do not appear to be limited in their ability to call for additional collateral in unusual or unforeseen circumstances, FERC regulation 35.47(g) appears to support some of DCO Core Principle D's objectives, namely that a DCO have appropriate tools and procedures to manage the risks associated with discharging its responsibilities, and that a DCO limit its exposure to potential losses from defaults by clearing members. FERC has noted that information regarding when an ISO or RTO will request additional collateral due to a material adverse change may help to “avoid any confusion, particularly during times of market duress, as to when such a clause may be invoked,” 204 while at the same time preventing a market participant from “exploit[ing] ambiguity as to when a market administrator may invoke a `material adverse change.'” 205 As such, this policy appears to help avoid potentially harmful delays or disruptions that could subject the RTOs and ISOs to unnecessary damage, and thus is congruent with, and to accomplish sufficiently, the regulatory objectives of Core Principle D in the context of Petitioners' activities with respect to the Transactions. The Commission seeks comment with respect to this preliminary conclusion. 202 FERC Original Order 741 at 65957. 203 See FERC Order 741 Implementation Chart. 204 FERC Original Order 741 at 65958. 205 Id. at 65958. f. Margin Requirement and Use of Risk-Based Models and Parameters in Setting Margin As discussed previously, Petitioners represent that each Petitioner requires that market participants maintain unsecured credit and/or post financial security (collectively, “margin”) that is sufficient to meet their estimated aggregate liability or financial obligations at all times, 206 although estimated aggregate liability calculations appear to vary among Petitioners and among products within a particular Petitioner's markets. 207 As represented by Petitioners, these practices seem to be congruent with, and to accomplish sufficiently, the regulatory objectives of DCO Core Principle D in the context of Petitioners' activities with respect to the Transactions. The Commission seeks comment with respect to this preliminary conclusion. 206 See Petition Attachments at 56-92. 207 For example, one Petitioner states that its margin requirements are calculated using historical data and estimates of potential future exposure for the purposes of minimizing default exposure, but notes that the mechanics of the potential future exposure estimates “vary depending on the market.” See id. at 77. It maintains customized approaches to margining particular market activity, including separate and distinct margining models for the FTR Market and the Forward Capacity Market (both the buy side and the sell side). Id. at 77-78 Similarly, another Petitioner states that its credit requirements are derived from historical data from the past three years for FTRs, but from the past one year for other transactions. Id. at 91-92. g. Ability To Offset Market Obligations FERC regulation 35.47(d) requires RTOs and ISOs to either (1) establish a single counterparty to all market participant transactions, (2) require each market participant to grant a security interest in the receivables of its transactions to the relevant RTO or ISO, or (3) provide another method of supporting netting that provides a similar level of protection to the market that is approved by FERC. Otherwise, RTOs and ISOs are prohibited from netting market participants' transactions and required to establish credit based on market participants' gross obligations. FERC regulation 35.47(d), which attempts to ensure that, in the event of a bankruptcy, ISOs and RTOs are not prohibited from offsetting accounts receivable against accounts payable, is congruent with the regulatory objectives of Core Principle D. In effect, this requirement appears to attempt to clarify an ISO's or RTO's legal status to take title to transactions in an effort to establish mutuality in the transactions as legal support for set-off in bankruptcy. 208 This clarification, in turn, would seem to limit an RTO's or ISO's exposure to potential losses from defaults by market participants. 208 See supra n. 122. Petitioners have represented that they either are, or plan on becomi [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%3A2012-20965. Public record. Not legal advice.