Vol. 77 Tuesday, 

No. 167 August 28, 2012 

Part II 

Commodity Futures Trading Commission 

Proposed Order and Request for Comment on a Petition From Certain 

Independent System Operators and Regional Transmission Organizations 

To Exempt Specified Transactions Authorized by a Tariff or Protocol 

Approved by the Federal Energy Commission or the Public Utility 

Commission of Texas From Certain Provisions of the Commodity Exchange 

Act; Notice 


srobinson on DSK4SPTVN1PROD with NOTICES2
52138 Federal Register / Vol. 77, No. 167 / Tuesday, August 28, 2012 / Notices 

1 In the Matter of the Petition for an Exemptive 

Order Under Section 4(c) of the Commodity 

Exchange Act by California Independent Service 

Operator Corporation; In the Matter of the Petition 

for an Exemptive Order Under Section 4(c) of the 

Commodity Exchange Act by the Electric Reliability 

Council of Texas, Inc.; In the matter of the Petition 

for an Exemptive Order Under Section 4(c) of the 

Commodity Exchange Act by ISO New England 

Inc.; In the Matter of the Petition for an Exemptive 

Order Under Section 4(c) of the Commodity 

Exchange Act by Midwest Independent 

Transmission System Operator, Inc.; In the Matter 

of the Petition for an Exemptive Order Under 

Section 4(c) of the Commodity Exchange Act by 

New York Independent System Operator, Inc.; and 

In the Matter of the Petition for an Exemptive Order 

Under Section 4(c) of the Commodity Exchange Act 

by PJM Interconnection, L.L.C. (Feb. 7, 2012, as 

amended June 11, 2012). 

2 7 U.S.C. 1 et seq. 

3 7 U.S.C. 6(c)(3)(A)–(J). 

4 7 U.S.C. 1a(18). ‘‘Further Definition of ‘Swap 

Dealer,’ ‘Security-Based Swap Dealer,’ ‘Major Swap 

Participant,’ ‘Major Security-Based Swap 

Participant’ and ‘Eligible Contract Participant,’ ’’ 77 

FR 30596, May 23, 2012. 

5 7 U.S.C. 6(c)(6). 

COMMODITY FUTURES TRADING 

COMMISSION 

Proposed Order and Request for 

Comment on a Petition From Certain 

Independent System Operators and 

Regional Transmission Organizations 

To Exempt Specified Transactions 

Authorized by a Tariff or Protocol 

Approved by the Federal Energy 

Commission or the Public Utility 

Commission of Texas From Certain 

Provisions of the Commodity 

Exchange Act 

AGENCY: Commodity Futures Trading 

Commission. 

ACTION: Notice of Proposed Order and 

Request for Comment. 

SUMMARY: The Commodity Futures 

Trading Commission (‘‘CFTC’’ or 

‘‘Commission’’) is requesting comment 

on a proposed exemption (the 

‘‘Proposed Exemption’’) issued in 

response to a consolidated petition 

(‘‘Petition’’) 1 from certain regional 

transmission organizations (‘‘RTOs’’) 

and independent system operators 

(‘‘ISOs’’) (collectively, ‘‘Petitioners’’) to 

exempt specified transactions from the 

provisions of the Commodity Exchange 

Act (‘‘CEA’’ or ‘‘Act’’) 2 and Commission 

regulations. The Proposed Exemption 

would exempt the contracts, agreements 

and transactions for the purchase or sale 

of the limited electricity-related 

products that are specifically described 

within the proposed order from the 

provisions of the CEA and Commission 

regulations, with the exception of 

sections 2(a)(1)(B), 4b, 4c(b), 4o, 

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 


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Federal Register / Vol. 77, No. 167 / Tuesday, August 28, 2012 / Notices 52139 

6 7 U.S.C. 6(c)(6). 

7See 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. 

8See Petition at 2–3, 6. 

9See Petition at 2–4. See 16 Tex. Admin. Code 

25.1 (1998). 

10See Petition at 2 n. 2. 

11See FERC Order 888 Promoting Wholesale 

Competition Through Open Access NonDiscriminatory Transmission Facilities (‘‘FERC 

Order 888’’), 61 FR 21540, April 24, 1996; See 

Petition at 2 n.2, 3. 

12See Petition at 3. 

13See id. at 2–3. 

14See id. at 11. 

15See id. at 3. 

16See id. at 3, 5–6. 

17See id. at 6. 

18See id. 

19 7 U.S.C. 1 et seq. 

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

21See 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). 

22 7 U.S.C. 2(a)(1)(A). 

23See 7 U.S.C. 2(a)(1)(I). 

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

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, nondiscriminatory 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, 4o, 

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 FERCor 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 


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52140 Federal Register / Vol. 77, No. 167 / Tuesday, August 28, 2012 / Notices 

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. 

26See 7 U.S.C. 6(c)(6). 

27See 7 U.S.C. 6(c)(6)(A) and (B). 

28Section 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. 

29Section 4(c)(2), 7 U.S.C. 6(c)(2), states: 

The Commission shall not grant any exemption 

* * * from any of the requirements of subsection 

(a) unless the Commission determines that (A) the 

requirement should not be applied to the 

agreement, contract, or transaction for which the 

exemption is sought and that the exemption would 

be consistent with the public interest and the 

purposes of this Act; and (B) the agreement, 

contract, or transaction— 

(i) Will be entered into solely between 

appropriate persons; and 

(ii) Will not have a material adverse effect on the 

ability of the Commission or any contract market to 

discharge its regulatory or self-regulatory duties 

under this Act. 

30 7 U.S.C. 6(a). 

31See 7 U.S.C. 6(c)(2). 

32See Petition at 4. 

33See id. at 11. 

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

35The 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)). 

36See 42 U.S.C. 7172. 

37See FERC Strategic Plan for Fiscal Years 2009– 

2014, 3 (Feb. 2012), http://www.ferc.gov/about/

strat-docs/FY-09-14-strat-plan-print.pdf. 

38 Id. 

39 Id. 

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 selfregulatory 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 


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Federal Register / Vol. 77, No. 167 / Tuesday, August 28, 2012 / Notices 52141 

40The 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)). 

41See 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.’ ’’). 

42See FERC Order 888. 

43FERC Order 888 at 21541. 

44FERC 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. 

45See, 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). 

46Public Utility Regulatory Act, TEX. UTIL. 

CODE ANN. 11.001 et seq. (Vernon 1998 & Supp. 

2005). 

47 16 Texas Admin. Code (‘‘TAC’’) 25.1 (1998). 

48 Id. 

49See generally 16 TAC 25.501–25.507. 

50See generally id. 

51See generally id. 

52See generally 16 TAC 25.503. 

53See 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. 54Petition at 6. 55Each 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). 

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 nondiscriminatory 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 demandresponse.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’’ 


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

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

58See id. at 6. 

59See id. at 7–8. 

60See id. at 7. 

61See id. 

62See id. at 7. 

63See 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. 

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

65See id. at 8. 

66See id. at 8–9. 

67That 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. 

68As 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. 

69See generally Petition at 20. 

70See id. at 3–4. 

71See generally FERC Order 888; FERC Order 

2000; 18 CFR 35.34(k)(2); and TAC 25.1. See also 

Petition at 11, 13–14. 

72Petition at 15–18. 

73See id. at 6–9. 

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

V.E. below. 

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 cashsettled 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. 


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75The 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)). 

76CEA 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)].’’ 

77Section 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. 

78See CEA 4(c)(2)(B)(i) and the discussion of CEA 

section 4(c)(3) below. 79CEA 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). 

80Section 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. 

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. 


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81See Petition at 11. 

82See id. 

83See id. at 13. 

84See 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). 

85See 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. 

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

87See generally Petition at 20. 

88See id. at 3–4. 

89See id. at 15–18. 

90See 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’’). 

91See appropriate persons discussion, below, 

section V.B.3. 

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 


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92See FERC Credit Reform Policy discussion, 

below, at section V.C. 

93See DCO core principle analysis below, at 

section V.D.; see also SEF core principle analysis 

below, at section V.E. 

94See appropriate persons analysis, below, at 

section V.B.3. 

95CEA 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.’’ 

96CEA 4(c)(3)(K). 

97According 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.’’). 

98Petition at 26–27 (citations omitted). 

99The 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. 

100Petition at 27 (citations omitted). 

101See CEA 1(a)(12). See also ‘‘Further Definition 

of ‘Swap Dealer,’ ‘Security-Based Swap Dealer,’ 

‘Major Swap Participant,’ ‘Major Security-Based 

Continued 

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 


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Swap Participant’ and ‘Eligible Contract 

Participant,’ ’’ 77 FR 30596, May 23, 2012. 

102See 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.’’) 

103CEA 4(c)(2)(B). 

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

(1992). 

105See Petition at 28. 

106See id. at 28. 

107Nor did the Petitioners seek an exemption 

from these provisions. See id. at 2–3. 

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 interagency 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), 4o, 

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 


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108The 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. 

109Final Rulemaking—Core Principles and Other 

Requirements for Designated Contract Markets, 72 

FR 36612 (June 19, 2012). 

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’’). 

111FERC Revised Order 741 at 10492–10493. 

112 18 CFR 35.47(c). 

113Specifically, FERC stated that ‘‘the risk 

associated with the potentially rapidly changing 

value of FTRs warrants adoption of risk 

management measures, including the elimination of 

unsecured credit. Because financial transmission 

rights have a longer-dated obligation to perform 

which can run from a month to a year or more, they 

have unique risks that distinguish them from other 

wholesale electric markets, and the value of a 

financial transmission right depends on 

unforeseeable events, including unplanned outages 

and unanticipated weather conditions. Moreover, 

financial transmission rights are relatively illiquid, 

adding to the inherent risk in their valuation.’’ 

FERC Original Order 741 at 65950. 

114 Id. at 65949. 

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). 116FERC Original Order 741 at 65948. 117 18 CFR 35.47(b). 118See 17 CFR 39.14(b) (requiring daily 

settlements). 119FERC Original Order 741 at 65946. 

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-thecounter positions and transactions in 

the underlying commodity and to 

provide such data to the Commission 

upon demand. Likewise, recentlyadopted 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 


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120 Id. 

121 18 CFR 35.47(d). 

122See 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). 

123 18 CFR 35.47(e). 

124 18 CFR 35.47(f). 

125 7 U.S.C. 7a–1(c)(2)(C). 

126 Id. 

127FERC Original Order 741 at 65956. 

128 Id. 

129 Id. 

130 18 CFR 35.47(g). 

131FERC Original Order 741 at 65957. 

132 7 U.S.C. 7a 1(c)(2)(D). 

133FERC Original Order 741 at 65958. 

134 Id. 

135See infra text at n. 398. 

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. 


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136 7 U.S.C. 7a–1(c)(2)(A)(i). 

137 7 U.S.C. 7a–1(c)(2)(A)(ii). 

138Petition Attachments at 1. 

139 Id. 

140 7 U.S.C. 7a–1(c)(2)(B)(i). 

141 7 U.S.C. 7a–1(c)(2)(B)(ii). 

142See Petition Attachments at 3–20. 

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

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

145See 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). 

146See Petition Attachments at 10–11. 

147See, e.g., id. at 9, 13. 

148See, e.g., id. at 15. 

149See, e.g., id. at 9, 13. 

150See 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. 

151See, e.g., id. at 4, 10, 16. 

152See, e.g., id. at 16, 20. 

153See id. at 4–20. 

154See id. at 16. 

155See id. at 3–20. 

156See generally FERC Order 888 at 21540. 

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 nondefaulting 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 nondefaulting 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 


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52150 Federal Register / Vol. 77, No. 167 / Tuesday, August 28, 2012 / Notices 

157P.U.C. SUBST. R. 25.361(b). See also Petition 

Attachments at 7–8. 

158 Id. at 502. 

159See Petition Attachments at 3–20. 

160 7 U.S.C. 7a–1(c)(2)(C). 

161 Id. 

162 Id. As set forth above, the exemption that 

would be provided by the Proposed Exemption 

would be available only with respect to the 

transactions specifically delineated therein. 

Accordingly, the DCO Core Principle C analysis is 

limited to a discussion of the Petitioners’ 

participant eligibility requirements. 

163See, supra n. 127 and accompanying text. 

164FERC Original Order 741 at 665955. 

165 18 CFR 35.47(f). 

166FERC Original Order 741 at 665956. 

167 Id. 

168Although 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. 

169See 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.’’). 

170 Id. 

171See Petition Attachments at 22–54. 

172See id. at 22–54. 

173See, 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). 

174See id. at 23, 35, 44–45. 

175See id. at 22, 35, 44. 

176See id. at 33. 

177See id. at 23, 37–38, 39, 48. 

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

179For 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. 

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


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Federal Register / Vol. 77, No. 167 / Tuesday, August 28, 2012 / Notices 52151 

180See 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/isorto4cappfercchart.pdf. 

181 7 U.S.C. 7a–1(c)(2)(D). 

182 7 U.S.C. 7a–1(c)(2)(D). 

183See Petition Attachments at 56–92. 

184 18 CFR 35.47(b). 185FERC Original Order 741 at 65946. 186 Id. 187See 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. 188See n. 126 and accompanying text. 189See FERC Original Order 741 at 65946. 190See FERC Order 741 Implementation Chart at 

11–12. 

191 Id. 

192See Petition Attachments at 56–92. 

193See 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). 

194A 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. 

195The 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 

Continued 

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 riskbased 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) 


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52152 Federal Register / Vol. 77, No. 167 / Tuesday, August 28, 2012 / Notices 

all times to meet each separate credit requirement. 

See id. at 84. 196See supra at n. 115. 197See FERC Order 741 Implementation Chart at 

2–3. 

198See id. at 4–5. 

199See Petition Attachments at 56–92. 

200See FERC Order 741 Implementation Chart at 

7. 

201See, e.g., Petition Attachments at 56–57, 69– 

70, 76–77. 

202FERC Original Order 741 at 65957. 

203See FERC Order 741 Implementation Chart. 

204FERC Original Order 741 at 65958. 

205 Id. at 65958. 

206See Petition Attachments at 56–92. 

207For 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. 

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 RiskBased 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 


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208See supra n. 122. 

209See FERC Order 741 Implementation Chart at 

5–6. 

210A 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). 

211 7 U.S.C. 7a–1(d)(92)(i)–(ii). 212See Petition Attachments at 94–103. 213Under 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. 214See 17 CFR 39.14(b) (requiring daily 

settlements). 215 7 U.S.C. 7a–1(c)(2)(F). 

216See Petition Attachments at 105–110. 

217See id. at 105. 

218See id. at 108. 

219See id. at 105–110. 

220 7 U.S.C. 7a–1(c)(2)(G)(i). 

221 7 U.S.C. 7a–1(c)(2)(G)(ii). 

222See generally Petition Attachments at 112– 

126. 

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 setoff 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 onehundred 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 


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223 Id. 

224See supra at n. 149 and accompanying text. 

See also, e.g., Petition at 71. 

225See 11 U.S.C. 553. 

226 7 U.S.C. 7a–1(c)(2)(H). 

227See generally, Petition Attachments at 128– 

150. 

228 7 U.S.C. 7a–1(c)(2)(I)(i)–(ii). 

229 7 U.S.C. 7a–1(c)(2)(I)(iii). 

230See generally Petition Attachments at 152– 

158. 

231See id. at 157. 

232See id. 

233See id. 

234See id. at 152, 156, 158. 

235 7 U.S.C. 7a–1(c)(2)(J). 

236See generally Petition Attachments at 160– 

166. 

237See id. at 161–162. PURA 39.151(d), P.U.C. 

SUBST. R. 25.362(e)(1)(B) and 25.503(f)(8). 

238See Petition Attachments at 161–162. 

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 wellestablished 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 


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239See id. 

240 7 U.S.C. 7a–1(c)(2)(K). 

241See generally Petition Attachments at 168– 

173. 

242See 18 CFR 125.2–.3. 

243See 18 CFR 125.3 at (6)–(9). 

244See Petition Attachments at 169. 

245 7 U.S.C. 7a–1(c)(2)(L)(i)–(ii). 

246 7 U.S.C. 7a–1(c)(2)(L)(iii). 

247See generally Petition Attachments at 175– 

182. 

248 7 U.S.C. 7a–1(c)(2)(M). 

249See generally Petition Attachments at 184– 

190. 

250See id. at 186. 

251See id. at 188–189. 

252See id. at 185. 

253See id. at 184, 187, 190. 

254 7 U.S.C. 7a–1(c)(2)(N). 

255See 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 

Continued 

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 marginsetting 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 


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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. 

256See Petition Attachments at 192–198. 

257 7 U.S.C. 7a–1(c)(2)(O)(i). 

258 7 U.S.C. 7a–1(c)(2)(O)(ii). 

259See Petition Attachments at 200–208. 

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

261See Petition Attachments at 208 (citing to 

FERC Order No. 2000). 

262See id. at 202. 

263 7 U.S.C. 7a–1(c)(2)(P)(i). 

264 7 U.S.C. 7a–1(c)(2)(P)(ii). 

265See Petition Attachments at 210–216. 

266See id. at 210. 

267See id. at 211. 

268 7 U.S.C. 7a–1(c)(2)(O). 

269See Petition Attachments at 219. 

270See id. at 218. 

271See id. at 221–223. 

272See 18 CFR 35.34(j)(1)(ii). 

273See 18 CFR 35.28(g)(6). 

274 7 U.S.C. 7a–1(c)(2)(R). 

275See generally Petition Attachments at 225– 

235. 

276See id. 

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 


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

278 7 U.S.C. 7b–3(f)(1) 

279 7 U.S.C. 7b–3(f)(2). 

280SEF 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. 

281Petition Attachments at 238–245. 

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

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

284See id. at 128, 131–150. See also id. at 238, 

241–245. 

285 7 U.S.C. 7b–3(f)(3). 

286See Petition at 7. 

287See Petition Attachments at 252–253. 

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

289FERC Order on Compliance Filing to PJM, 139 

FERC ¶ 61,057 issued April 19, 2012 in Docket No. 

ER09–1063–004. 

290See generally Petition Attachments at 124– 

147. 

291See generally id. 

292On 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 nonISO 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. 

293See Petition at 126–150. 

294See generally Petition Attachments at 247– 

258. 

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 physicallydelivered 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 RealTime 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 DayAhead 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 RealTime 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 selfinterest 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 


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295See generally id. at 126–150. 

296See Petition at 6. 

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

298See generally Petition Attachments at 128– 

150. 

299See Petition at 7–9. 

300See Petition at 7–9. 

301 7 U.S.C. 7b–3(f)(4). 

302See generally Petition Attachments at 260– 

269. 

for manipulative behavior and market 

power, as well as market flaws (such as 

persistent non-convergence of DayAhead 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 DayAhead 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 DayAhead 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 


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303See generally id. 

304See id. 

305See id. at 2–20. 

306 7 U.S.C. 7b–3(f)(5). 

307See generally the discussions in sections 

V.D.10. and V.D.13. supra. 

308See generally Petition Attachments at 271– 

276. 

309Further Definition of ‘Swap Dealer,’ ‘SecurityBased Swap Dealer,’ ‘Major Swap Participant,’ 

‘Major Security-Based Swap Participant’ and 

‘Eligible Contract Participant,’ 77 FR 30596, May 

23, 2012. 

310See Petition at 18–21; see Petition 

Attachments at 285–291. 

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 DoddFrank 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 


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52160 Federal Register / Vol. 77, No. 167 / Tuesday, August 28, 2012 / Notices 

311See Petition at 20; see, e.g., Petition 

Attachments at 22–24, 27, 33, 37. 

312See Petition at 20; see Petition Attachments at 

22, 28, 35, 37, 44, 47–48. 

313See Petition at 20; see, e.g., Petition 

Attachments at 23, 27, 44, 50. 

314See Petition at 18; see, e.g., Petition 

Attachments at 22, 25, 30–31, 39–43, 283. 

315See 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. 

316See, e.g., Petition Attachments at 30. Some 

Petitioners required market participants to 

demonstrate and maintain certain minimum 

financial requirements including an investmentgrade 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. 

317See Petition at 18; see, e.g., Petition 

Attachments at 22, 31, 39. 

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

84. 

319See Petition Attachments at 56–92. 

320 18 CFR 35.47(d). 

321See FERC Order 741 Implementation Chart at 

5–6; See generally Petition at 19. 

322 7 U.S.C. 7b–3(f)(8). 

323Core Principles and Other Requirements for 

Swap Execution Facilities, 76 FR 1229, proposed 

Jan. 7, 2011. 

324See Petition Attachments at 293–298. 

325See, e.g., id. at 293–295, 298. 

326See, e.g., id. at 296–297. 

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 setoff 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 


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327Petition Attachments at 293 (CAISO). 

328 7 U.S.C. 7b–3f(9)(A). 

329 7 U.S.C. 7b–3f(9)(B). 

330See Petition Attachments at 300–305. 

331See id. at 300, 302–305. 

332See id. 

333See Petition Attachments at 177–178. 

334 7 U.S.C. 7b–3(f)(10). 

335See generally Petition at 307–312. 

336See, e.g., id. at 309. 

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

V.D.11. supra. 

338 7 U.S.C. 7b–3(f)(11). 

339See FERC Order Nos. 888 and 2000. See also 

the discussion in section V.D.14. supra. 

340See generally Petition Attachments at 192– 

198. 

341See generally id. 

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

supra. 

343 7 U.S.C. 7b–3(f)(12). 

344See FERC Order No. 888 at 281. 

345See FERC Order No. 2000 at 709; 18 CFR 

35.34(j)(1). 

346See Petition Attachments at 210, 213–216, 

321, 324–326. 

347See id. at 211, 322. 

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

349 7 U.S.C. 7b–3(f)(13)(A). 

350 7 U.S.C. 7b–3(f)(13)(B). 

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 


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52162 Federal Register / Vol. 77, No. 167 / Tuesday, August 28, 2012 / Notices 

351See Petition Attachments at 3–4, 6, 8–10, 13, 

16, 20, 328–333. 

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

353See supra n. 86 and accompanying text. 

354See Petition Attachments at 3, 7, 12, 13, 16– 

17, 18–19, 335–340. See also analysis under DCO 

Core Principle B. 

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

356 7 U.S.C. 7b–3(f)(14)(A). 

357 7 U.S.C. 7b–3(f)(14)(B). 

358 7 U.S.C. 7b–3(f)(14)(C). 

359See generally Petition Attachments at 152– 

158, 333–340. 

360See supra n. 230 and accompanying text. 

361See Petition Attachments at 152–158, 333– 

339. 

362See id. at 152, 155–157. 

363See 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. 

364See id. at 152, 154, 156, 158. 

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

supra. 

366See 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. 

367See Petition Attachments at 342–346. 

368PJM 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. 

369 7 U.S.C. 6(c). 

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 


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370 17 CFR 23.410(a)–(b), 32.4 and part 180. 371 17 CFR part 180. 372See Petition at 33–34. Petitioners requested 

relief from ‘‘all provisions of the Act and 

Commission regulations, except in each case 

sections 4b, 4o, 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. 

373See, 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). 

374Petition at 5–9. 

375 Id. at 6. 

376 Id. at 9. 377 7 U.S.C. 6(c). 378For 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. 

379The 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. 

380 7 U.S.C. 6(c)(3)(A)–(J). 

381 7 U.S.C. 1a(18). 

382 17 CFR 1.3(m). 

383 7 U.S.C. 6(c). 

384 7 U.S.C. 6(c)(3). 

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

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), 4o, 

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 antifraud 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 


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52164 Federal Register / Vol. 77, No. 167 / Tuesday, August 28, 2012 / Notices 

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

387Petition at 2–3. 

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

PJM. 

389The 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. 

390See Petition at 2. 

391See 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.’’ 

392Section 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). 

393See 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. 

394 18 CFR 35.47. 

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 expresslyidentified 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 


srobinson on DSK4SPTVN1PROD with NOTICES2
Federal Register / Vol. 77, No. 167 / Tuesday, August 28, 2012 / Notices 52165 

395See Petition Attachments at 1. 

396 18 CFR 35.47. 

397See generally FERC Order 741 Implementation 

Chart. 

398See, 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). 

399See 11 U.S.C. 553. 

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

401The 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. 

402Petition Attachments at 28. 

403FERC MOU (Oct. 12, 2005) available at 

http://www.ferc.gov/legal/maj-ord-reg/mou/mou33.pdf. 

404Petition at 25. 

405 Id. at 25–26. 

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 wellreasoned 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 


srobinson on DSK4SPTVN1PROD with NOTICES2
52166 Federal Register / Vol. 77, No. 167 / Tuesday, August 28, 2012 / Notices 

406 Id. at 26. 

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 electricityrelated 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), 4o, 

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 electricityrelated 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’’ 


srobinson on DSK4SPTVN1PROD with NOTICES2
Federal Register / Vol. 77, No. 167 / Tuesday, August 28, 2012 / Notices 52167 

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). 

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 RealTime 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 


srobinson on DSK4SPTVN1PROD with NOTICES2
52168 Federal Register / Vol. 77, No. 167 / Tuesday, August 28, 2012 / Notices 

408 5 U.S.C. 601 et seq. 409Under CEA section 2(e), only ECPs are 

permitted to participate in a swap subject to the 

end-user clearing exception. 410See Opting Out of Segregation, 66 FR 20740 

at 20743, Apr. 25, 2001. 

411See 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-ofelectricity-market-surveillance-and-analysisthrough-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. 

412See 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). 413 7 U.S.C. 19(a). 

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), 4o, 

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 


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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 DoddFrank 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 


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414See, 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.’ ’’). 

415See 75 FR at 65955. 

416The 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. 

417There are possibilities of economies of scale if 

multiple Petitioners share the same counsel in 

preparing these memoranda or opinions. 

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 costmitigating, 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 


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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 


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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 


srobinson on DSK4SPTVN1PROD with NOTICES2
Federal Register / Vol. 77, No. 167 / Tuesday, August 28, 2012 / Notices 52173 

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 selfregulatory 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 recordkeeping 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 electricityrelated 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. 

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

BILLING CODE P 


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