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Notice

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

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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]

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]

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]

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:

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]

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]

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]

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.

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]

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]

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]

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]

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.

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]

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]

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]

“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]

“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.

“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.

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]

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]

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.

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]

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]

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]

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]

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]

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]

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]

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.

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]

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.

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]

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:

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]

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]

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]

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.

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:

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]

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]

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]

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]

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.

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.

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.

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.

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.

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.

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.

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.

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.

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]

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.

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]

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]

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]

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.

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]

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]

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.

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]

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]

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.

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]

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]

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]

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]

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.

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.

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]

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.

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.

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.

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.

Petitioners have represented that they either are, or plan on becoming, central counterparties.[209] Though there appears to be strong support for the proposition that the central counterparty structure [210] would give rise to enforceable rights of setoff of the central counterparty, the Commission believes it would be in the public interest to have further clarity regarding whether a Petitioner's chosen approach to comply with FERC regulation 35.47(d) grants sufficient certainty regarding the ability to enforce setoff rights. As such, the Commission proposes that, as a prerequisite to the granting of the 4(c)(6) request, each Petitioner must submit a well-reasoned legal memorandum from, or a legal opinion of, outside counsel that, in the Commission's sole discretion, provides the Commission with adequate assurance that the approach selected by the Petitioner will in fact provide the Petitioner with set-off rights in a bankruptcy proceeding.

Subject to this condition, compliance with FERC regulation 35.47(d) appears to be congruent with, and to accomplish sufficiently, Core Principle D's regulatory objectives in the context of Petitioners' activities with respect to the Transactions. The Commission seeks comment with respect to this preliminary conclusion. The Commission also seeks comment with respect to the proposed prerequisite of assurance that the Petitioners can in fact exercise setoff rights in the event of the bankruptcy of a participant.

5. DCO Core Principle E: Settlement Procedures

Among the requirements set forth by Core Principle E are the requirements that a DCO (a) have the ability to complete settlements on a timely basis under varying circumstances, and (b) maintain an adequate record of the flow of funds associated with each transaction that the DCO clears.[211]

Petitioners represent that they have policies and procedures that contain detailed procedures regarding data and record-keeping, and that, with the exception of ERCOT, they have, or will soon have, billing periods and settlement periods of no more than seven days each (for a total of 14 days).[212] ERCOT is in the process of implementing changes by which the weighted average billing and settlement cycle will be less than 15 days.[213] While this approach does not meet the standards applicable to registered DCOs,[214] it appears to be congruent with, and to accomplish sufficiently, the regulatory objectives of DCO Core Principle E in the context of Petitioners' activities with respect to the Transactions. The Commission seeks comment on this preliminary conclusion.

6. DCO Core Principle F: Treatment of Funds

Core Principle F requires a DCO to have standards and procedures designed to protect and ensure the safety of member and participant funds, to hold such funds in a manner that would minimize the risk of loss or delay in access by the DCO to the funds, and to invest such funds in instruments with minimal credit, market, and liquidity risks.[215]

Petitioners represent that they have tariff provisions and related governing documents that accomplish the regulatory goals of DCO Core Principle F.[216] For example, CAISO represents that its tariffs require it to maintain specified types of separate accounts for funds it receives or holds, including segregated and aggregated market clearing accounts.[217] Similarly, MISO represents that its tariffs require MISO to hold all monies deposited by its participants (whom MISO refers to as “Tariff Customers”) as financial assurance in a separate, interest-bearing money market account with one-hundred percent of the interest earned accruing to the benefit of the Tariff Customer.[218] The other Petitioners represent that they have appropriate investment policies or practices, such as segregation requirements and/or limitations on investment options.[219] As represented by Petitioners, these practices appear congruent with, and to accomplish sufficiently, the regulatory objectives of DCO Core Principle F in the context of Petitioners' activities with respect to the Transactions. The Commission seeks comment with respect to this preliminary conclusion.

7. DCO Core Principle G: Default Rules and Procedures

Core Principle G requires a DCO to have rules and procedures designed to allow for the efficient, fair, and safe management of events when members or participants become insolvent or otherwise default on their obligations to the DCO.[220] Core Principle G also requires a DCO to clearly state its default procedures, make publicly available its default rules, and ensure that it may take timely action to contain losses and liquidity pressures and to continue meeting each of its obligations.[221]

a. General Default Procedures

Each Petitioner represents that it has procedures in its tariffs or other governing documents that address events surrounding the insolvency or default of a market participant.[222] For example, Petitioners represent that such documents identify events of default (e.g. failure to make payments when due, failure to support an estimated liability with adequate security, events of insolvency, and failure to perform other obligations under the tariff), describe the cure period associated with an event of default, and describe the actions to be taken in the event of default and/or detail each Petitioners' remedies—which may include, among other things, termination of services and/or agreements, initiation of debt collection procedures and levying financial penalties.[223] As detailed above, in the event that the remedies outlined in each Petitioner's governing documents are insufficient to timely cure a default, Petitioners have the right to socialize losses from the default among other market participants by, for example, “short-paying” such other participants.[224]

b. Setoff

Generally speaking, it is a well-established tenet of clearing that a DCO acts as the buyer to every seller and as the seller to every buyer, thereby substituting the DCO's credit for bilateral counter-party risk. As such, when a DCO is involved, there is little question as to the identity of a counterparty to a given transaction. However, because ISOs and RTOs can act as agents for their participants, there could be ambiguity as to the identity of a counterparty to a given transaction. As a result, in the event of a bankruptcy of a market participant and in the event of a lack of the mutuality of obligation required by the Bankruptcy Code,[225] an ISO or RTO may be liable to pay a bankrupt market participant for transactions in which that participant is owed funds, without the ability to offset amounts owed by that participant with respect to other transactions. Stated differently, although the defaulting market participant may owe money to the ISO or RTO, if the ISO or RTO also owes money to such participant, the ISO or RTO may be required to pay the defaulting participant the full amount owed without being able to offset the amounts owed by that participant to the ISO or RTO, which latter amounts may be relegated to claims in the bankruptcy proceedings. As more fully described in section V.D.4.g., the requirement that Petitioners provide memoranda or opinions of counsel as discussed therein is intended to address this issue.

The foregoing arrangements appear congruent to, and to accomplish sufficiently, the regulatory objectives of DCO Core Principle G in the context of Petitioners' activities with respect to the Transactions. The Commission seeks comment with respect to this preliminary conclusion.

8. Core Principle H: Rule Enforcement

Core Principle H requires a DCO to (1) maintain adequate arrangements and resources for the effective monitoring and enforcement of compliance with its rules and for resolution of disputes, (2) have the authority and ability to discipline, limit, suspend, or terminate a clearing member's activities for violations of those rules, and (3) report to the Commission regarding rule enforcement activities and sanctions imposed against members and participants.[226]

Each Petitioner represents that it maintains tariffs or procedures or is subject to a regulatory framework that accomplishes the regulatory goals of DCO Core Principle H. Petitioners have, e.g., the power to take a range of actions against participants that fail to pay, pay late, or fail to post financial security. [227]

Based on Petitioners' representations, it appears that these practices are congruent with, and sufficiently accomplish, the regulatory objectives of DCO Core Principle H in the context of Petitioners' activities with respect to the Transactions. The Commission seeks comment with respect to this preliminary conclusion.

9. DCO Core Principle I: System Safeguards

Core Principle I requires a DCO to demonstrate that: (1) It has established and will maintain a program of oversight and risk analysis to ensure that its automated systems function properly and have adequate capacity and security, and (2) it has established and will maintain emergency procedures and a plan for disaster recovery and will periodically test backup facilities to ensure daily processing, clearing and settlement of transactions.[228] Core Principle I also requires that a DCO establish and maintain emergency procedures, backup facilities, and a plan for disaster recovery that allows for the timely recovery and resumption of the DCO's operations and the fulfillment of each of its obligations and responsibilities.[229]

Petitioners represent that they have policies and procedures that accomplish the regulatory goals of DCO Core Principle I,[230] albeit in a manner that is somewhat different than the way in which a DCO complies with DCO Core Principle I. This is because Petitioners are also responsible for managing power reliably and, thus, require additional operational safeguards to specifically address that function. For example, NYISO is subject to reliability rules established by the New York State Reliability Council, Northeast Power Coordinating Council, and the North American Electric Reliability Corporation.[231] In order to comply with these rules, NYISO has procedures in place to address emergency situations and maintains an alternate control center and back-up computer systems and data centers at a separate location.[232] NYISO also performs internal and external audits to ensure its internal controls, procedures, and business processes comply with accepted standards.[233] The other Petitioners represent that they have similar procedures and practices such as, computer back-up systems, operate multiple control and data centers, dedicate resources to internal audit and security teams, and maintain disaster recovery plans designed to address operational, physical, and cyber security events.[234]

Based on Petitioners' representations, it appears that these system safeguard practices are congruent with, and accomplish sufficiently, the regulatory objectives of DCO Core Principle I in the context of Petitioners' activities with respect to the Transactions. The Commission seeks comment with respect to this preliminary conclusion.

10. DCO Core Principle J: Reporting

Core Principle J requires a DCO to provide to the Commission all information that the Commission determines to be necessary to conduct oversight of the DCO.[235] With the exception of ERCOT, Petitioners represent that, pursuant to their Tariffs and other FERC orders, FERC has access to the information that it would need to oversee the Petitioners.[236] With respect to ERCOT, ERCOT represents that the PURA and PUCT Substantive Rules require it to provide information to the PUCT on request.[237] ERCOT also represents that its Bylaws require ERCOT corporate members to provide information to ERCOT.[238] In addition, according to ERCOT, the ERCOT Protocols require ERCOT to manage confidential information, but enable ERCOT to release confidential information to government officials if required by law, regulation or order.[239] As noted above, the Commission is proposing to condition this exemptive order on the completion of an appropriate information sharing agreement between the Commission and PUCT.

Based on the foregoing, including Petitioners' representations, it appears that these practices are congruent with, and sufficiently accomplish, the regulatory objectives of Core Principle J in the context of Petitioners' activities with respect to the Transactions. The Commission seeks comment with respect to this preliminary conclusion.

11. Core Principle K: Recordkeeping

Core Principle K requires a DCO to maintain records of all activities related to its business as a DCO in a form and manner acceptable to the Commission for a period of not less than five years.[240]

Petitioners represent that their practices satisfy the regulatory goals of DCO Core Principle K because they have adequate recordkeeping requirements or systems.[241] In addition, Petitioners represent that FERC has comprehensive recordkeeping regulations that cover, among other things, protection and storage of records, record storage media, destruction of records, and premature destruction or loss of records.[242] The record retention requirements for accounting records are, in the main, at or in excess of five years.[243] In addition, ERCOT, which is not subject to FERC jurisdiction, represents that it has also adopted specific books and records requirements that accomplish the regulatory goals of DCO Core Principle K. Specifically, ERCOT represents that it has specific record retention rules established in the EROCT Protocols and is required to retain market accounting information for a period of seven years.[244]

Based on these regulations and Petitioners' representations, it appears that these practices are congruent with, and sufficiently accomplish, the regulatory objectives of DCO Core Principle K in the context of Petitioners' activities with respect to the Transactions. The Commission seeks comment with respect to this preliminary conclusion.

12. DCO Core Principle L: Public Information

Core Principle L requires a DCO to make information concerning the rules and operating procedures governing its clearing and settlement systems (including default procedures) available to market participants.[245] Core Principle L also requires a DCO to provide market participants with sufficient information to enable them to identify and evaluate accurately the risks and costs associated with using the DCO's services, and to disclose publicly and to the Commission information concerning: (1) The terms and conditions of each contract, agreement, and transaction cleared and settled by the DCO; (2) the fees that the DCO charges its members and participants; (3) the DCO's margin-setting methodology, and the size and composition of its financial resources package; (4) daily settlement prices, volume, and open interest for each contract the DCO settles or clears; and (5) any other matter relevant to participation in the DCO's settlement and clearing activities.[246]

Each Petitioner represents that it makes its tariff or related governing documents publicly available on its Web site, which, in turn, allows market participants (and the public) to access its rules and procedures regarding, among other things, participant and product eligibility requirements, risk management methodologies, settlement procedures, and other information that may impact prices, such as transmission system models, reserved transmission capacity, and similar information.[247]

Based on Petitioners' representations, it appears that these practices are congruent with, and sufficiently accomplish, the regulatory objectives of DCO Core Principle L in the context of Petitioners' activities with respect to the Transactions. The Commission seeks comment with respect to this preliminary conclusion.

13. DCO Core Principle M: Information Sharing

Core Principle M requires a DCO to enter into and abide by the terms of all appropriate and applicable domestic and international information-sharing agreements, and use relevant information obtained from the agreements in carrying out the DCO's risk management program.[248]

Petitioners represent that they have policies and procedures that allow them to share information with and receive information from other entities as necessary to carry out their risk management functions.[249] For example, ISO NE represents that its Information Policy sets out rules for sharing information with participants, FERC, and other Petitioners.[250] Similarly, the NYISO represents that its tariff provides for information sharing with other ISOs and RTOs.[251] ERCOT represents that it is likewise subject to a comprehensive set of rules under the PURA, PUCT Rules, and the ERCOT Protocols that address information exchange obligations between ERCOT, the ERCOT Independent Market Monitor, ERCOT market participants, and the PUCT.[252] MISO, PJM, and CAISO all claim to have similar information sharing policies and procedures—although, the entities with which each ISO/RTO shares information do vary.[253]

Based on the foregoing and Petitioners' representations, it appears that these practices are congruent with, and sufficiently accomplish, the regulatory objectives of Core Principle M in the context of Petitioners' activities with respect to the Transactions. The Commission seeks comment with respect to this preliminary conclusion.

14. DCO Core Principle N: Antitrust

Core Principle N requires a DCO to avoid, unless necessary or appropriate to achieve the purposes of the CEA, adopting any rule or taking any action that results in any unreasonable restraint of trade, or imposing any material anticompetitive burden.[254]

As discussed above, the formation of the Petitioners (except for ERCOT) was encouraged by FERC (pursuant to FERC Order Nos. 888 and 2000) in order to foster greater competition in the power generation sectors by allowing open access to transmission lines.[255] In addition, Petitioners represent that they are subject to continued oversight by FERC, PUCT or their market monitors, as appropriate, which oversight could detect activities such as undue concentrations or market power, discriminatory treatment of market participants or other anticompetitive behavior.[256]

Based on Petitioners' representations, it appears that Petitioners' existence and practices are congruent with, and sufficiently accomplish, the regulatory objectives of Core Principle N. The Commission seeks comment with respect to this preliminary conclusion.

15. DCO Core Principle O: Governance and Fitness Standards

Core Principle O requires a DCO to establish governance arrangements that are transparent to fulfill public interest requirements and to permit the consideration of the views of owners and participants.[257] A DCO must also establish and enforce appropriate fitness standards for directors, members of any disciplinary committee, members of the DCO, any other individual or entity with direct access to the settlement or clearing activities of the DCO, and any party affiliated with any of the foregoing individuals or entities.[258]

Petitioners represent that their tariffs, organizational documents, and applicable state law set forth specific governance standards that are consistent with the regulatory goals which address, for example, director independence and fitness requirements.[259] In addition, Petitioners assert that FERC Order Nos. 888 and 2000 set out certain minimum governance structures for ISOs and RTOs. Petitioners state that Order No. 888 requires the following: an ISO's governance should be structured in a fair and non-discriminatory manner; an ISO and its employees should have no financial interest in the economic performance of any power market participant; and an ISO should adopt and enforce strict conflict of interest standards.[260] Petitioners assert that Order No. 2000 likewise identified minimum characteristics that RTOs must exhibit, including, independence from all market participants.[261] Similarly, Petitioners represent that PURA mandates ERCOT to include unaffiliated directors and market segment representation in its governance structure.[262]

Based on Petitioners' representations, it appears that Petitioner's governance structures are congruent with, and sufficiently accomplish, the regulatory objectives of DCO Core Principle O in the context of Petitioners' activities with respect to the Transactions. The Commission seeks comment with respect to this preliminary conclusion.

16. DCO Core Principle P: Conflicts of Interest

Pursuant to DCO Core Principle P, each DCO must establish and enforce rules to minimize conflicts of interest in the decision-making process of the DCO.[263] In addition, each DCO must establish a process for resolving conflicts of interest.[264]

Each Petitioner represents that it has established a conflict of interest policy in a Code of Conduct or other corporate document that requires board members and employees to, among other things, avoid activities that are contrary to the interests of the Petitioner.[265] In addition, CAISO represents that Order No. 888 requires ISOs to implement strict conflict of interest policies.[266] Similarly, ERCOT asserts that the PUCT Substantive Rules require it to adopt policies to mitigate conflicts of interest.[267]

Based upon Petitioners' representations, it appears that the conflict of interest policies Petitioners have adopted and that the requirements Petitioners are subject to are congruent with, and sufficiently accomplish, the regulatory objectives of DCO Core Principle P in the context of Petitioners' activities with respect to the Transactions. The Commission seeks comment with respect to this preliminary conclusion.

17. DCO Core Principle Q: Composition of Governing Boards

DCO Core Principle Q provides that each DCO shall ensure that the composition of the governing board or committee of the derivatives clearing organization includes market participants.[268]

ERCOT represents that its governing board includes representatives from the market,[269] CAISO, on the other hand, asserts that its board composition is mandated by California statute, wherein members are appointed by the Governor of California and confirmed by the California senate.[270] ISO NE and MISO assert that they have active market participants who are involved in the nomination and selection of Board members, while NYISO asserts that its market participants provide input and feedback through market participant committees, and other subcommittees and working groups, and PJM has a Members Committee that elects the members of the PJM Board.[271] FERC regulations require that an RTO “must have a decision making process that is independent of control by any market participant or class of participants.” [272] However, FERC also requires that each ISO and RTO “adopt business practices and procedures that achieve Commission-approved independent system operator and regional transmission organization board of directors' responsiveness to customers and other stakeholders and satisfy [specified] criteria.” [273]

Based on Petitioner's representations, and the regulations and supervision of FERC, it appears that these practices are congruent with, and sufficiently accomplish, the regulatory objectives of DCO Core Principle Q in the context of Petitioners' activities with respect to the Transactions. The Commission seeks comment with respect to this preliminary conclusion.

18. DCO Core Principle R: Legal Risk

Core Principle R requires a DCO to have a well-founded, transparent, and enforceable legal framework for each aspect of its activities.[274]

Petitioners assert that they operate under a transparent and comprehensive legal framework that is grounded in the Federal Power Act or the Texas Public Utility Regulatory Act, as applicable, and administered by FERC or the PUCT, as applicable.[275] Indeed, Petitioners assert that they are subject to FERC or PUCT orders rules and regulations and that each Petitioner operates pursuant to a tariff that has been reviewed and approved by FERC or the PUCT, as applicable.[276] Moreover, with respect to an area of particular concern (eligibility for setoff in bankruptcy), the CFTC is requiring independent confirmation.[277]

Based on Petitioners' representations, it appears that this framework is congruent with, and sufficiently accomplishes, the regulatory objectives of Core Principle R in the context of Petitioners' activities with respect to the Transactions. The Commission seeks comment with respect to this preliminary conclusion.

E. SEF Core Principles

1. SEF Core Principle 1: Compliance With Core Principles

SEF Core Principle 1 requires a SEF to comply with the Core Principles described in part 37 of the Commission's Regulations.[278] As demonstrated by the following analysis, the Commission has made a preliminary determination that 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 SEF core principle. The Commission requests comment with respect to this preliminary determination.

2. SEF Core Principle 2: Compliance With Rules

SEF Core Principle 2 requires a SEF to establish and enforce compliance with any rule of the SEF.[279] A SEF is also required to (1) establish and enforce rules with respect to trading, trade processing, and participation that will deter market abuses and (2) have the capacity to detect, investigate and enforce those rules, including a means to (i) provide market participants with impartial access to the market, and (ii) capture information that may be used in establishing whether rule violations have occurred.[280]

Petitioners represent that they have transparent rules for their market, including rules that govern market abuses and compliance enforcement.[281] For instance, the independent market monitor established by statute for the ERCOT region oversees market behavior and reports any market compliance issues to the state regulator.[282] If a market participant violates ERCOT rules, depending on the nature of the offense, ERCOT and/or the state regulator may take appropriate action against the party, including, but not limited to, terminating, expelling, suspending, or sanctioning a member.[283] The other Petitioners also represent that they have enforcement mechanisms that allow the Petitioners to, among other things, monitor their markets, investigate suspected tariff violations, take action against violators (including assessing fines or suspending or terminating a market participant's participation in market activities), and refer potential violations to FERC.[284]

Based on the foregoing, it appears that the Petitioners' practices are consistent with, and sufficiently accomplish, the regulatory goals of SEF Core Principle 2 in the context of Petitioners' activities with respect to the Transactions. The Commission requests comment with respect to this preliminary determination.

3. SEF Core Principle 3: Swaps Not Readily Susceptible to Manipulation

SEF Core Principle 3 requires a SEF submitting a contract to the Commission for certification or approval to demonstrate that the swap is not readily susceptible to manipulation.[285]

a. Energy Transactions

Petitioners define Energy Transactions to include both physically-delivered as well as cash-settled contracts.[286] For purposes of this Proposed Exemption, the Commission limits the analysis to Energy Transactions that are cash-settled.

Petitioners have represented to the Commission that market participants use the cash-settled Energy Transactions to arbitrage between the Day-Ahead and Real-Time markets.[287] The result is that prices between the Day-Ahead and Real-Time markets converge and reduce the price volatility normally found in electricity markets.[288] Indeed, the contracts were created with this very purpose in mind.[289]

The Commission understands that MMUs operated by each of the Petitioners have been organized in such a way that both the Real-Time and Day-Ahead markets are monitored to identify suspicious trading activity.[290] In the event the MMUs identify suspicious trading activity, FERC, or PUCT in the case of ERCOT, is notified so that further investigation may be done. An example of such suspicious trading activity would involve a market participant engaging in Energy Transactions that repeatedly incur a loss.[291] Repeated losses in Energy Transactions would indicate that a market participant is sustaining losses to improve another position. For example, in the event a market participant tried to manipulate the price of electricity in the Day-Ahead or Real-Time markets to improve a different position, such as an FTR, they would have to submit bids that drove up the price of electricity for that specific node. In order to do this, however, the participant would have to submit a large dollar amount of offers at an inflated price. The Commission believes that this type of trading activity should be detectable by the MMUs. In addition to being difficult to effectuate simply because of the financial resources required, the Commission believes that any such activity should be apparent to not only MMUs using their ordinary oversight tools, but to market participants, who should have a self-interest in reporting such activity to the MMUs. Notably, such manipulative schemes have been identified and prosecuted by FERC in the past.[292]

Petitioners represent that they have adequate staff and IT resources to conduct market surveillance.[293] Each Petitioner follows a similar market design which allows for price discovery at thousands of nodes and paths in short time intervals (every five to fifteen minutes) in both the Real-Time and Day-Ahead markets.[294] The MMUs look for manipulative behavior and market power, as well as market flaws (such as persistent non-convergence of Day-Ahead and Real-Time prices), which are fed back into a stakeholder process for changing the market structure and rules.[295]

Based on the Petitioners' representations regarding the surveillance carried out by the MMUs for each Petitioner and the method by which the Day-Ahead and Real-Time auctions are conducted, it appears that Petitioners' policies and procedures to mitigate the susceptibility of Energy Transactions to manipulation are congruent with, and sufficiently accomplish, the regulatory objectives of SEF Core Principle 3 in the context of Petitioners' activities with respect to the Energy Transactions. The Commission seeks comment with respect to this preliminary conclusion.

b. Financial Transmission Rights (“FTRs”)

Based upon the Petitioners' representations, the Commission understands FTRs to be cash-settled contracts that entitle the holder to a payment equal to the difference in the price of electricity between two specific nodes.[296] The difference in price between the two nodes represents the settlement price. The price at each node is established through auctions conducted on the Day-Ahead market of each Petitioner.[297] As discussed above, the Commission has made a preliminary determination that the Real-Time and Day-Ahead markets on Petitioners' platforms appear to be consistent with SEF Core Principle 3.

As previously discussed, both the Petitioners and their respective MMUs conduct market surveillance of both the Real-Time and Day-Ahead markets to identify manipulation of the price of electricity. In the event unusual trading activity is detected by the Petitioners' MMUs, the MMUs will immediately contact FERC, or PUCT in the case of ERCOT, so that an investigation into the unusual activity may begin.[298] Although the price of FTRs may be altered by the manipulation of the Real-Time or Day-Ahead markets, FERC requires that the Petitioners have systems to monitor for such activity.

The Commission believes that the Petitioners' policies and procedures should mitigate the susceptibility of FTRs to manipulation and that they are congruent with, and sufficiently accomplish, the regulatory objectives of SEF Core Principle 3 in the context of Petitioners' activities with respect to FTRs. The Commission seeks comment with respect to this preliminary conclusion.

In addition to the Petitioners' policies and procedures for the detection of manipulative behavior in connection with FTRs, the Commission notes that since an FTR holder is entitled to a payment based on the price difference between two nodes, and not the physical delivery of electricity, it may be the case that FTRs are difficult to use to manipulate the price of electricity. For instance, the size of a participant's FTR position should not affect the price of electricity established on the Petitioners' Real-Time and Day-Ahead markets and holding an FTR does not provide a means to limit the deliverable supply of electricity. The Commission seeks comment on this evaluation and whether it should be considered in analyzing FTRs under SEF Core Principle 3.

c. Capacity and Reserve Transactions

Both Capacity and Reserve Transactions are entered into pursuant to auctions carried out by each of the Petitioners.[299] However, unlike the auctions for the Real-Time and Day-Ahead markets, the auctions for capacity and reserve transactions simply allow each Petitioner to accept bids submitted by market participants that have the ability to inject electricity into the Petitioner's electricity transmission system.[300]

The Commission notes that the Petitioners would apply the same oversight policies and procedures to Capacity and Reserve Transactions that they apply to Energy Transactions and FTRs. The Commission believes that these measures appear to be consistent with, and to accomplish sufficiently, the regulatory objectives of SEF Core Principle 3 in the context of Petitioners' activities with respect to Capacity and Reserve Transactions. The Commission seeks comment with respect to this preliminary conclusion.

The Commission also seeks comment on whether the auction procedures used in connection with Capacity and Reserve Transactions could reduce the likelihood for manipulation of such agreements due to the fact that the Petitioners themselves are the only possible counterparty during each auction. For example, when CAISO conducts an auction for Generation Capacity, it is the only party that would enter into the agreement with a CAISO market participant capable of providing the contracted for electricity. CAISO would then call upon the Capacity and Reserve Transaction counterparties to inject electricity into the system when the technical requirements of operating the transmission system deem injection necessary. Accordingly, Capacity and Reserve Transactions seem to be distinguishable from FTRs or Energy Transactions in that they are used exclusively for operational maintenance of the electric transmission system, and not as a means of reducing exposure to price volatility, arbitrage or price discovery. The Commission seeks comment on this analysis of Capacity and Reserve Transactions and whether it should be considered in the Commission's review of these instruments under SEF Core Principle 3.

4. SEF Core Principle 4: Monitoring of Trading and Trade Processing

SEF Core Principle 4 requires a SEF to establish and enforce rules or terms and conditions defining trading procedures to be used in entering and executing orders traded on or through the SEF and procedures for the processing of swaps on or through the SEF.[301] SEFs are also required to establish a system to monitor trading in swaps to prevent manipulation, price distortion and disruptions of the delivery or cash settlement process through surveillance, compliance and disciplinary practices and procedures. The main goal of this Core Principle is to monitor trading activity to detect or deter market participants from manipulating the price or deliverable supply of a commodity.

a. Energy Transactions

Generally, the Petitioners have tariffs in place that list how Energy Transactions are to be entered into the trading platform.[302] Using these procedures, MMUs are able to track the Energy Transactions submitted by market participants and identify trading activity that could be manipulative. As a result, Petitioners' policies and procedures regarding monitoring of trading and trade processing appear to be consistent with, and to accomplish sufficiently, the regulatory objectives of SEF Core Principle 4 in the context of Petitioners' activities with respect to Energy Transactions. The Commission seeks comment with respect to this preliminary conclusion.

b. FTRs

The process by which the FTR allocation and auction takes place provides the Petitioners with a basic system that allows the Petitioners to determine which market participants hold FTRs. According to the Petitioners' tariffs, LSEs applying for FTRs during the allocation phase must first establish that they are in fact exposed to load levels for the transmission lines on which they will transmit electricity.[303] Once an LSE has demonstrated such exposure, they will be allowed to participate in the FTR allocation. The FTRs are allocated to each LSE in direct relation to the level of exposure to which the LSEs are subject.[304] This process of determining congestion exposure and allocating FTRs in relation to that exposure ensures that Petitioners will have a record of the number of FTRs held by each member.

During the auction and secondary market phases, the Petitioners also have systems in place to track which participants hold FTRs. During the auction phase, any credit-worthy member of the RTO or ISO may bid on FTRs. Since the auctions are conducted on the Petitioners' platforms, they will have records of which market participants hold FTRs after the auctions. Once an auction is complete, credit-worthy members may then engage in bilateral transactions to trade FTRs. Again, Petitioners have implemented systems to track these bilateral transactions between FTR holders. Once a bilateral transaction is reported, the Petitioner then performs a credit check to ensure that the new owner of the FTR has the financial capability to assume the risk posed by ownership of the FTR.[305] The Petitioners do not perform an analysis to determine whether a member is obtaining a large position in the secondary FTR market. The Petitioners only identify which members hold FTRs in the secondary market.

Based on the foregoing representations, it appears that the Petitioners' policies and procedures regarding the monitoring of trading and trade processing are consistent with, and to accomplish sufficiently, the regulatory objectives of SEF Core Principle 4 in the context of Petitioners' activities with respect to FTRs. The Commission seeks comment with respect to this preliminary conclusion.

c. Capacity and Reserve Transactions

As discussed above, the auction process used for Capacity and Reserve Transactions differs from the process used in the Real-Time and Day-Ahead markets. Furthermore, Capacity and Reserve Transactions are not used to limit exposure to price volatility, discover prices or engage in arbitrage. The transactions are predominantly bilateral agreements between each Petitioner and certain of that Petitioner's market participants for the provision of electricity in order to meet the technical requirements necessary to operate the electric transmission system. The contracts are not readily susceptible to manipulation and there is no market trading that must be monitored to prevent manipulation or congestion of the physical delivery market. As a result, the Petitioners' policies and procedures regarding the monitoring of trading and trade processing appear to be consistent with, and to accomplish sufficiently, the regulatory objectives of SEF Core Principle 4 in the context of Petitioners' activities with respect to Capacity and Reserve Transactions. The Commission seeks comment with respect to this preliminary conclusion.

5. SEF Core Principle 5: Ability To Obtain Information

SEF Core Principle 5 requires a SEF to establish and enforce rules that will allow it to obtain any necessary information to perform the functions described in section 733 of the Dodd-Frank Act, provide information to the Commission upon request, and have the capacity to carry-out such international information-sharing agreements as the Commission may require.[306] As discussed above,[307] each Petitioner represents that it has rules in place that require market participants to submit information to Petitioners upon request so that Petitioners may conduct investigations and provide or give access to such information to their market monitors and FERC or PUCT, as applicable.[308] On the basis of these representations, it appears that Petitioners' practices are consistent with, and sufficiently accomplish, the regulatory goals of SEF Core Principle 5. The Commission seeks comment with respect to this preliminary determination.

6. SEF Core Principle 6: Position Limits or Accountability

SEF Core Principle 6 requires SEFs that are trading facilities, as that term is defined in CEA section 1a(51), to establish position limits or position accountability for speculators, as is necessary and appropriate, for each swap traded on the SEF in order to prevent or reduce the potential threat of market manipulation or congestion, especially during trading in the delivery month.[309] While the markets administered by Petitioners are subject to MMUs (as discussed above in section IV.C.), Petitioners do not have position limits or position accountability thresholds for speculators in order to reduce the potential threat of market manipulation or congestion. The Commission specifically requests comment as to whether the lack of position limits or position accountability thresholds for speculators in Petitioners' markets, given the nature of their markets and market participants, and the other regulatory protections applicable to these markets as described herein, would prevent the Commission from determining that the Proposed Exemption is consistent with the public interest and the purposes of the CEA.

7. SEF Core Principle 7: Financial Integrity of Transactions

SEF Core Principle 7 requires a SEF to establish and enforce rules and procedures for ensuring the financial integrity of swaps entered on or through the facilities of the SEF, including the clearance and settlement of swaps pursuant to section 2(h)(1) of the CEA.

a. Risk Management Requirements and Credit Policies

Petitioners represent that they ensure the financial integrity of transactions that are entered on or through their markets through the risk management requirements and credit policies that apply to their market participants.[310] In addition to minimum capitalization requirements, Petitioners represent that they all have in place, or are in the process of implementing, risk management policies and procedures and internal controls appropriate to their trading activities in the RTO and ISO markets in which they participate.[311] Petitioners further represent that they require a responsible officer of the market participant to certify, on an annual basis, that the market participant has in place risk management policies, procedures and internal controls appropriate to its trading activities.[312] Moreover, several Petitioners represent that they have proposed verification programs that confirm that participants who pose significant risks to the markets in which they participate have in place adequate risk management policies and internal controls.[313]

In terms of credit policies, Petitioners represent that they have established “comprehensive and integrated” credit policies to manage credit risk and protect the financial integrity of transactions with market participants.[314] In addition, Petitioners represent that FERC Order 741 placed additional risk management and credit requirements on RTOs and ISOs.[315]

b. Minimum Financial Standards and Ongoing Monitoring for Compliance

In addition, based on Petitioners' representations, it appears that Petitioners' policies and procedures include minimum financial standards [316] and creditworthiness standards [317] for their market participants.[318] Moreover, Petitioners represent that their policies and procedures, require Petitioners to monitor, on an ongoing basis, their market participants for compliance with such standards.[319]

c. Establishment of a Central Counterparty

As discussed in section V.C. above, FERC regulation 35.47(d) requires RTOs and ISOs to (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.[320] Petitioners have represented that they either are, or plan on becoming, central counterparties.[321]

As described in section V.D.4.g. above, the Commission is proposing to require that each Petitioner submit a well-reasoned legal memorandum from, or a legal opinion of, outside counsel that, in the Commission's sole discretion, provides the Commission with adequate assurance that the approach selected by the Petitioner will in fact provide the Petitioner with set-off rights in a bankruptcy proceeding. In addition, the Commission is requesting comment on whether ERCOT should be obligated to comply with the requirements of FERC regulation 35.47(d).

d. Conclusion

Issues regarding risk management requirements, financial standards, and the use of a central counterparty are also addressed within the context of DCO Core Principle D. The Commission's preliminary conclusion that Petitioners policies and procedures are congruent with, and sufficiently accomplish, the regulatory objectives of Core Principle D in the context of the Petitioners' activities with respect to the Transactions is relevant in considering SEF Core Principle 7.

Based on the foregoing analysis, including the representations of the Petitioners, Petitioners' policies and procedures appear to be consistent with, and to accomplish sufficiently, the regulatory objectives of SEF Core Principle 7 in the context of Petitioners' activities with respect to the Transactions. The Commission seeks comment with respect to this preliminary conclusion.

8. SEF Core Principle 8: Emergency Authority

SEF Core Principle 8 requires that SEFs adopt rules to provide for the exercise of emergency authority.[322] A SEF should have procedures and guidelines for decision-making and implementation of emergency intervention in the market. A SEF should have the authority to perform various actions, including without limitation: liquidating or transferring open positions in the market, suspending or curtailing trading in any swap, and taking such market actions as the Commission may direct. In addition, SEFs must provide prompt notification and explanation to the Commission of the exercise of emergency authority.[323]

Petitioners represent that their Tariffs generally provide a wide range of authorities to address emergency situations.[324] Certain Petitioners have the ability to close out and liquidate all of a market participant's current and forward FTR positions if the market participant no longer meets creditworthiness requirements, or fails to make timely payment when due, in each case following any opportunity given to cure the deficiency.[325] Other Petitioners have the authority to suspend trading in their markets.[326]

Just as the SEFs have rules in place that require them to take emergency actions to protect the markets by “including imposing or modifying position limits, imposing or modifying price limits, imposing or modifying intraday market restrictions, imposing special margin requirements, ordering the liquidation or transfer of open positions in any contract, ordering the fixing of a settlement price,” one Petitioner represents that it may take actions to protect its markets by postponing the closure of affected markets, removing bids that have previously resulted in market disruptions, setting an administrative price to settle metered supply, or demanding, suspending or limiting the ability of scheduling coordinators to submit Energy Transactions.[327]

Based on the foregoing representations, it appears that Petitioners' policies and procedures regarding the exercise of emergency authority are congruent with, and sufficiently accomplish, the regulatory objectives of SEF Core Principle 8 in the context of Petitioners' activities with respect to the Transactions. The Commission seeks comment with respect to this preliminary conclusion.

9. SEF Core Principle 9: Timely Publication of Trading Information

SEF Core Principle 9 requires a SEF to make public timely information on price, trading volume, and other data on swaps to the extent prescribed by the Commission.[328] In addition, SEFs are required to have the capacity to electronically capture and transmit trade information with respect to transactions executed on the SEF.[329]

Petitioners represent that their Tariffs generally require the timely publication of trading information.[330] Petitioners regulated by FERC also assert that they are able to publicly release market operations and grid management information using their Open Access Same-Time Information System (OASIS) program.[331] This system transmits information which includes market results, the market clearing price and volume.[332] Similarly, ERCOT's protocols require them to disseminate information which relates to market operations, prices, availability of services and the terms and conditions of the FTRs.[333]

Based on the foregoing representations, it appears that Petitioners' policies and procedures regarding the publication of trading information are congruent with, and sufficiently accomplish, the regulatory objectives of SEF Core Principle 9 in the context of Petitioners' activities with respect to the Transactions. The Commission seeks comment with respect to this preliminary conclusion.

10. SEF Core Principle 10: Recordkeeping and Reporting

SEF Core Principle 10 requires a SEF to maintain records of all activity relating to the business of the SEF, report such information to the Commission and to keep swaps information open to inspection by the Commission.[334] Petitioners represent that their Tariffs require their market participants to provide Petitioners with information on a regular and ad hoc basis.[335] Petitioners further represent that they are required to comply with FERC or PUCT regulations, as applicable, regarding the maintenance of information by public utilities.[336]

Based on the Petitioners representations and the discussion regarding DCO Core Principles J and K above,[337] it appears that these practices are congruent with, and sufficiently accomplish the regulatory objectives of SEF Core Principle 10 in the context of Petitioners' activities with respect to the Transactions. The Commission seeks comment with respect to this preliminary conclusion.

11. SEF Core Principle 11: Antitrust Considerations

SEF Core Principle 11 prevents a SEF from adopting any rule or taking any action that results in any unreasonable restraint of trade, or imposes any material anticompetitive burden, unless necessary or appropriate to achieve the purposes of the Act.[338] As discussed above, FERC established the RTO/ISO system to promote competition in the electricity market.[339] Petitioners represent that their rates, terms and conditions of service are subject to the oversight, review and acceptance of FERC or PUCT, as applicable.[340] Petitioners further represent that FERC or PUCT and their MMUs review trading activity to identify anticompetitive behavior.[341]

Based on Petitioners' representations and the discussion of DCO Core Principle N above,[342] it appears that Petitioners' existence and practices are congruent with, and sufficiently accomplish, the regulatory objectives of SEF Core Principle 11 in the context of Petitioners' activities with respect to the Transactions. The Commission seeks comment on this preliminary conclusion.

12. SEF Core Principle 12: Conflicts of Interest

SEF Core Principle 12 requires a SEF to establish and enforce rules to minimize conflicts of interest and establish a process for resolving conflicts of interest.[343] As discussed above, FERC Order No. 888 requires ISOs to adopt or enforce strict conflict of interest policies.[344] Similarly, FERC Order No. 2000 requires RTOs to be independent of any market participant, and to include in their demonstration of independence that the RTO, its employees, and any non-stakeholder directors do not have financial interests in any market participant.[345] Each Petitioner represents that it has either established codes of conduct, which include conflict of interest rules, for employees and members of the Board of Directors [346] or implemented specific policies and procedures to mitigate conflicts of interest.[347] Based on Petitioners' representations and the discussion of DCO Core Principle P above,[348] it appears that Petitioners' conflict of interest policies and the requirements to which the Petitioners are subject are congruent with, and sufficiently accomplish, the regulatory objectives of SEF Core Principle 12 in the context of Petitioners' activities with respect to the Transactions. The Commission seeks comment with respect to this preliminary conclusion.

13. SEF Core Principle 13: Financial Resources

SEF Core Principle 13 requires a SEF to have adequate financial, operational and managerial resources to discharge each responsibility of the SEF.[349] In addition, the financial resources of a SEF are considered to be adequate if the value of the financial resources exceeds the total amount that would enable the SEF to cover the operating costs of the SEF for a 1-year period, as calculated on a rolling basis.[350]

Petitioners represent that they have rules in place that allow them to collect revenue from market participants sufficient for each of their operations.[351] Petitioners further represent to have adequate managerial resources to operate their systems.[352] As discussed above, FERC Order No. 888 requires RTOs to have appropriate incentives for efficient management and administration.[353] Each Petitioner represents that it has sufficient staff necessary for its operations.[354]

Based on Petitioners' representations and the discussion regarding DCO Core Principle B above,[355] it appears that Petitioners' practices are congruent with, and sufficiently accomplish, the regulatory objectives of SEF Core Principle 13 in the context of Petitioners' activities with respect to the Transactions. The Commission seeks comment with respect to this preliminary conclusion.

14. SEF Core Principle 14: System Safeguards

SEF Core Principle 14 requires a SEF to establish and maintain a program of risk analysis and oversight to identify and minimize sources of operational risk, through the development of appropriate controls and procedures, and automated systems, that are reliable and secure, and have adequate scalable capacity.[356] Moreover, a SEF must establish and maintain emergency procedures, backup facilities, and a plan for disaster recovery that allows for the timely recovery and resumption of operations, and the fulfillment of the responsibilities and obligations of the SEF.[357] The SEF must also conduct tests to verify that the backup resources of the SEF are sufficient to ensure continued order processing and trade matching, price reporting, market surveillance, and maintenance of a comprehensive and accurate audit trail.[358]

Petitioners represent that they have a program of risk analysis and oversight to identify and minimize sources of operational risk through the development of appropriate controls and procedures; reliable automated systems; and emergency procedures.[359] Indeed, Petitioners are responsible for managing power reliably and, thus, require additional operational safeguards to specifically address that function.[360]

Petitioners represent that they have computer systems that incorporate adequate business continuity and disaster recovery functionality.[361] Some Petitioners state that they maintain offsite backup computer systems fully able to operate in the event the primary system fails [362] whereas other Petitioners state that they operate two control centers and/or two data centers in which each center is functionally capable of operating as the primary center.[363] Some Petitioners further state that they conduct testing of emergency procedures and system components on a regular basis to ensure that mission critical processes and vital records are recoverable, as well as the readiness of backup facilities and personnel.[364]

Based on Petitioners' representations and the discussion regarding DCO Core Principle I above,[365] it appears that Petitioners' practices are congruent with, and sufficiently accomplish, the regulatory objectives of SEF Core Principle 14 in the context of Petitioners' activities with respect to the Transactions. The Commission seeks comment with respect to this preliminary conclusion.

15. SEF Core Principle 15: Designation of Chief Compliance Officer

SEF Core Principle 15 requires that a SEF designate an individual as Chief Compliance Officer, with specific delineated duties.[366] The Chief Compliance Officer for a SEF would be responsible for reporting to the board and ensuring that the SEF is in compliance with the SEF rules. Each Petitioner represents that it has a Chief Compliance Officer [367] or the functional equivalent of such a position.[368]

Based on the Petitioners' representations, it appears that Petitioners' practices are congruent with, and sufficiently accomplish, the regulatory objectives of SEF Core Principle 15 in the context of Petitioners' activities with respect to the Transactions. The Commission seeks comment with respect to this preliminary conclusion.

VIII. Proposed Exemption

A. Discussion of Proposed Exemption

Pursuant to the authority provided by section 4(c)(6) of the CEA,[369] in accordance with CEA sections 4(c)(1) and (2), and consistent with the Commission's determination that the statutory requirements for granting an exemption pursuant to section 4(c)(6) of the Act have been satisfied, the Commission is proposing to issue the exemption described in the Proposed Exemption set forth below. The Proposed Exemption would exempt, subject to the limitations and conditions contained therein, the purchase and sale of certain electricity-related products, including specifically-defined “financial transmission rights,” “energy transactions,” “forward capacity transactions,” and “reserve or regulation transactions,” from most provisions of the CEA. The Commission is proposing to explicitly exclude from the exemption relief the Commission's general anti-fraud, anti-manipulation and enforcement authority under the CEA including, but not limited to, 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 and any implementing regulations promulgated thereunder including, but not limited to Commission regulations 23.410(a) and (b), 32.4 [370] and part 180.[371] The preservation of the Commission's anti-fraud and anti-manipulation authority provided by these provisions generally is consistent with both the scope of the exemption requested in the Petition [372] and recent Commission practice.[373]

The particular categories of contracts, agreements and transactions to which the Proposed Exemption would apply correspond to the types of transactions for which relief was explicitly requested in the Petition.[374] Petitioners requested relief for four specific types of transactions and the Proposed Exemption would exempt those transactions. With respect to those transactions, the Petition also included the parenthetical “(including generation, demand response or convergence or virtual bids/transactions).” [375] The Commission notes that such transactions would be included within the scope of the exemption if they would qualify as the financial transmission rights, energy transactions, forward capacity transactions or reserve or regulation transactions for which relief is explicitly provided within the exemption. Petitioners also have requested relief for “the purchase and sale of a product or service that is directly related to, and a logical outgrowth of, any [of Petitioner's] core functions as an ISO/RTO * * * and all services related thereto.” [376] The Commission has determined that it would be inappropriate, and, accordingly, has declined to propose that the exemption be extended beyond the scope of the transactions that are specifically defined in the Proposed Exemption. As noted above, the authority to issue an exemption from the CEA provided by section 4(c) of the Act may not be automatically or mechanically exercised. Rather, the Commission is required to affirmatively determine, inter alia, that the exemption would be consistent with the public interest and the purposes of the Act.[377] With respect to the four groups of transactions explicitly detailed in the Proposed Exemption, the Commission's proposed finding that the Proposed Exemption would be in the public interest and would be consistent with the purposes of the CEA was grounded, in part, on certain transaction characteristics and market circumstances described in the Petition that may or may not be shared by other, as yet undefined, transactions engaged in by the Petitioners or other RTO or ISO market participants.[378] Similarly, unidentified transactions might include novel features or have market implications or risks that are not present in the specified transactions. Such elements may impact the Commission's required section CEA 4(c) public interest analysis or may warrant the attachment of additional or differing terms and conditions to any relief provided. Due to the potential for adverse consequences resulting from an exemption that includes transactions whose qualities and effect on the broader market cannot be fully appreciated absent further specification, it does not appear that the Commission can justify a conclusion that it would be in the public interest to provide an exemption of the full breadth requested. The Commission notes, however, that it has requested comment on whether the proposed scope of the exemption is sufficient to allow for innovation and, if not, how the scope could be expanded, without exempting products that may be substantially different from those reviewed by the Commission. The Commission also notes that it stands ready to review promptly any additional applications for an exemption pursuant to section 4(c)(6), in accordance with CEA sections 4(c)(1) and (2), of the CEA for other precisely defined products.[379]

The scope of the Proposed Exemption is limited by two additional factors. First, it is restricted to agreements, contracts or transactions where all parties thereto are either: (1) Entities described in section 4(c)(3)(A) through (J) of the CEA [380] or (2) “eligible contract participants,” as defined in section 1a(18) of the Act [381] or in Commission regulation 1.3(m).[382] Although Petitioners have requested an exemption pursuant to section 4(c)(6) of the CEA, any exemption pursuant to this subsection must be issued in “in accordance with” sections 4(c)(1) and 4(c)(2).[383] Section 4(c)(2) prohibits the Commission from issuing an exemption pursuant to section 4(c) unless the Commission determines that the agreement, contract or transaction “will be entered into solely between `appropriate persons.' ” Appropriate persons include those entities explicitly delineated in sections 4(c)(3)(A) through (J) of the Act as well as others that the Commission, under the discretionary authority provided by section 4(c)(3)(K), deems to be appropriate persons “in light of their financial or other qualifications, or the applicability of appropriate regulatory protections.” [384] As noted above, the Commission has proposed to determine that eligible contract participants, as defined in section 1a(18) of the Act or in Commission regulation 1.3(m), should be considered appropriate persons for purposes of the Proposed Exemption.[385] The Commission recognizes that the market participant eligibility standards of an individual RTO or ISO may not be coextensive with the criteria required by sections 4(c)(3)(A) through (J) or section 1a(18) of the Act and, therefore, there may be certain RTO or ISO participants engaging in transactions of the type described in the Proposed Exemption that would not qualify for the Proposed Exemption. In particular, the Commission is interested in considering 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). Accordingly, the Commission has requested comment on whether the Commission should enlarge the list of appropriate persons for purposes of the exemption to include other types of entities identified in the Petition that satisfy alternative criteria. Any request to include additional entities should be accompanied by a description of the financial or other qualifications of such entities or the available regulatory protections that would render them comparable to the appropriate persons and eligible contract participants delineated in the Act. The Commission also is interested in receiving comments addressing whether and how market participants who satisfy substitute qualifications would be capable of bearing the risks associated with the relevant markets.

In order to be eligible for the exemption that would be provided by the Proposed Exemption, the agreement, contract or transaction also must be offered or sold pursuant to the “tariff” of a “requesting party” and the tariff must have been approved or permitted to take effect by the PUCT (in the case of ERCOT) or by FERC (in the case of all other Petitioners). This requirement reflects the range of the Commission's authority as set forth in section 4(c)(6) [386] of the CEA and is consistent with the scope of the relief requested.[387] “Requesting Party” is defined to include the six Petitioners (i.e., CAISO, ERCOT, ISO NE., MISO, NYSO and PJM) and any of their respective successors in interest. To account for differences in terminology used by such entities and their respective regulators, the term “tariff” is defined to include a “tariff, rate schedule or protocol.”

Consistent with the range of the statutory authority explicitly provided by CEA section 4(c), the Proposed Exemption would extend the exemption to the agreements, contracts or transactions set forth therein and “any person or class of persons offering, entering into, rendering advice or rendering other services with respect to” such transactions. In addition, for as long as the Proposed Exemption would remain in effect, each of the six named Petitioners [388] would be able to avail themselves of the Proposed Exemption with respect to all four expressly-identified groups of products, regardless of whether or not the particular Petitioner offers the particular product at the present time. That is, a Petitioner would not be required to request future supplemental relief for a product that it does not currently offer, but that qualifies as one of the four types of transactions in the Proposed Exemption. All six Petitioners that filed the consolidated Petition requested an exemption of the scope provided and the Petition was analyzed accordingly.[389] The exemption would not extend, however, to any RTO or ISO that was not a party to the Petition under consideration because the Commission has not reviewed the tariffs or business practices of any other RTO or ISO and, therefore, cannot discern whether extending the Proposed Exemption to it would be equally congruent with the public interest and the purposes of the Act. The Commission has determined to issue one Proposed Exemption in lieu of the six separate orders requested by Petitioners.[390] In light of the fact that there are “[congruents] in [the Petitioners'] markets and operations,” and the fact that the exemption for each will be coextensive, as requested by the Petitioners,[391] it would appear that issuing six separate but identical Proposed Exemptions that raise the same issues and questions is unnecessary, could result in needlessly duplicative comments and would be an inefficient use of Commission resources. Any concerns that the public may have with respect to providing relief to any particular Petitioner can be adequately explained in a sole comment on the consolidated Proposed Exemption. The Commission disagrees with the Petitioners' assertion that distinct orders are necessary because a solitary order would require each Petitioner to submit an individual application to obtain supplemental relief or to amend the relief provided thereby. To the contrary, the Commission confirms that individual Petitioners (or other entities) may file individual requests for supplemental exemptions and the Commission may, consistent with the criteria under CEA section 4(c)(6), issue further exemptions either individually or in the collective, as necessary or appropriate and in accordance with the facts and circumstances presented.[392] In fact, ISO NE and CAISO have filed individual requests for supplemental relief that currently are under review by Commission staff.[393]

The Proposed Exemption indicates that, when a final order is issued, it would be made effective immediately. The Commission proposes, however, three conditions precedent to the issuance of a final exemption that may be applicable to one or more specific Petitioners. First, the Commission proposes to refrain from issuing a final order to a specific RTO or ISO unless the RTO or ISO has adopted all of requirements set forth in FERC regulation 35.47; [394] such tariff provisions have been approved or have been permitted to take effect by FERC or PUCT, as applicable; and such tariff provisions, have become effective and have been fully implemented by the particular RTO or ISO. That is, the Commission is considering requiring that any policies and procedures that the RTO or ISO has adopted in order to comply with the obligations contained in FERC regulation 35.47 be in actual practice. Petitioners note that their structure and operations are different from the DCOs registered with the Commission.[395] However, FERC Regulation 35.47 is a set of credit policies purpose-built for RTOs and ISOs.

The Commission's statutorily required determination that the Proposed Exemption is consistent with the public interest and the purposes of the Act was supported, in considerable part, on the grounds that the credit reform policies mandated by FERC regulation 35.47 [396] were consistent with the regulatory objectives of several of the core principles applicable to DCOs and the expectation that the Petitioners regulated by FERC would put those mandates into practice prior to the issuance of the exemption. Moreover, while ERCOT is not subject to regulation by FERC, the fact that these mandates were developed specifically for RTOs and ISOs suggests that holding ERCOT to these standards may well be appropriate.

While all Petitioners have represented that they have fulfilled certain requirements of FERC regulation 35.47, it appears that material gaps in complete execution remain.[397] For example, due to requested extensions of time for compliance, certain Petitioners have only recently submitted tariffs to comply with FERC regulation 35.47(d) (accordingly, the tariffs remain subject to FERC approval) and, in some cases, full implementation is not expected until 2013.[398] Because the implementation of the FERC credit reform policies is central to the Commission's determination that this exemption is in the public interest, it may well be that requiring Petitioners to have fully implemented such reforms prior to the issuance of a final order is necessary and appropriate.

Second, the Commission proposes as an additional prerequisite to the issuance of an exemption to an RTO or ISO that the RTO or ISO provide a well-reasoned legal opinion or memorandum from outside counsel that, in the Commission's sole discretion, provides the Commission with assurance that the netting arrangements contained in the approach selected by the particular Petitioner to satisfy the obligations contained in FERC regulation 35.47(d) will, in fact, provide the Petitioner with enforceable rights of setoff against any of its market participants under title 11 of the United States Code [399] in the event of the bankruptcy of the market participant.[400]

There appears to be strong support for the proposition that a central counterparty structure would achieve the mutuality of obligation necessary for enforceable rights of setoff for the central counterparty, and Petitioners have represented that they either are, or plan on becoming, central counterparties.[401] The Commission is concerned, however, that there is some ambiguity as to how individual Petitioners are interpreting the single counterparty requirement contained in FERC regulation 35.47(d) and whether the single counterparty structure chosen by individual Petitioners would provide enforceable setoff rights. For example, the Petition states that ERCOT “expects to adopt the central counterparty structure; however, this structure will not involve clearing, as that term applies to a designated clearing organization or swaps execution facility (i.e., the central counterparty does not act as a financial intermediary, nor is there any novation of transactions to a central counterparty).” [402] The Commission shares FERC's goal of ensuring that, in the event of bankruptcy of a participant, Petitioners are not prohibited from offsetting accounts receivable against accounts payable. Consistent with that goal and to mitigate any ambiguity regarding the bankruptcy protections provided by the central counterparty arrangements adopted by particular Petitioners, the Commission is proposing to require, as a prerequisite to the granting of the 4(c) request to a particular Petitioner, that the Commission be provided with a legal opinion or memoranda of counsel, applicable to the tariffs and operations of that Petitioner, that provides the Commission with assurance that the approach selected by the Petitioner to satisfy the obligations contained in FERC regulation 35.47(d) will provide the Petitioner with rights of setoff, enforceable against any of its market participants under title 11 of the United States Code in the event of the bankruptcy of the market participant. The Commission would retain sole discretion to accept or reject the adequacy of the legal opinion or memoranda for purposes of issuing the exemption. As noted above, the Commission is seeking comment on the preconditions set forth above and the costs and benefits thereof.

Third, the Proposed Exemption would be conditioned, as applicable to ERCOT, on the completion of an information sharing agreement, acceptable to the Commission, between the PUCT and the Commission. As with the 2005 Memorandum of Understanding (“MOU”) between the Commission and FERC, as discussed below, the Commission would expect the terms of a CFTC-PUCT MOU to provide that PUCT will furnish information in its possession to the CFTC upon its request and will notify the CFTC if any information requested by it is not in PUCT's possession. As noted above, the Commission is seeking comment on the preconditions set forth above and the costs and benefits thereof.

The Proposed Exemption also contains certain information-sharing conditions. First, the Proposed Exemption is expressly conditioned upon the existing information sharing arrangement between the Commission and FERC, and, as noted above, the completion of an information sharing agreement between the Commission and PUCT. The Commission notes that the CFTC and FERC executed a MOU in 2005 pursuant to which the agencies have shared information successfully.[403] The terms of the CFTC-FERC MOU provide that FERC will furnish information in its possession to the CFTC upon its request and will notify the CFTC if any information requested by it is not in FERC's possession.

The Petitioners recognize the need to be responsive to Commission requests for information and “to assist the Commission as necessary in fulfilling its mission under the Act” [404] and Petitioners have indicated their intent to be responsive to requests for information by the Commission that will further enable the Commission to perform its regulatory and enforcement duties.[405] Petitioners caveat this assistance, however, by stating that “certain of the tariffs may require that an ISO/RTO notify its members prior to providing information in response to a subpoena.” [406] This notice requirement could significantly compromise the Commission's enforcement efforts as there are likely to be situations where it would be neither prudent nor advisable for an entity under investigation by the Commission to learn of the investigation prior to Commission notification to the entity. Accordingly, the Proposed Exemption includes a second information-sharing condition that requires that neither the tariffs nor any other governing documents of the particular RTO or ISO pursuant to whose tariff the agreement, contract or transaction is to be offered or sold, shall include any requirement that the RTO or ISO notify its members prior to providing information to the Commission in response to a subpoena or other request for information or documentation. The Commission specifically requests comment on this condition and as to whether there may be an alternative condition that the Commission might use to achieve the same result.

Finally, the Proposed Exemption expressly notes that it is based upon the representations made in the Petition and in the supporting materials provided to the Commission by the Petitioners and their counsel and that any material change or omission in the facts and circumstances pursuant to which the Proposed Exemption is granted might require the Commission to reconsider its finding that the exemption contained therein is appropriate and/or in the public interest. The Commission has also explicitly reserved the discretionary authority, to suspend, terminate or otherwise modify or restrict the exemption provided. The reservation of these rights is consistent with prior Commission practice and is necessary to provide the Commission with the flexibility to address relevant facts or circumstances as they arise.

B. Proposed Exemption

Consistent with the determinations set forth above, the Commission hereby proposes to issue the following Order:

Pursuant to its authority under section 4(c)(6), in accordance with CEA sections 4(c)(1) and (2), of the Commodity Exchange Act (“CEA” or Act”), the Commodity Futures Trading Commission (“CFTC” or “Commission”).

1. Exempts, subject to the conditions and limitations specified herein, the purchase or sale of the electricity-related agreements, contracts, and transactions that are specified in paragraph 2 of this Order and any person or class of persons offering, entering into, rendering advice, or rendering other services with respect thereto, from all provisions of the CEA, except, in each case, the Commission's general anti-fraud, anti-manipulation and enforcement authority under the CEA, including, but not limited to, 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 and any implementing regulations promulgated thereunder including, but not limited to, Commission regulations 23.410(a) and (b), 32.4 and part 180.

2. Scope. This exemption applies only to agreements, contracts and transactions that satisfy all of the following requirements:

a. The agreement, contract or transaction is for the purchase and sale of one of the following electricity-related products:

(1) The “Financial Transmission Rights” defined in paragraph 5(a) of this Order, except that the exemption shall only apply to such Financial Transmission Rights where:

(a) Each Financial Transmission Right is linked to, and the aggregate volume of Financial Transmission Rights for any period of time is limited by, the physical capability (after accounting for counterflow) of the electricity transmission system operated by a Requesting Party offering the contract, for such period;

(b) The Requesting Party serves as the market administrator for the market on which the Financial Transmission Rights are transacted;

(c) Each party to the transaction is a member of the Requesting Party (or is the Requesting Party itself) and the transaction is executed on a market administered by that Requesting Party; and

(d) The transaction does not require any party to make or take physical delivery of electricity.

(2) “Energy Transactions” as defined in paragraph 5b of this Order.

(3) “Forward Capacity Transactions,” as defined in paragraph 5c of this Order.

(4) “Reserve or Regulation Transactions” as defined in paragraph 5d of this Order.

b. All parties to the agreement, contract or transaction are “appropriate persons,” as defined sections 4(c)(3)(A) through (J) of the CEA or “eligible contract participants” as defined in section 1a(18)(A) of the CEA and in Commission regulation 1.3(m).

c. The agreement, contract or transaction is offered or sold pursuant to a Requesting Party's tariff and that tariff has been approved or permitted to take effect by:

(1) In the case of the Electricity Reliability Council of Texas (“ERCOT”), the Public Utility Commission of Texas (“PUCT”) or

(2) In the case of all other Requesting Parties, the Federal Energy Regulatory Commission (“FERC”).

3. Applicability to particular regional transmission organizations (“RTOs”) and independent system operators (“ISOs”). Subject to the conditions contained in the Order, the Order applies to all Requesting Parties with respect to the transactions described in paragraph 2 of this Order.

4. Conditions. The exemption provided by this Order is expressly conditioned upon the following:

a. Information sharing: With respect to ERCOT, information sharing arrangements between the Commission and PUCT that are acceptable to the Commission are executed and continue to be in effect. With respect to all other Requesting Parties, information sharing arrangements between the Commission and FERC that are acceptable to the Commission continue to be in effect.

b. Notification of requests for information: With respect to each Requesting Party, neither the tariffs nor any other governing documents of the particular RTO or ISO pursuant to whose tariff the agreement, contract or transaction is to be offered or sold, shall include any requirement that the RTO or ISO notify its members prior to providing information to the Commission in response to a subpoena or other request for information or documentation.

5. Definitions. The following definitions shall apply for purposes of this Order:

a. A “Financial Transmission Right” 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 Requesting Party, at a specified source (i.e., where electricity is deemed injected into the grid of a Requesting Party) and a specified sink (i.e., where electricity is deemed withdrawn from the grid of a Requesting Party). The term “Financial Transmission Rights” 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).

b. “Energy Transactions” are transactions in a “Day-Ahead Market” or “Real-Time Market,” as those terms are defined in paragraphs 5e and 5f of this Order, for the purchase or sale of a specified quantity of electricity at a specified location (including “Demand Response,” as defined in paragraph 5c(2) of this Order, where:

(1) The price of the electricity is established at the time the transaction is executed;

(2) Performance occurs in the Real-Time Market by either

(a) Delivery or receipt of the specified electricity, or

(b) A cash payment or receipt at the price established in the Real-Time Market; and

(3) 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 Requesting Party for that period of time.

c. “Forward Capacity Transactions” are transactions in which a Requesting Party, for the benefit of load-serving entities, purchases any of the rights described in subparagraphs (1), (2) and (3) below. In each case, to be eligible for the exemption, the aggregate cleared volume of all such transactions for any period of time shall be limited to the physical capability of the electricity transmission system operated by a Requesting Party for that period of time.

(1) “Generation Capacity,” meaning the right of a Requesting Party to:

(a) Require certain sellers to maintain the interconnection of electric generation facilities to specific physical locations in the electric-power transmission system during a future period of time as specified in the Requesting Party's Tariff;

(b) Require such sellers to offer specified amounts of electric energy into the Day-Ahead or Real-Time Markets for electricity transactions; and

(c) Require, subject to the terms and conditions of a Requesting Party's Tariff, such sellers to inject electric energy into the electric power transmission system operated by the Requesting Party;

(2) “Demand Response,” meaning the right of a Requesting Party to require that certain sellers of such rights curtail consumption of electric energy from the electric power transmission system operated by a Requesting Party during a future period of time as specified in the Requesting Party's Tariff; or

(3) “Energy Efficiency,” meaning the right of a Requesting Party to require specific performance of an action or actions that will reduce the need for Generation Capacity or Demand Response Capacity over the duration of a future period of time as specified in the Requesting Party's Tariff.

d. “Reserve or Regulation Transactions” are transactions:

(1) In which a Requesting Party, for the benefit of load-serving entities and resources, purchases, through auction, the right, during a period of time as specified in the Requesting Party's Tariff, to require the seller of such right to operate electric facilities in a physical state such that the facilities can increase or decrease the rate of injection or withdrawal of a specified quantity of electricity into or from the electric power transmission system operated by the Requesting Party with:

(a) Physical performance by the seller's facilities within a response time interval specified in a Requesting Party's Tariff (Reserve Transaction); or

(b) Prompt physical performance by the seller's facilities (Area Control Error Regulation Transaction);

(2) For which the seller receives, in consideration, one or more of the following:

(a) Payment at the price established in the Requesting Party's Day-Ahead or Real-Time Market, as those terms are defined in paragraphs 5f and 5g of this Order, price for electricity applicable whenever the Requesting Party exercises its right that electric energy be delivered (including Demand Response, ” as defined in paragraph 5c(2) of this Order);

(b) Compensation for the opportunity cost of not supplying or consuming electricity or other services during any period during which the Requesting Party requires that the seller not supply energy or other services;

(c) An upfront payment determined through the auction administered by the Requesting Party for this service;

(d) An additional amount indexed to the frequency, duration, or other attributes of physical performance as specified in the Requesting Party's Tariff; and

(3) In which the value, quantity, and specifications of such transactions for a Requesting Party for any period of time shall be limited to the physical capability of the electricity transmission system operated by the Requesting Party for that period of time.

e. “Day-Ahead Market” means an electricity market administered by a Requesting Party on which the price of electricity at a specified location is determined, in accordance with the Requesting Party's Tariff, for specified time periods, none of which is later than the second operating day following the day on which the Day-Ahead Market clears.

f. “Real-Time Market” means an electricity market administered by a Requesting Party on which the price of electricity at a specified location is determined, in accordance with the Requesting Party's tariff, for specified time periods within the same 24-hour period.

g. “Requesting Party” means California Independent Service Operator Corporation (“CAISO”); ERCOT; ISO New England Inc. (“ISO NE”); Midwest Independent Transmission System Operator, Inc. (“MISO”); New York Independent System Operator, Inc. (“NYISO”) or PJM Interconnection, L.L.C. (“PJM”), or any successor in interest to any of the foregoing.

h. “Tariff.” Reference to a Requesting Party's “tariff” includes a tariff, rate schedule or protocol.

i. “Petition” means the consolidated petition for an exemptive order under 4(c)(6) of the CEA filed by CAISO, ERCOT, ISO NE., MISO, NY ISO and PJM on February 7, 2012, as later amended.

6. Effective Date. This Order is effective immediately.

This order is based upon the representations made in the consolidated petition for an exemptive order under 4(c) of the CEA filed by the Requesting Parties [407] and supporting materials provided to the Commission by the Requesting Parties and their counsel. Any material change or omission in the facts and circumstances pursuant to which this order is granted might require the Commission to reconsider its finding that the exemption contained therein is appropriate and/or in the public interest. Further, the Commission reserves the right, in its discretion, to revisit any of the terms and conditions of the relief provided herein, including but not limited to, making a determination that certain entities and transactions described herein should be subject to the Commission's full jurisdiction, and to condition, suspend, terminate or otherwise modify or restrict the exemption granted in this order, as appropriate, upon its own motion.

IX. Related Matters

A. Regulatory Flexibility Act

The Regulatory Flexibility Act [408] (“RFA”) requires that agencies consider whether the Proposed Exemption will have a significant economic impact on a substantial number of small entities and, if so, provide a regulatory flexibility analysis respecting the impact. The Commission believes that the Proposed Exemption will not have a significant economic impact on a substantial number of small entities. The Proposed Exemption detailed in this release would affect organizations including Petitioners and eligible contract participants (“ECPs”).[409] The Commission has previously determined that ECPs are not “small entities” for purposes of the RFA.[410] In addition, the Commission believes that Petitioners should not be considered small entities based on the central role they play in the operation of the electronic transmission grid and the creation of organized wholesale electric markets that are subject to FERC and PUCT regulatory oversight,[411] analogous to functions performed by DCMs and DCOs, which the Commission has determined not to be small entities.[412]

Accordingly, the Commission does not expect the Proposed Exemption to have a significant impact on a substantial number of entities. Therefore, the Chairman, on behalf of the Commission, hereby certifies, pursuant to 5 U.S.C. 605(b), that the Proposed Exemption would not have a significant economic impact on a substantial number of small entities. The Commission invites the public to comment on whether the entities covered by this Proposed Exemption should be considered small entities for purposes of the RFA, and, if so, whether there is a significant impact on a substantial number of entities.

B. Paperwork Reduction Act

The purposes of the Paperwork Reduction Act of 1995, 44 U.S.C. 3501 et seq. (“PRA”) are, among other things, to minimize the paperwork burden to the private sector, ensure that any collection of information by a government agency is put to the greatest possible uses, and minimize duplicative information collections across the government. The PRA applies to all information, “regardless of form or format,” whenever the government is “obtaining, causing to be obtained [or] soliciting” information, and includes requires “disclosure to third parties or the public, of facts or opinions,” when the information collection calls for “answers to identical questions posed to, or identical reporting or recordkeeping requirements imposed on, ten or more persons.” The PRA would not apply in this case given that the exemption would not impose any new recordkeeping or information collection requirements, or other collections of information on ten or more persons that require approval of the Office of Management and Budget (“OMB”).

C. Cost-Benefit Considerations

1. Consideration of Costs and Benefits

a. Introduction

Section 15(a) of the CEA [413] requires the Commission to consider the costs and benefits of its actions before promulgating a regulation under the CEA or issuing certain orders. In proposing this exemption, the Commission is required by section 4(c)(6) to ensure the same is consistent with the public interest. In much the same way, section 15(a) further specifies that the costs and benefits shall be evaluated in light of five broad areas of market and public concern: (1) Protection of market participants and the public; (2) efficiency, competitiveness and financial integrity of futures markets; (3) price discovery; (4) sound risk management practices; and (5) other public interest considerations. The Commission considers the costs and benefits resulting from its discretionary determinations with respect to the section 15(a) factors.

As discussed above, in response to a Petition from certain regional transmission organizations and independent system operators, the Commission is proposing to exempt specified transactions from the provisions of the CEA and Commission regulations with the exception of those prohibiting fraud and manipulation (i.e., 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 and any implementing regulations promulgated thereunder including, but not limited to, Commission regulations 23.410(a) and (b), 32.4 and part 180). The Proposed Exemption is transaction-specific—that is, it would exempt contracts, agreements and transactions for the purchase or sale of the limited set of electricity-related products that are 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.

More specifically, the Commission is proposing to 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 proposed Order, if such transactions are offered or entered into pursuant to a tariff under which a Petitioner operates that has been approved by FERC or the Public Utility Commission of Texas, as applicable. The Proposed Exemption extends to any persons (including Petitioners, their members and their market participants) offering, entering into, rendering advice, or rendering other services with respect to such transactions. Important to the Commission's Proposed Exemption is the Petitioners' representations that the aforementioned transactions are: (i) Tied to the physical capacity of the Petitioner's electricity grids; (ii) used to promote the reliable delivery of electricity; and (iii) are intended for use by commercial participants that are in the business of generating, transmitting and distributing electricity. In other words, these are not purely financial transactions; rather, they are inextricably linked to, and limited by, the capacity of the grid to physically deliver electricity.

In the discussion that follows, the Commission considers the costs and benefits of the proposed Order to the public and market participants generally, including the costs and benefits of the conditions precedent that must be satisfied before a Petitioner may claim the exemption.

b. Proposed Baseline

The Commission's proposed baseline for consideration of the costs and benefits of this Proposed Exemption are the costs and benefits that the public and market participants (including Petitioners) would experience in the absence of this proposed regulatory action. In other words, the proposed baseline is an alternative situation in which the Commission takes no action, meaning that the transactions that are the subject of this Petition would be required to comply with all of the CEA and Commission regulations, as may be applicable. In such a scenario, the public and market participants would experience the full benefits and costs related to the CEA and Commission regulations, but as discussed in detail above, the transactions would still be subject to the congruent regulatory regimes of the FERC and PUCT. In areas where the Commission believed additional requirements were necessary to ensure the public interest, the Commission proposed additional requirements (e.g., the requirement that Petitioners submit a memorandum or opinion of counsel to the Commission confirming the enforceability of the Petitioners' netting arrangements in the event of a bankruptcy of a participant).

The Commission also considers the regulatory landscape as it exists outside the context of the Dodd-Frank Act's enactment. Here too, it is important to highlight Petitioners' representations that each of the transactions for which an exemption is requested is already 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. For example, the costs and benefits attendant to the Commission's condition that transactions be entered into between “appropriate persons” as described in CEA section 4(c)(3) has an analog outside the context of the Dodd-Frank Act in FERC's minimum criteria for RTO market participants as set forth in FERC Order 741.

In the discussion that follows, where reasonably feasible, the Commission endeavors to estimate quantifiable dollar costs of the Proposed Exemption. The benefits of the Proposed Exemption, as well as certain costs, however, are not presently susceptible to meaningful quantification. Most of the costs arise from limitations on the scope of the proposed Order, and many of the benefits arise from avoiding defaults and their implications that are clearly large in magnitude, but impracticable to estimate. Where it is unable to quantify, the Commission discusses proposed costs and benefits in qualitative terms.

c. Costs

The Proposed Order is exemptive and would provide potentially eligible transactions with relief from the requirements of the CEA and attendant Commission regulations. As with any exemptive rule or order, the proposal is permissive, meaning that Petitioners were not required to request it and are not required to rely on it. Accordingly, the Commission assumes that Petitioners required and would rely on the Proposed Exemption only if the anticipated benefits warrant the costs of the same. Here, the Proposed Exemption identifies certain conditions precedent to the grant of the Proposed Exemption. The Commission is of the view that, as a result of the conditions, Petitioners, market participants and the public would experience minimal, if any, ongoing, incremental costs as a result of these conditions. This is so because, as Petitioners certify pursuant to CFTC Rule 140.99(c)(3)(ii), the attendant conditions are substantially similar to requirements that Petitioners and their market participants already incur in complying with FERC or PUCT regulation.

The first condition—that 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)—should not impose any significant, incremental costs because Petitioners must already incur costs in complying with their existing legal and regulatory obligations under the FPA and FERC or PUCT regulations, which mandate that only eligible market participants may engage in the transactions that are the subject of this proposal, as explained in section V.B.3. above.

The second is that 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. This is a statutory requirement for the exemption. See CEA 4(c)(6)(A), (B). Moreover, requiring that Petitioners' not operate outside their tariff requirements derives from existing legal requirements and is not a cost attributable to this proposal.

Third, as described in section V.B.1. above, FERC and PUCT impose on their respective Petitioners, and their market monitors, various information management requirements. These existing requirements are not materially different from the condition that 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. However, certain existing tariffs (see footnote 406 and accompanying text) may not currently meet the condition; therefore the Commission requests comment as to whether this condition imposes a significant burden or increase in cost on Petitioners with such tariffs, and whether there are alternative conditions that may be used to achieve a similar result. Further, Petitioners have agreed to provide any information to the Commission upon request that will further enable the Commission to perform its regulatory and enforcement duties. While the Commission is mindful that the process of responding to subpoenas or requests for information involves costs, such subpoenas and requests for information, and thus the associated costs, are independent of the current proposed Order.

Fourth, information sharing arrangements that are satisfactory to the Commission between the Commission and FERC, and the Commission and PUCT, must be in full force and effect is not a cost to Petitioners or to other members of the public but, in the case of FERC, has been an inter-agency norm since 2005. Moreover, and with respect to the proposed condition that would require the Commission and PUCT to enter into an information sharing arrangement, the sharing of information between government agencies is an efficient means of reducing governmental costs.

Finally, the Commission is proposing to require, as a prerequisite to the granting of the 4(c)(6) request to a particular Petitioner, that the Petitioner provide the Commission with a legal opinion or memoranda of counsel that provides the Commission with assurance that the approach selected by the Petitioner to satisfy the obligations contained in FERC regulation 35.47(d) will provide the Petitioner with enforceable rights of setoff against any of its market participants under title 11 of the United States Code in the event of the bankruptcy of the market participant. For instance, for transactions in a DCO context, the DCO is clearly the central counterparty. In the case of most ISOs and RTOs, there has been some ambiguity in this regard. As a result of this ambiguity, in the event of the bankruptcy of a participant, there is a concern that ISOs and RTOs may be liable to pay a bankrupt participant for transactions in which that participant is owed funds, without the ability to net amounts owed by the market participant in a bankruptcy, despite the fact that the tariffs submitted by the Petitioners to FERC include explicit language permitting set-off and netting.[414] As FERC expressed in the FERC Credit Rulemaking and the FERC Order on Rehearing, there is a risk that the explicit tariff language may be insufficient to protect the Petitioners in bankruptcy, and even if this risk were to be at a low probability of manifestation, there would be a high cost to market participants and the stability of the markets if it did so.[415] The Commission would require that the opinions or memoranda would be addressed to the Commission and would be signed on behalf of the law firm that is issuing the opinion, rather than by specific partners and/or associates. The Commission also would require the text of the opinion or memoranda to satisfy certain enumerated criteria. Based on the Laffey Matrix for 2012, assuming the opinion is prepared by a seasoned attorney (with 20 plus years of legal practice), his/her hourly rate ($734 per hour) multiplied by the amount of hours taken to prepare the opinion, will be the basic cost of such an opinion.[416] The Commission estimates that the cost of such memoranda will range between $15,000 and $30,000, part of which depends on the complexity of the analysis necessary to support the conclusion that the Petitioner's setoff rights are enforceable, and assuming that the opinion will take 20-40 hours to prepare.[417]

d. Benefits

In proposing this exemption, the Commission is required by section 4(c)(6) to ensure the same is consistent with the public interest. In much the same way, CEA section 15(a) requires that the Commission consider the benefits to the public of its action. In meeting its public interest obligations under both 4(c)(6) and 15(a), the Commission in sections V.B.1. and V.D. proposes a detailed consideration of the nature of the transactions and FERC and PUCT regulatory regimes, including whether the protections provided by those regimes are, at a minimum, congruent with the Commission's oversight of DCOs and SEFs.

This exercise is not rote; rather, in proposing that this exemption is in the public interest, the Commission's comprehensive action benefits the public and market participants in several substantive ways, as discussed below. In addition, by considering a single application from all Petitioners at the same time, and proposing to allow all provisions of the exemption to 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, this proposal provides a cost-mitigating, procedural efficiency. The Commission's proposal also reduces the potential need for future amendments to the final exemption in order for one Petitioner to offer or enter into the same type of transactions currently offered by another.

In more substantive terms, by requiring that the transactions at issue are, in fact, limited to those that are administered by the petitioning RTOs/ISOs, and are inextricably linked to the organized wholesale electricity markets that are subject to FERC and PUCT regulation and oversight, the Commission limits the scope of the proposed relief. In so doing, the proposal minimizes the potential that purely financial risk can accumulate outside the comprehensive regime for swaps regulation established by Congress in the Dodd-Frank Act and implemented by the Commission. The mitigation of such risk inures to the benefit of Petitioners, market participants and the public, especially Petitioners' members and electricity ratepayers.

The condition that only “appropriate persons” may enter the transactions that are the subject of this proposal benefits the public and market participants by ensuring that (1) only persons with resources sufficient to understand and manage the risks of the transactions are permitted to engage in the same, and (2) persons without such resources do not impose credit costs on other participants (and the ratepayers for such other participants). Further, the condition requiring that the transactions only be offered or sold pursuant to a FERC or PUCT tariff benefits the public by, for example, ensuring that the transactions are subject to a regulatory regime that is focused on the physical provision of reliable electric power, and also has credit requirements that are designed to achieve risk management goals congruent with the regulatory objectives of the Commission's DCO Core Principles. Absent these and other similar limitations on participant- and financial-eligibility, the integrity of the markets at issue could be compromised and members and ratepayers left unprotected from potentially significant losses. Moreover, the Commission's requirement that Petitioner's file an opinion of counsel regarding the right of set-off in bankruptcy provides a benefit in that the analytical process necessary to formulate such an opinion would highlights risks faced by the Petitioners, and permit them to adapt their structure and procedures in a manner best calculated to mitigate such risks, and thus helps ensure the orderly handling of financial affairs in the event a participant fails as a result of these transactions.

Finally, the Commission's retention of its authority to redress any fraud or manipulation in connection with the transactions at issue protects market participants and the public generally, as well as the financial markets for electricity products. For example, a condition precedent to the Proposed Exemption is effective information sharing arrangements between the FERC and the Commission, and PUCT and the Commission. Through such an arrangement, the Commission expects that it will be able to request information necessary to examine whether activity on Petitioners' markets is adversely affecting the Commission regulated markets. Further, the condition precedent that Petitioners not notify a member prior to providing the Commission with information will help maximize the effectiveness of the Commission's enforcement program.

e. Costs and Benefits as Compared to Alternatives

The Commission considered alternatives to the proposed rulemaking. For instance, the Commission could have chosen: (i) Not to propose an exemption or (ii), as Petitioners' requested, to provide relief for

“the purchase and sale of a product or service that is directly related to, and a logical outgrowth of, any [of Petitioners'] core functions as an ISO/RTO * * * and all services related thereto.” Regarding this latter request, the Commission understands the Petition as requesting relief for transactions not yet in existence. In this Order, the Commission proposes what it considers a measured approach—in terms of the implicated costs and benefits of the exemption—given its current understanding of transactions at issue.

Regarding the first alternative, the Commission considered that Congress, in the Dodd-Frank Act, required the Commission to exempt certain contracts, agreements or transactions from duties otherwise required by statute or Commission regulation by adding a new section that permits the Commission to exempt from its regulatory oversight 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, where such exemption was in the public interest and consistent with the purposes of the CEA. Having concluded that the instant exemption meets those tests, the Commission proposes that a no exemption alternative would be inconsistent with Congressional intent and contrary to the public interest. At the same time, however, the Commission believes it would also be inappropriate to adopt the second alternative.

The second alternative would extend the Proposed Exemption to all “logical outgrowths” of the transactions at issue. The Commission proposes that such an exemption would be contrary to the Commission's obligation under section 4(c) of the Act. As noted above, the authority to issue an exemption from the CEA provided by section 4(c) of the Act may not be automatically or mechanically exercised. Rather, the Commission is required to affirmatively determine, inter alia, that the exemption would be consistent with the public interest and the purposes of the Act.

With respect to the four groups of transactions detailed in the Proposed Exemption, the Commission's finding that the Proposed Exemption would be in the public interest and would be consistent with the purposes of the CEA is grounded, in part, on known transaction characteristics and market circumstances described in the Petition that may or may not be shared by other, as yet undefined, transactions engaged in by the Petitioners or other RTO or ISO market participants. Similarly, unidentified transactions might include novel features or have market implications or risks that are beyond evaluation at the present time, and are not present in the specified transactions.

2. Consideration of CEA Section 15(a) Factors with respect to the Proposed Order

a. Protection of Market Participants and the Public

In proposing the exemption as it did, the Commission endeavored to provide relief that was in the public interest. A key component of that consideration is the assessment of how the Proposed Exemption protects market participants and the public. As discussed above, market participants and the public are protected by the existing regulatory structure that includes congruent regulatory goals, and by the four conditions placed upon the proposed relief by requiring, inter alia, that: (i) Only those with the financial wherewithal are permitted to engage in the transactions; (ii) the transactions at issue must be within the scope of a Petitioner's FERC or PUCT tariff; (iii) no advance notice to members of information requests to Petitioners from the Commission; and (iv) the Commission and FERC, and PUCT and the Commission, must have an information sharing arrangement in full force and effect. Additionally, the requirement that Petitioners file and opinion of counsel regarding bankruptcy matters provides additional information from which the Commission may be assured that the netting that Petitioners rely upon as an integral part of their risk management is in fact enforceable.

b. Efficiency, Competitiveness, and Financial Integrity of Futures Markets

To the extent that the transactions at issue could have an indirect effect on the efficiency, competitiveness, and financial integrity of the markets subject to the Commission's jurisdiction, the relief is tailored in such a way as to mitigate any such effects. More specifically, the Proposed Exemption is limited to the transactions identified and defined herein. In this way, the Commission eliminates the potential that as-yet-unknown transactions not linked to the physicality of the electric system may be offered or sold under this Proposed Exemption. Further, the Commission's retention of its full enforcement authority will help ensure that any misconduct in connection with the exempted transactions does not jeopardize the financial integrity of the markets under the Commission's jurisdiction.

c. Price Discovery

As discussed above in section V.B.4, with respect to FTRs, Forward Capacity Transactions, and Reserve or Regulation Transactions, these transactions do not directly impact on transactions taking place on Commission regulated markets—they are not used for price discovery and are not used as settlement prices for other transactions in Commission regulated markets

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, does not mean that these transactions will be unregulated. To the contrary, as explained in more detail above, Petitioners have market monitoring systems in place to detect and deter manipulation that takes place on their markets. Further, as noted above, the Commission retains all of its anti-fraud and anti-manipulation authority as a condition of the Proposed Exemption.

d. Sound Risk Management Practices

As with the other areas of cost-benefit consideration, the Commission's evaluation of sound risk management practices occurs throughout this release, notably in sections V.D.4.a. and V.E.7.a. which consider the Petitioners' risk management policies and procedures, and the related requirements of FERC and PUCT (in particular, FERC Order 741 on Credit Policies), in light of the Commission's risk management requirements for DCOs and SEFs.

e. Other Public Interest Considerations

The Commission proposes that because these transactions are part of, and inextricably linked to, the organized wholesale, physical electricity markets that are subject to regulation and oversight of FERC or PUCT, as applicable, the Commission's Proposed Exemption, with its attendant conditions, requirements, and limitations, is in the public interest. In so considering, the Commission proposes that the public interest is best served if the Commission dedicates its resources to the day-to-day oversight of its registrants and the financial markets subject to the CEA.

3. Request for Public Comment on Costs and Benefits

The Commission invites public comment on its cost-benefit considerations and dollar cost estimates, including the consideration of reasonable alternatives. Commenters are invited to submit any data or other information that they may have quantifying or qualifying the costs and benefits of the proposal with their comment letters.

X. Request for Comment

The Commission requests comment on all aspects of its Proposed Exemption. In addition, the Commission specifically requests comment on the specific provisions and issues highlighted in the discussion above and on the issues presented in this section. For each comment submitted, please provide a detailed rationale supporting the response.

1. Has the Commission used the appropriate standard in analyzing whether the Proposed Exemption is in the public interest?

2. The Commission recognizes that there may be differences among the Petitioners with respect to size, scope of business, and underlying regulatory framework. Should any provisions of the Proposed Exemption be modified or adjusted, or should any conditions be added, to reflect such differences?

3. Is the scope set forth for the Proposed Exemption sufficient to allow for innovation? Why or why not? If not, how should the scope be modified to allow for innovation without exempting products that may be materially different from those reviewed by the Commission? Should the Commission exempt such products without considering whether such exemption is in the public interest? Consider this question also with the understanding that any Petitioner (or any entity that is not a current petitioner) may separately petition the Commission for an amendment of any final order granted in this matter.

4. Should the Commission exercise its authority pursuant to section 4(c)(3)(K) of the CEA to extend the Proposed Exemption to agreements contracts or transactions that are entered into by parties other than “appropriate persons” as defined in sections 4(c)(3)(A) through (J) of the CEA, or “eligible contract participants,” as defined in section 1a(18)(A) or (B) of the Act and Commission regulation 1.3(m)? If so, please provide a description of the additional parties that should be included.

a. The Commission specifically seeks comment regarding whether (and, if so, why) it is in the public interest to expand the list of such parties to include market participants who “active[ly] participat[e] in the generation, transmission or distribution of electricity” but who are neither “appropriate persons,” as defined in section 4(c)(3)(A) through (J) of the CEA, nor “eligible contract participants,” as defined in section 1a(18)(A) of the Act and Commission regulation 1.3(m)?

b. If any additional parties should be added, please provide:

(1) An explanation of the financial or other qualifications of such persons or the available regulatory protections that would render such persons “appropriate persons.”

(2) The basis for the conclusion that such parties could bear the financial risks of the agreements, contracts, and transactions to be exempted by the Proposed Exemption.

(3) The basis for the conclusion that including such parties would not have any adverse effect on the relevant RTO or ISO.

(4) The basis for the conclusion that failing to include such parties would have an adverse effect on any relevant RTO or ISO.

5. Should the Commission require each Petitioner that is regulated by FERC to have fully implemented the requirements set forth in FERC Order 741 as a condition precedent to the issuance of a final order granting the Proposed Exemption to the particular Petitioner? Why or why not?

6. Should ERCOT be required to comply with the requirements set forth in FERC Order 741 as a prerequisite to the issuance to ERCOT of a final order granting the Proposed Exemption as to ERCOT? Why or why not?

a. The Commission specifically seeks comment upon whether and why ERCOT would or would not be able to comply with each of the requirements set forth in FERC Order 741. Are any of these requirements inapplicable for an RTO/ISO?

b. Should ERCOT be permitted to adopt alternatives to any of the specific requirements set forth in FERC Order 741 (such as the seven day settlement period in FERC regulation 35.47(b))? What is the basis for the conclusion that the alternative measures would be the equivalents of the FERC requirements in terms of protecting the financial integrity of the transactions that are within the scope of the exemption?

7. Should the Commission require, as a prerequisite to issuing a final order granting the Proposed Exemption to a particular Petitioner, that the Commission be provided with a legal opinion or memoranda of counsel, applicable to the tariffs and operations of that Petitioner, that provides the Commission with assurance that the approach selected by the Petitioner to satisfy the obligations contained in FERC regulation 35.47(d) will provide the Petitioner with rights of setoff, enforceable against any of its market participants under title 11 of the United States Code in the event of the bankruptcy of the market participant? Why or why not? Are there alternative ways to provide the requisite assurance regarding the bankruptcy protections provided by the approach to 35.47(d) compliance selected by Petitioners and the requisite assurance that the central counterparty structure selected by Petitioners will be consistent or contain elements commonly associated with central counterparties?

8. Should the Commission require the execution of an acceptable information sharing arrangement between the Commission and PUCT as a condition precedent to the issuance to ERCOT of a final order granting the request for an exemption?

9. Should the Proposed Exemption be conditioned upon the requirement that the Petitioners cooperate with the Commission in its conduct of special calls/further requests for information with respect to contracts, agreements or transactions that are, or are related to, the contracts, agreements, or transactions that are the subject of the Proposed Exemption?

10. Should Petitioners be required to have the ability to obtain market data and other related information from their participants with respect to contracts, agreements or transactions in markets for, or related to, the contracts, agreements or transactions that are the subject of the Proposed Exemption? The Commission specifically seeks comment on whether the Petitioners should capable of re-creating the Day-Ahead Market and Real-Time prices.

11. What is the basis for the conclusion that Petitioners do, or do not, provide to the public sufficient timely information on price, trading volume, and other data with respect to the markets for the contracts, agreements and transactions that are the subject of the Proposed Exemption? What RTO or ISO tariff provisions, if any, require them to do so or preclude them from doing so?

12. What is the basis for the conclusion that the Proposed Exemption will, or will not, have any material adverse effect on the Commission's ability to discharge its regulatory duties under the CEA, or on any contract market's ability to discharge its self-regulatory duties under the CEA?

13. What are the bases for the conclusions that the Petitioners' tariffs, practices, and procedures do, or do not, appropriately address the regulatory goals of each of the DCO Core Principles?

14. What factors support, or detract from, the Commission's preliminary conclusion that FTRs, Energy Transactions, Capacity and Reserve Transactions are not readily susceptible to manipulation for the reasons stated above? Could a market participant use an FTR to manipulate the price of electricity established on the Day-Ahead and Real-Time markets operated by Petitioners? If so, what is the basis for that conclusion? What is the basis for the conclusion that market participants can, or cannot, use Energy Transactions, Capacity or Reserve Transactions to manipulate electricity prices without detection by Independent Market Monitors?

15. What is the basis for the conclusion that Petitioners have, or have not, satisfied applicable market monitoring requirements with respect to FTRs, Energy Transactions, Capacity and Reserve Transactions? What is the basis for the conclusion that the record-keeping functions performed by Petitioners are, or are not, appropriate to address any concerns raised by the market monitoring process? What is the basis for the conclusion that the market monitoring functions performed by Petitioners and their MMUs do, or do not, provide adequate safeguards to prevent the manipulation of Petitioners' markets?

16. What is the basis for the conclusion that Petitioners, or their participants, should, or should not, be required to satisfy position limit requirements with respect to any of the contracts, agreements or transactions that are the subject of the Proposed Exemption? Specifically, what is the basis for the conclusion that it is, or is not, possible for Petitioners, or their participants, to violate position limits with FTRs or Virtual Bids? What is the basis for the conclusion that the nature of FTRs or Virtual Bids do, or do not, inherently limit the ability of market participants to engage in manipulative conduct?

17. What are the bases for the conclusions that Petitioners do, or do not, adequately satisfy the SEF requirements for (a) recordkeeping and reporting, (b) preventing restraints on trade or imposing any material anticompetitive burden, (c) minimizing conflicts of interest, (d) providing adequate financial resources, (e) establishing system safeguards and (f) designating a CCO? Specifically, do the procedures and principles in place allow the Petitioners to meet the requirements of SEF core principles 10-15?

18. What is the basis for the conclusion that the Petitioners' eligibility requirements for participants are, or are not, appropriate to ensure that market participants can adequately bear the risks associated with the Participants markets?

19. What is the basis for the conclusion that Petitioners do, or do not, have adequate rules in place to allow them to deal with emergency situations as they arise? What deficiencies, if any, Are there with respect to their emergency procedures that would prevent any Petitioner from taking necessary action to address sudden market problems?

20. The Commission invites comment on its consideration of the costs and benefits of the Proposed Exemption, including the costs of any information requirements imposed therein. The Commission also seeks comment on the costs and benefits of this Proposed Exemption, including, but not limited to, those costs and benefits specified within this proposal. Commenters are also are invited to submit any data or other information that they may have quantifying or qualifying the costs and benefits of the proposal with their comment letters.

Issued in Washington, DC on August 21, 2012, by the Commission.

Sauntia S. Warfield,

Assistant Secretary of the Commission.

Notice of 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 Pursuant to the Authority Provided in Section 4(c)(6) of the Act—Commission Voting Summary and Statements of Commissioners

Note:

The following appendices will not appear in the Code of Federal Regulations.

Appendix 1—Commission Voting Summary

On this matter, Chairman Gensler and Commissioners Sommers, Chilton, O'Malia and Wetjen voted in the affirmative; no Commissioner voted in the negative.

Appendix 2—Statement of Chairman Gary Gensler

I support the proposed relief from the Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act) swaps provisions for certain electricity-related transactions entered into on markets administered by regional transmission organizations (RTOs) or independent system operators (ISOs). The relief responds to a petition filed by a group of RTOs and ISOs.

Congress directed the CFTC, when it is in the public interest, to provide relief from the Dodd-Frank Act's swaps market reform provisions for certain transactions on markets administered by RTOs and ISOs.

These entities were established for the purpose of providing affordable, reliable electricity to consumers within their geographic region. They are subject to extensive regulatory oversight by the Federal Energy Regulatory Commission (FERC), or in one instance, by the Public Utility Commission of Texas (PUCT). In addition, these markets administered by RTOs and ISOs are central to FERC and PUCT's regulatory missions to oversee wholesale sales and transmission of electricity.

The scope of the proposed relief extends to the petitioners for four categories of transactions—financial transmission rights, energy transactions, forward capacity transactions, and reserve or regulation transactions. Each of these transactions are inextricably linked to the physical delivery of electricity.

I look forward to receiving public comment on the proposed relief.

Footnotes

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).

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3.  7 U.S.C. 6(c)(3)(A)-(J).

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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.

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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.

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8.  See Petition at 2-3, 6.

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9.  See Petition at 2-4. See 16 Tex. Admin. Code 25.1 (1998).

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10.  See Petition at 2 n. 2.

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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.

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12.  See Petition at 3.

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13.  See id. at 2-3.

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14.  See id. at 11.

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15.  See id. at 3.

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16.  See id. at 3, 5-6.

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17.  See id. at 6.

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18.  See id.

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20.  Section 722(e) of the Dodd-Frank Act.

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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).

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23.  See 7 U.S.C. 2(a)(1)(I).

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24.  See 7 U.S.C. 2(a)(1)(I)(i) and (ii).

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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.

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26.  See 7 U.S.C. 6(c)(6).

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27.  See 7 U.S.C. 6(c)(6)(A) and (B).

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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.

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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.

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31.  See 7 U.S.C. 6(c)(2).

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32.  See Petition at 4.

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33.  See id. at 11.

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34.  Federal Power Act, 16 U.S.C. 791a et seq.

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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)).

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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.

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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)).

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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.' ”).

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42.  See FERC Order 888.

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43.  FERC Order 888 at 21541.

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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.

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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).

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46.  Public Utility Regulatory Act, TEX. UTIL. CODE ANN. 11.001 et seq. (Vernon 1998 & Supp. 2005).

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47.  16 Texas Admin. Code (“TAC”) 25.1 (1998).

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49.  See generally 16 TAC 25.501-25.507.

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50.  See generally id.

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51.  See generally id.

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52.  See generally 16 TAC 25.503.

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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.

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54.  Petition at 6.

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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).

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56.  See Petition at 7. See also section VIII. below.

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57.  See id. at 7. See also section VIII. below.

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58.  See id. at 6.

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59.  See id. at 7-8.

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60.  See id. at 7.

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61.  See id.

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62.  See id. at 7.

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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.

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64.  See id. at 8-9. See also section VIII. below.

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65.  See id. at 8.

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66.  See id. at 8-9.

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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.

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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.

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69.  See generally Petition at 20.

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70.  See id. at 3-4.

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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.

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72.  Petition at 15-18.

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73.  See id. at 6-9.

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74.  See the discussions in sections V.B., V.D., and V.E. below.

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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)).

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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)].”

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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.

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78.  See CEA 4(c)(2)(B)(i) and the discussion of CEA section 4(c)(3) below.

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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).

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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.

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81.  See Petition at 11.

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82.  See id.

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83.  See id. at 13.

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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).

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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.

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86.  See Petition at 14. See also 18 CFR 35.34(k)(2).

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87.  See generally Petition at 20.

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88.  See id. at 3-4.

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89.  See id. at 15-18.

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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”).

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91.  See appropriate persons discussion, below, section V.B.3.

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92.  See FERC Credit Reform Policy discussion, below, at section V.C.

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93.  See DCO core principle analysis below, at section V.D.; see also SEF core principle analysis below, at section V.E.

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94.  See appropriate persons analysis, below, at section V.B.3.

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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.”

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96.  CEA 4(c)(3)(K).

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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.”).

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98.  Petition at 26-27 (citations omitted).

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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.

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100.  Petition at 27 (citations omitted).

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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.

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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.”)

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103.  CEA 4(c)(2)(B).

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104.  See H.R. No. 978, 102d Cong. 2d Sess. 79 (1992).

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105.  See Petition at 28.

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106.  See id. at 28.

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107.  Nor did the Petitioners seek an exemption from these provisions. See id. at 2-3.

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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.

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109.  Final Rulemaking—Core Principles and Other Requirements for Designated Contract Markets, 72 FR 36612 (June 19, 2012).

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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”).

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111.  FERC Revised Order 741 at 10492-10493.

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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.

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114.  Id. at 65949.

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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).

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116.  FERC Original Order 741 at 65948.

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118.  See 17 CFR 39.14(b) (requiring daily settlements).

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119.  FERC Original Order 741 at 65946.

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120.  Id.

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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).

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125.  7 U.S.C. 7a-1(c)(2)(C).

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126.  Id.

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127.  FERC Original Order 741 at 65956.

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128.  Id.

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129.  Id.

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131.  FERC Original Order 741 at 65957.

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132.  7 U.S.C. 7a 1(c)(2)(D).

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133.  FERC Original Order 741 at 65958.

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134.  Id.

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135.  See infra text at n. 398.

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136.  7 U.S.C. 7a-1(c)(2)(A)(i).

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137.  7 U.S.C. 7a-1(c)(2)(A)(ii).

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138.  Petition Attachments at 1.

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139.  Id.

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140.  7 U.S.C. 7a-1(c)(2)(B)(i).

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141.  7 U.S.C. 7a-1(c)(2)(B)(ii).

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142.  See Petition Attachments at 3-20.

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143.  See, e.g., id. at. 4, 8-9, 10, 15, 20.

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144.  See id. at 4, 8, 10, 13, 15, 20.

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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).

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146.  See Petition Attachments at 10-11.

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147.  See, e.g., id. at 9, 13.

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148.  See, e.g., id. at 15.

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149.  See, e.g., id. at 9, 13.

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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.

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151.  See, e.g., id. at 4, 10, 16.

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152.  See, e.g., id. at 16, 20.

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153.  See id. at 4-20.

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154.  See id. at 16.

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155.  See id. at 3-20.

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156.  See generally FERC Order 888 at 21540.

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157.  P.U.C. SUBST. R. 25.361(b). See also Petition Attachments at 7-8.

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158.  Id. at 502.

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159.  See Petition Attachments at 3-20.

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160.  7 U.S.C. 7a-1(c)(2)(C).

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161.  Id.

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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.

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163.  See, supra n. 127 and accompanying text.

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164.  FERC Original Order 741 at 665955.

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166.  FERC Original Order 741 at 665956.

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167.  Id.

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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.

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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.”).

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170.  Id.

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171.  See Petition Attachments at 22-54.

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172.  See id. at 22-54.

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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).

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174.  See id. at 23, 35, 44-45.

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175.  See id. at 22, 35, 44.

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176.  See id. at 33.

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177.  See id. at 23, 37-38, 39, 48.

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178.  See id. at 23, 35-36, 38, 44-45, 49.

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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.

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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.

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181.  7 U.S.C. 7a-1(c)(2)(D).

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182.  7 U.S.C. 7a-1(c)(2)(D).

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183.  See Petition Attachments at 56-92.

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185.  FERC Original Order 741 at 65946.

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186.  Id.

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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.

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188.  See n. 126 and accompanying text.

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189.  See FERC Original Order 741 at 65946.

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190.  See FERC Order 741 Implementation Chart at 11-12.

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191.  Id.

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192.  See Petition Attachments at 56-92.

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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).

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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.

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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.

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196.  See supra at n. 115.

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197.  See FERC Order 741 Implementation Chart at 2-3.

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198.  See id. at 4-5.

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199.  See Petition Attachments at 56-92.

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200.  See FERC Order 741 Implementation Chart at 7.

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201.  See, e.g., Petition Attachments at 56-57, 69-70, 76-77.

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202.  FERC Original Order 741 at 65957.

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203.  See FERC Order 741 Implementation Chart.

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204.  FERC Original Order 741 at 65958.

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205.  Id. at 65958.

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206.  See Petition Attachments at 56-92.

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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.

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208.  See supra n. 122.

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209.  See FERC Order 741 Implementation Chart at 5-6.

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210.  A central counterparty is, within a particular market, the buyer to every seller and the seller to every buyer. See Principles for Financial Market Infrastructures ¶ 1.13 (CPSS-IOSCO 2012).

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211.  7 U.S.C. 7a-1(d)(92)(i)-(ii).

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212.  See Petition Attachments at 94-103.

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213.  Under these arrangements, the time between Operating Day and payment will be 13 days or less for all transactions in the Day-Ahead Market, and will be 15 days or less for 90% of transactions in the Real Time Market. See id. at 96.

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214.  See 17 CFR 39.14(b) (requiring daily settlements).

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215.  7 U.S.C. 7a-1(c)(2)(F).

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216.  See Petition Attachments at 105-110.

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217.  See id. at 105.

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218.  See id. at 108.

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219.  See id. at 105-110.

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220.  7 U.S.C. 7a-1(c)(2)(G)(i).

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221.  7 U.S.C. 7a-1(c)(2)(G)(ii).

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222.  See generally Petition Attachments at 112-126.

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223.  Id.

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224.  See supra at n. 149 and accompanying text. See also, e.g., Petition at 71.

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226.  7 U.S.C. 7a-1(c)(2)(H).

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227.  See generally, Petition Attachments at 128-150.

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228.  7 U.S.C. 7a-1(c)(2)(I)(i)-(ii).

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229.  7 U.S.C. 7a-1(c)(2)(I)(iii).

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230.  See generally Petition Attachments at 152-158.

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231.  See id. at 157.

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232.  See id.

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233.  See id.

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234.  See id. at 152, 156, 158.

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235.  7 U.S.C. 7a-1(c)(2)(J).

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236.  See g enerally Petition Attachments at 160-166.

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237.  See id. at 161-162. PURA 39.151(d), P.U.C. SUBST. R. 25.362(e)(1)(B) and 25.503(f)(8).

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238.  See Petition Attachments at 161-162.

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239.  See id.

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240.  7 U.S.C. 7a-1(c)(2)(K).

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241.  See generally Petition Attachments at 168-173.

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243.  See 18 CFR 125.3 at (6)-(9).

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244.  See Petition Attachments at 169.

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245.  7 U.S.C. 7a-1(c)(2)(L)(i)-(ii).

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246.  7 U.S.C. 7a-1(c)(2)(L)(iii).

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247.  See generally Petition Attachments at 175-182.

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248.  7 U.S.C. 7a-1(c)(2)(M).

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249.  See generally Petition Attachments at 184-190.

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250.  See id. at 186.

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251.  See id. at 188-189.

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252.  See id. at 185.

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253.  See id. at 184, 187, 190.

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254.  7 U.S.C. 7a-1(c)(2)(N).

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255.  See FERC Order No. 888; FERC Order No. 2000. Moreover, Petitioners represent that their rules are typically subject to advance review by stakeholders and must be approved by FERC (except for ERCOT whose rules are approved by PUCT). These rules are, in turn, subject to review by the MMU, who attempt to detect, among other things, detect market power abuses. See generally Petition Attachments at 192-198. With respect to ERCOT, TAC 25.361(i) expressly states that “The existence of ERCOT is not intended to affect the application of any state or federal anti-trust laws.” In addition, ERCOT represents that it conducts antitrust training for its employees annually, holds open meetings to promote the transparent development of market rules, established a Corporate Standard to addresses antitrust issues, and that “PURA, PUCT Substantive Rules and ERCOT Protocols also require that ERCOT allow access to the transmission system for all buyers and sellers of electricity on a nondiscriminatory basis, which facilitates actions consistent with the antitrust considerations of [DCO Core Principle N].” See Petition Attachments at 193-194.

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256.  See Petition Attachments at 192-198.

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257.  7 U.S.C. 7a-1(c)(2)(O)(i).

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258.  7 U.S.C. 7a-1(c)(2)(O)(ii).

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259.  See Petition Attachments at 200-208.

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260.  See id. at 200 (citing to FERC Order No. 888).

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261.  See Petition Attachments at 208 (citing to FERC Order No. 2000).

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262.  See id. at 202.

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263.  7 U.S.C. 7a-1(c)(2)(P)(i).

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264.  7 U.S.C. 7a-1(c)(2)(P)(ii).

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265.  See Petition Attachments at 210-216.

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266.  See id. at 210.

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267.  See id. at 211.

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268.  7 U.S.C. 7a-1(c)(2)(O).

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269.  See Petition Attachments at 219.

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270.  See id. at 218.

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271.  See id. at 221-223.

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272.  See 18 CFR 35.34(j)(1)(ii).

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273.  See 18 CFR 35.28(g)(6).

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274.  7 U.S.C. 7a-1(c)(2)(R).

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275.  See generally Petition Attachments at 225-235.

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276.  See id.

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277.  See the discussion in section V.D.4.g.

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279.  7 U.S.C. 7b-3(f)(2).

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280.  SEF Core Principle 2 also requires a SEF to establish rules governing the operation of the facility, including trading procedures, and provide rules that, when a swap is subject to the mandatory clearing requirement, hold swap dealers and major swap participants responsible for compliance with the mandatory trading requirement under section 2(h)(8) of the Act.

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281.  Petition Attachments at 238-245.

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282.  See id. at 130. See also id. at 239-240.

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283.  See id. at 129. See also id. at 239-240.

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284.  See id. at 128, 131-150. See also id. at 238, 241-245.

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285.  7 U.S.C. 7b-3(f)(3).

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286.  See Petition at 7.

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287.  See Petition Attachments at 252-253.

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288.  See id. at 142. See also id. at 253.

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289.  FERC Order on Compliance Filing to PJM, 139 FERC ¶ 61,057 issued April 19, 2012 in Docket No. ER09-1063-004.

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290.  See generally Petition Attachments at 124-147.

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291.  See generally id.

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292.  On March 9, 2012 Constellation Energy and FERC's Office of Enforcement entered into a Stipulation and Consent Agreement in which Constellation neither admitted nor denied wrongdoing. FERC initially alleged that Constellation manipulated the price of electricity using virtual and physically-settled transactions on the markets of ISO NE and NYISO to benefit non-ISO swap positions. After receiving two anonymous hotline tips, FERC was alerted to potentially problematic trading after detecting successive losses by Constellation in their virtual and physical bids on the NYISO. Constellation agreed to pay a fine of $135,000,000 and disgorge $110,000,000 in unjust profits. See Order approving stipulation and agreement, Docket No. IN12-7-000, 138 FERC ¶ 61,168.

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293.  See Petition at 126-150.

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294.  See generally Petition Attachments at 247-258.

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295.  See generally id. at 126-150.

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296.  See Petition at 6.

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297.  See, e.g., Petition Attachments at 252.

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298.  See generally Petition Attachments at 128-150.

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299.  See Petition at 7-9.

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300.  See Petition at 7-9.

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301.  7 U.S.C. 7b-3(f)(4).

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302.  See generally Petition Attachments at 260-269.

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303.  See generally id.

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304.  See id.

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305.  See id. at 2-20.

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306.  7 U.S.C. 7b-3(f)(5).

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307.  See generally the discussions in sections V.D.10. and V.D.13. supra.

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308.  See generally Petition Attachments at 271-276.

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309.  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.

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310.  See Petition at 18-21; see Petition Attachments at 285-291.

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311.  See Petition at 20; see, e.g., Petition Attachments at 22-24, 27, 33, 37.

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312.  See Petition at 20; see Petition Attachments at 22, 28, 35, 37, 44, 47-48.

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313.  See Petition at 20; see, e.g., Petition Attachments at 23, 27, 44, 50.

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314.  See Petition at 18; see, e.g., Petition Attachments at 22, 25, 30-31, 39-43, 283.

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315.  See Petition at 19. Such additional requirements include (a) limiting the amount of unsecured credit extended to any market participant to no more than $50 million; (b) adopting a billing period of no more than seven days and allowing a settlement period of no more than seven days; (c) eliminating unsecured credit in the financial transmission rights market; (d) establishing a single counterparty to all market participant transactions, or requiring each market participant to grant a security interest to the RTO or ISO in the receivables of its transactions, or providing another method of supporting netting; (e) limiting the time period by which a market participant must cure a collateral call to no more than two days; (f) requiring minimum participant criteria for market participants to be eligible to participate in the markets; and (g) requiring additional collateral due to a material adverse change. See 18 CFR 35.47.

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316.  See, e.g., Petition Attachments at 30. Some Petitioners required market participants to demonstrate and maintain certain minimum financial requirements including an investment-grade credit rating documented by reports of a credit reporting agency, tangible net-worth threshold, total asset threshold, a certain current ratio, or a certain debt to total capitalization ratio. See, e.g., Petition Attachments at 26, 33-34, 37, 43. In certain instances, the minimum financial standards for market participants are scalable to the RTO and ISO markets in which they participate. See, e.g., Petition Attachments at 26, 31. The proposed rule regarding minimum financial standards also requires at a minimum, that members qualify as an eligible contract participant as defined by the CEA. The Commission notes that ISO NE has represented that it has market participants that may not meet the definition of eligible contract participant, but are “appropriate persons” for purposes of the 4(c) exemption. See Petition Attachments at 30. The Commission proposes to condition the granting of the 4(c) request on all parties to the agreement, contract or transaction being “appropriate persons,” as defined sections 4(c)(3)(A) through (J) of the Act or “eligible contract participants” as defined in section 1a(18)(A) of the Act and in Commission regulation 1.3(m). See provision 2.B. of the Proposed Exemption.

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317.  See Petition at 18; see, e.g., Petition Attachments at 22, 31, 39.

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318.  See, e.g., Petition Attachments at 27, 30, 35, 84.

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319.  See Petition Attachments at 56-92.

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321.  See FERC Order 741 Implementation Chart at 5-6; See generally Petition at 19.

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322.  7 U.S.C. 7b-3(f)(8).

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323.  Core Principles and Other Requirements for Swap Execution Facilities, 76 FR 1229, proposed Jan. 7, 2011.

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324.  See Petition Attachments at 293-298.

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325.  See, e.g., id. at 293-295, 298.

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326.  See, e.g., id. at 296-297.

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327.  Petition Attachments at 293 (CAISO).

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328.  7 U.S.C. 7b-3f(9)(A).

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329.  7 U.S.C. 7b-3f(9)(B).

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330.  See Petition Attachments at 300-305.

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331.  See id. at 300, 302-305.

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332.  See id.

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333.  See Petition Attachments at 177-178.

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334.  7 U.S.C. 7b-3(f)(10).

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335.  See generally Petition at 307-312.

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336.  See, e.g., id. at 309.

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337.  See the discussions in sections V.D.10. and V.D.11. supra.

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338.  7 U.S.C. 7b-3(f)(11).

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339.  See FERC Order Nos. 888 and 2000. See also the discussion in section V.D.14. supra.

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340.  See generally Petition Attachments at 192-198.

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341.  See generally id.

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342.  See also the discussion in section V.D.14. supra.

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343.  7 U.S.C. 7b-3(f)(12).

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344.  See FERC Order No. 888 at 281.

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345.  See FERC Order No. 2000 at 709; 18 CFR 35.34(j)(1).

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346.  See Petition Attachments at 210, 213-216, 321, 324-326.

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347.  See id. at 211, 322.

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348.  See the discussion in section V.D.16. supra.

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349.  7 U.S.C. 7b-3(f)(13)(A).

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350.  7 U.S.C. 7b-3(f)(13)(B).

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351.  See Petition Attachments at 3-4, 6, 8-10, 13, 16, 20, 328-333.

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352.  See id. at 3, 7-8, 10, 13, 16, 18-19.

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353.  See supra n. 86 and accompanying text.

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354.  See Petition Attachments at 3, 7, 12, 13, 16-17, 18-19, 335-340. See also analysis under DCO Core Principle B.

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355.  See the discussion in section V.D.2. supra.

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356.  7 U.S.C. 7b-3(f)(14)(A).

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357.  7 U.S.C. 7b-3(f)(14)(B).

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358.  7 U.S.C. 7b-3(f)(14)(C).

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359.  See generally Petition Attachments at 152-158, 333-340.

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360.  See supra n. 230 and accompanying text.

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361.  See Petition Attachments at 152-158, 333-339.

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362.  See id. at 152, 155-157.

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363.  See id. at 153, 158. Certain Petitioners maintain alternate operational control centers in addition to offsite backup computer systems and data centers. See id. at 155-157.

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364.  See id. at 152, 154, 156, 158.

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365.  See also the discussion in section V.D.8. supra.

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366.  See 7 U.S.C. 7b-3(f)(15). designation of chief compliance officer.—

(A) IN GENERAL.—Each swap execution facility shall designate an individual to serve as a chief compliance officer.

(B) DUTIES.—The chief compliance officer shall—

(i) report directly to the board or to the senior officer of the facility;

(ii) review compliance with the core principles in this subsection;

(iii) in consultation with the board of the facility, a body performing a function similar to that of a board, or the senior officer of the facility, resolve any conflicts of interest that may arise;

(iv) be responsible for establishing and administering the policies and procedures required to be established pursuant to this section;

(v) ensure compliance with this Act and the rules and regulations issued under this Act, including rules prescribed by the Commission pursuant to this section; and

(vi) establish procedures for the remediation of noncompliance issues found during compliance office reviews, look backs, internal or external audit findings, self-reported errors, or through validated complaints.

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367.  See Petition Attachments at 342-346.

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368.  PJM has two compliance heads who coordinate closely but are separately responsible for compliance in the following two distinct areas: (1) compliance with regulatory and legal obligations; and (2) compliance with reliability standards as promulgated by the regional reliability counsels, NERC and FERC. Regulatory and legal compliance addresses legal obligations, including compliance with the PJM Tariff, FERC regulations and laws, and regulations governing other corporate matters, such as antitrust, human resources and procurement. Regulatory and legal compliance is handled in the Office of General Counsel, by an Assistant General Counsel and Director of Regulatory Oversight and Compliance. Reliability compliance addresses the security of the grid, both operationally and from any cyber threat. This function is handled in the area of operations and the Executive Director of Reliability and Compliance reports directly to the senior vice president for operations. All compliance functions (both reliability and regulatory) are coordinated through PJM's Regulatory Oversight & Compliance Committee (“ROCC”). The ROCC is chaired by the Assistant General Counsel who has reporting obligations to the CEO and a direct line to the Board's Governance Committee and Audit Committee. See Petition Attachments at 347.

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370.  17 CFR 23.410(a)-(b), 32.4 and part 180.

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372.  See Petition at 33-34. Petitioners requested relief from “all provisions of the Act and Commission regulations, except in each case sections 4b, 4 o, 6(c) and 9(a)(3) of the Act to the extent that these sections prohibit fraud in connection with transactions subject to the Act, or manipulation of the price of any swap or contract for the sale of a commodity in interstate commerce or for future delivery on or subject to the rules of a registered entity, and from the requirement to provide information to the Commission as expressly permitted by their respective protocols or as provided under section 720 of the Dodd-Frank Wall Street Reform and Consumer Protection Act.” The Proposed Exemption simply would preserve the Commission's authority under the delineated provisions and their implementing regulations without caveat, in order to avoid ambiguity as to what conduct remains prohibited.

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373.  See, e.g., Order (1) Pursuant to Section 4(c) of the Commodity Exchange Act, Permitting the Kansas City Board of Trade Clearing Corporation To Clear Over-the-Counter Wheat Calendar Swaps and (2) Pursuant to Section 4d of the Commodity Exchange Act, Permitting Customer Positions in Such Cleared-Only Swaps and Associated Funds To Be Commingled With Other Positions and Funds Held in Customer Segregated Accounts, 75 FR 34983, 34985 (2010).

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374.  Petition at 5-9.

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375.  Id. at 6.

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376.  Id. at 9.

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378.  For example, the transactions that included with the scope of the Proposed Exemption appear to be limited to those tied to the physical capacity of the Petitioners' electricity grids. Petition at 6-8, 11.

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379.  The Commission is currently reviewing two supplemental petitions. Specifically, ISO NE has filed a supplemental request for an exemption pursuant to section 4(c)(6) for “IBT” Transactions. See In the Matter of the Application for an Exemptive Order Under Section 4(c) of the Commodity Exchange Act by ISO New England Inc. (Apr. 30, 2012), available at http://www.cftc.gov/stellent/groups/public/@requestsandactions/documents/ifdocs/iso-ne4crequest.pdf. CAISO has filed a similar request for “inter-scheduling coordinator trades” or “inter-SC trades.” See In the Matter of the Application for an Exemptive Order Under Section 4(c) of the Commodity Exchange Act by California Independent System Operator Corporation (May 30, 2012), available at http://www.cftc.gov/stellent/groups/public/@requestsandactions/documents/ifdocs/caiso4crequest.pdf.

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380.  7 U.S.C. 6(c)(3)(A)-(J).

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385.  See discussion in section V.B.3. supra.

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386.  See the discussion in section V.A. supra.

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387.  Petition at 2-3.

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388.  CAISO, ERCOT, ISO NE., MISO, NYSO and PJM.

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389.  The Requestors note that it is “reasonable to expect that each ISO/RTO will, over time, consider offering under its own individual tariff one or more classes of contract, agreement and transaction that is currently offered under any other ISO/RTO tariff,” and accordingly request that exemption be granted to all requestors for transactions that are currently offered by any of them. Petition at 6.

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390.  See Petition at 2.

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391.  See Petition at 6:

“While the ISOs/RTOs operate pursuant to individual tariffs, they share many commonalities in their markets and operations. Although the current market structures of the individual ISOs/RTOs may vary, it is reasonable to expect that each ISO/RTO will, over time, consider offering under its own individual tariff one or more classes of contract, agreement or transaction that is currently offered under any other ISO/RTO tariff. We thus request that each individual exemptive Order apply collectively to each class of contract, agreement or transaction provided by the ISOs/RTOs. This will provide the appropriate breadth to the exemptive Order so that an individual Requestor will not be required to seek future amendments to offer or enter into contracts, agreements or transactions that are currently offered by any other Requestor.”

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392.  Section 4(c) permits the Commission to issue an exemption “on its own initiative or on application of any person.” 7 U.S.C. 4(c)(1).

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393.  See In the Matter of the Application for an Exemptive Order Under Section 4(c) of the Commodity Exchange Act by ISO New England Inc. (Apr. 30, 2012), available at http://www.cftc.gov/stellent/groups/public/@requestsandactions/documents/ifdocs/iso-ne4crequest.pdf. CAISO has filed a similar request for “inter-scheduling coordinator trades” or “inter-SC trades.” See In the Matter of the Application for an Exemptive Order Under Section 4(c) of the Commodity Exchange Act by California Independent System Operator Corporation (May 30, 2012), available at http://www.cftc.gov/stellent/groups/public/@requestsandactions/documents/ifdocs/caiso4crequest.pdf.

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395.  See Petition Attachments at 1.

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397.  See generally FERC Order 741 Implementation Chart.

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398.  See, e.g., FERC Order 741 Implementation Chart at 6 (stating that ISO NE submitted a package of tariff changes with FERC to establish itself as the central counterparty for market participant transactions. The filing was made with a requested effective date of January 1, 2013).

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400.  See text at n. 122 and text at n. 208 supra.

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401.  The Commission also notes that not all of the central counterparty arrangements proposed by Petitioners have been approved by their respective regulators and/or become effective and, accordingly, are potentially subject to change. See, e.g., FERC Order 741 Implementation Chart at 5-6.

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402.  Petition Attachments at 28.

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403.  FERC MOU (Oct. 12, 2005) available at http://www.ferc.gov/legal/maj-ord-reg/mou/mou-33.pdf.

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404.  Petition at 25.

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405.  Id. at 25-26.

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406.  Id. at 26.

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407.  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 (“CAISO”); 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. (“ERCOT”); In the Matter of the Petition for an Exemptive Order Under Section 4(c) of the Commodity Exchange Act by ISO New England Inc. (“ISO NE”); 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. (“MISO”); 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. (“NYISO”); 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. (“PJM”) (Feb. 7, 2012, as amended June 11, 2012).

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409.  Under CEA section 2(e), only ECPs are permitted to participate in a swap subject to the end-user clearing exception.

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410.  See Opting Out of Segregation, 66 FR 20740 at 20743, Apr. 25, 2001.

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411.  See RFA analysis as conducted by FERC regarding the 5 Petitioners, CAISO, NYISO, PJM, MISO and ISO NE., https://www.federalregister.gov/articles/2011/10/26/2011-27626/enhancement-of-electricity-market-surveillance-and-analysis-through-ongoing-electronic-delivery-of#h-17.

Commission staff also performed an independent RFA analysis based on Subsector 221 of Sector 22 (utilities companies) which defines any small utility corporation as one that does not generate more than 4 million of megawatts of electricity per year, and Subsector 523 of Sector 52 (Securities, Commodity Contracts, and Other Financial Investments and Related Activities) of the SBA, 13 CFR 121.201 (1-1-11 Edition), which identifies a small business size standard of $7 million or less in annual receipts. Staff concludes that none of the Petitioners is a small entity, based on the following information:

MISO reports 594 million megawatt hours per year, https://www.midwestiso.org/Library/Repository/Communication%20Material/Corporate/Corporate%20Fact%20Sheet.pdf;

ERCOT reports 335 million megawatt hours per year, http://www.ercot.com/content/news/presentations/2012/ERCOT_Quick_Facts_June_%202012.pdf;

CAISO reports 200 million megawatts per year, http://www.caiso.com/Documents/CompanyInformation_Facts.pdf;

NYISO reports 17 million megawatts per month, which calculates to 204 megawatts per year, http://www.nyiso.com/public/about_nyiso/nyisoataglance/index.jsp;

PJM reports $35.9 billion billed in 2011, http://pjm.com/markets-and-operations.aspx; and

ISO NE reports 32,798 gigawatt hours in the first quarter of 2011, which translates into almost 33 million megawatts for the first quarter of 2011, http://www.iso-ne.com/markets/mkt_anlys_rpts/qtrly_mktops_rpts/2012/imm_q1_2012_qmr_final.pdf.

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412.  See A New Regulatory Framework for Clearing Organizations, 66 FR 45604, 45609, Aug. 29, 2001(DCOs); Policy Statement and Establishment of Definitions of “Small Entities” for Purposes of the Regulatory Flexibility Act, 47 FR 18618, 18618-18619, Apr. 30, 1982 (DCMs).

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414.  See, e.g., In re Semcrude, 399 B.R. 388, 393 (Bank. D. Del. 2009) (stating that “debts are considered `mutual' only when `they are due to and from the same persons in the same capacity.' ”).

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415.  See 75 FR at 65955.

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416.  The Court in Laffey v. Northwest Airlines, Inc., 572 F.Supp. 354, 371 (D.D.C. 1983) ruled that hourly rates for attorneys practicing civil law in the Washington, DC metropolitan area could be categorized by years in practice and adjusted yearly for inflation. For 2012 Laffey Matrix rates, see http://www.justice.gov/usao/dc/divisions/civil_Laffey_Matrix_2003-2012.pdf.

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417.  There are possibilities of economies of scale if multiple Petitioners share the same counsel in preparing these memoranda or opinions.

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[FR Doc. 2012-20965 Filed 8-27-12; 8:45 am]

BILLING CODE P