10492 Federal Register / Vol. 76, No. 38 / Friday, February 25, 2011 / Rules and Regulations 

1Credit Reforms in Organized Wholesale Electric 

Markets, Order No. 741, 75 FR 65942 (Oct. 21, 

2010), FERC Stats. & Regs. ¶ 31,317 (2010) (Order 

No. 741). 

2 16 U.S.C. 824d, 824e. 

3 In organized wholesale electric markets, defaults 

not supported by collateral are typically socialized 

among all other market participants. 

4Promoting Wholesale Competition Through 

Open Access Non-Discriminatory Transmission 

Services by Public Utilities; Recovery of Stranded 

Costs by Public Utilities and Transmitting Utilities, 

Order No. 888, 61 FR 21540 (May 10, 1996), FERC 

Stats. & Regs. ¶ 31,036, at 31,937 (1996) (pro forma 

OATT, section 11 (Creditworthiness)), order on 

reh’g, Order No. 888–A, 62 FR 12274 (Mar. 14, 

1997), FERC Stats. & Regs. ¶ 31,048 (1997), order on 

reh’g, Order No. 888–B, 81 FERC ¶ 61,248 (1997), 

order on reh’g, Order No. 888–C, 82 FERC ¶ 61,046 

(1998), aff’d in relevant part sub nom. Transmission 

Access Policy Study Group v. FERC, 225 F.3d 667 

(D.C. Cir. 2000), aff’d sub nom. New York v. FERC, 

535 U.S. 1 (2002). 

5 109 FERC ¶ 61,186 (2004) (Policy Statement). 

6References to FTR markets in this order, as in 

Order No. 741, also include the Transmission 

SAS is intended to operate. Some of the 

main considerations for environmental 

concerns are installation locations and 

the resulting exposure to environmental 

conditions for the AP/SAS system 

equipment, including considerations for 

other equipment that may be affected 

environmentally by the AP/SAS 

equipment installation.The level of 

environmental qualification must be 

related to the severity of the considered 

failure conditions and effects on the 

rotorcraft. 

Test & Analysis Requirements 

Compliance with the requirements of 

these special conditions may be shown 

by a variety of methods, which typically 

consist of analysis, flight tests, ground 

tests, and simulation, as a minimum. 

Compliance methodology is related to 

the associated failure condition 

category. If the AP/SAS is a complex 

system, compliance with the 

requirements for failure conditions 

classified as ‘‘major’’ may be shown by 

analysis, in combination with 

appropriate testing to validate the 

analysis. Compliance with the 

requirements for failure conditions 

classified as ‘‘hazardous/severe-major’’ 

may be shown by flight-testing in 

combination with analysis and 

simulation, and the appropriate testing 

to validate the analysis. Flight tests may 

be limited for ‘‘hazardous/severe-major’’ 

failure conditions and effects due to 

safety considerations. Compliance with 

the requirements for failure conditions 

classified as ‘‘catastrophic’’ may be 

shown by analysis, and appropriate 

testing in combination with simulation 

to validate the analysis. Very limited 

flight tests in combination with 

simulation are used as a part of a 

showing of compliance for 

‘‘catastrophic’’ failure conditions. Flight 

tests are performed only in 

circumstances that use operational 

variations, or extrapolations from other 

flight performance aspects to address 

flight safety. 

These special conditions require that 

the Hoh AP/SAS system installed on a 

Bell model 407 helicopter, Type 

Certificate Number H2SW, meet these 

requirements to adequately address the 

failure effects identified by the FHA, 

and subsequently verified by the SSA, 

within the defined system design 

integrity requirements. 

Issued in Fort Worth, Texas, on February 

14, 2011. 

Kimberly K. Smith, 

Manager, Rotorcraft Directorate, Aircraft 

Certification Service. 

[FR Doc. 2011–4229 Filed 2–24–11; 8:45 am] 

BILLING CODE 4910–13–P 

DEPARTMENT OF ENERGY 

Federal Energy Regulatory 

Commission 

18 CFR Part 35 

[Docket No. RM10–13–001; Order 

No. 741–A] 

Credit Reforms in Organized 

Wholesale Electric Markets 

AGENCY: Federal Energy Regulatory 

Commission, DOE. 

ACTION: Final rule; order on rehearing. 

SUMMARY: In this order on rehearing, the 

Commission reaffirms in part its 

determinations in Credit Reforms in 

Organized Wholesale Electric Markets, 

Order No. 741, to amend its regulations 

to improve the management of risk and 

use of credit in the organized wholesale 

electric markets. This order denies in 

part and grants in part rehearing and 

clarification regarding certain 

provisions of Order No. 741. 

DATES: Effective Date: This order will 

become effective on March 28, 2011. 

FOR FURTHER INFORMATION CONTACT: 

Christina Hayes (Legal Information), 

Office of the General Counsel, Federal 

Energy Regulatory Commission, 888 

First Street, NE., Washington, DC 

20426, (202) 502–6194. 

Lawrence Greenfield (Legal 

Information), Office of the General 

Counsel, Federal Energy Regulatory 

Commission, 888 First Street, NE., 

Washington, DC 20426, (202) 502– 

6415. 

Scott Miller (Technical Information), 

Office of Energy Policy and 

Innovation, Federal Energy Regulatory 

Commission, 888 First Street, NE., 

Washington, DC 20426, (202) 502– 

8456. 

SUPPLEMENTARY INFORMATION: 

Before Commissioners: Jon Wellinghoff, 

Chairman; Marc Spitzer, Philip D. Moeller, 

John R. Norris, and Cheryl A. LaFleur. 

Order on Rehearing 

1. In Order No. 741, the Commission 

adopted reforms to credit policies used 

in organized wholesale electric power 

markets.1 In the instant order, the 

Commission addresses requests for 

rehearing of Order No. 741. The 

Commission grants rehearing as to its 

establishment of a $100 million 

corporate family cap on unsecured 

credit and extends the deadline for 

complying with the requirement 

regarding the ability to offset market 

obligations to September 30, 2011, with 

the relevant tariff revisions to take effect 

January 1, 2012, but denies rehearing in 

all other respects, as discussed below. 

I. Background 

2. As noted in Order No. 741, the 

Commission must 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,2 and 

clear and consistent credit policies are 

an important element in ensuring rates 

that are just, reasonable, and not unduly 

discriminatory or preferential. The 

management of risk and credit requires 

a balance between protecting the 

markets from costly defaults 3 and 

ensuring that barriers to entry for market 

participants are not prohibitive. 

3. The Commission provided 

guidance to the industry on appropriate 

credit policies in Order No. 888 4 and 

the Policy Statement on Electric 

Creditworthiness.5 Credit policies 

among the organized wholesale electric 

markets, however, developed in an 

incremental manner leading to varying 

credit practices. Because these variable 

practices posed a heightened risk to the 

stability of the organized wholesale 

electric markets, and especially in light 

of recent events in the financial markets, 

the Commission proposed that the 

different credit practices among the 

organized wholesale electric markets be 

strengthened. 

4. In Order No. 741, the Commission 

directed the regional transmission 

organizations (RTO) and independent 

system operators (ISO) to revise their 

tariffs to reflect the following reforms: 

implementation of shortened settlement 

timeframes, restrictions on the use of 

unsecured credit, elimination of 

unsecured credit in all financial 

transmission rights (FTR) or equivalent 

markets,6 adoption of steps to address 


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Federal Register / Vol. 76, No. 38 / Friday, February 25, 2011 / Rules and Regulations 10493 

Congestion Contracts (TCC) markets in NYISO and 

the Congestion Revenue Rights (CRR) markets in 

California Independent System Operator (CAISO). 

7Financial Marketers are comprised of Energy 

Endeavors LP, Big Bog Energy, LP, Gotham Energy 

Marketing, LP, Rockpile Energy, LP, Coaltrain 

Energy, LP, Longhorn Energy, LP, GRG Energy, LLC, 

MET MA, LLC, Pure Energy, Inc., Red Wolf Energy 

Trading, LLC, Jump Power, LLC, Silverado Energy 

LP, JPTC, LLC, Blue Star Energy, LLC, and Tower 

Research Capital LLC. 

8Six Cities are comprised of the Cities of 

Anaheim, Azusa, Banning, Colton, Pasadena, and 

Riverside, California. 

9Midwest TDUs are comprised of Indiana 

Municipal Power Agency, Madison Gas & Electric 

Company, Missouri River Energy Services, 

Southern Minnesota Municipal Power Agency and 

WPPI Energy. 

10Twin Cities are comprised of Twin Cities 

Power, LLC, Twin Cities Energy, LLC, TC Energy 

Trading, LLC, Cygnus Energy Futures, LLC, and 

Summit Energy, LLC. 

11The New York Transmission Owners are 

comprised of Central Hudson Gas & Electric 

Corporation, Consolidated Edison Company of New 

York, Inc., Long Island Power Authority, New York 

Power Authority, New York State Electric & Gas 

Corporation, Niagara Mohawk Power Corporation 

d/b/a National Grid, Orange and Rockland Utilities, 

Inc., and Rochester Gas and Electric Corporation. 

12Order No. 741, FERC Stats. & Regs. ¶ 31,317 at 

P 49–57. 

13Morgan Stanley, November 22, 2010 Request 

for Rehearing at 4–5 (Morgan Stanley Request). 

14Six Cities November 19, 2010 Request for 

Rehearing at 12–14 (Six Cities Request). 

15While a corporate family may choose to have 

a single member company participate in an RTO/ 

ISO’s market, or instead opt to have more than one 

do so, in either case, the single entity or multiple 

entities together will have a cap of no more than 

$50 million. 

16See Credit Reforms in Organized Wholesale 

Electric Markets, Notice of Proposed Rulemaking, 

75 FR 4310 (Jan. 27, 2010), FERC Stats. & Regs. 

¶ 32,651, at P 19 (2010). 

17Order No. 741, FERC Stats. & Regs. ¶ 31,317 at 

P 70–79. 

18APPA November 19, 2010 Request for 

Rehearing at 1–3, 4–9 (APPA Request); Midwest 

TDUs November 22, 2010 Request for Rehearing 

(Midwest TDUs Request). 

19 16 U.S.C. 824q(b)(4). 

20 Long-Term Firm Transmission Rights in 

Organized Electricity Markets, Order No. 681, FERC 

Stats. & Regs. ¶ 31,226, reh’g denied, Order No. 

681–A, 117 FERC ¶ 61,201 (2006). 

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. 

5. Requests for rehearing were filed by 

the New York Independent System 

Operator, Inc. (NYISO), Morgan Stanley 

Capital Group Inc. (Morgan Stanley), 

Financial Marketers,7 the American 

Public Power Association (APPA), East 

Texas Cooperatives, Six Cities,8

Midwest Transmission Dependent 

Utilities (Midwest TDUs),9 Twin 

Cities,10 and Southern California Edison 

Company (SCE). The New York 

Transmission Owners filed an answer.11

II. Discussion 

A. Use of Unsecured Credit 

1. Requests for Rehearing 

6. Six Cities and Morgan Stanley seek 

rehearing of the Commission’s 

requirement that each ISO and RTO 

revise its tariff provisions to reduce the 

extension of unsecured credit to no 

more than $50 million per market 

participant and $100 million per 

corporate family.12

7. Morgan Stanley argues that the 

Commission should eliminate the $50 

million market participant cap. Morgan 

Stanley contends that the separate 

caps—$50 million for a market 

participant and $100 million for a 

corporate family—will encourage 

entities to reconfigure their corporate 

structures to avoid the $50 million per 

entity cap and instead use the $100 

million corporate family cap. Morgan 

Stanley asserts that such a structure will 

increase costs to market participants, 

making the $50 million cap illusory and 

generating unnecessary burdens for 

ISOs and RTOs without a corresponding 

benefit.13

8. Conversely, Six Cities argue that 

the Commission should eliminate the 

$100 million corporate family cap. They 

assert that the Commission did not 

provide a rational explanation for 

permitting affiliated entities to impose a 

greater degree of risk than individual 

entities, and so should not have allowed 

the $100 million corporate family cap. 

Six Cities also argues that the $100 

million corporate family cap could run 

up to $600 million if there was a default 

in every ISO/RTO.14

2. Commission Determination 

9. The Commission grants rehearing 

on this issue. Specifically, the 

Commission is persuaded that an entity 

reconfiguring its corporate structure, to 

avoid the $50 million single-entity cap 

and to instead take advantage of the 

$100 million corporate family cap, 

raises a significant risk that is 

inconsistent with Order No. 741’s intent 

to lower risk. Additionally, the 

Commission has taken into 

consideration Six Cities’ point that 

affiliated entities should not be able to 

impose a greater risk to the stability of 

organized wholesale markets than 

individual entities. We agree that the 

cumulative danger posed by a $100 

million corporate family cap on the use 

of unsecured credit poses an 

unacceptable risk to the organized 

wholesale electric markets; many 

market participants either themselves or 

through subsidiaries participate in 

multiple markets. We agree with Six 

Cities that the default of a single entity 

could result in a significant cumulative 

unsecured exposure if we were to allow 

the higher $100 million corporate cap 

for unsecured credit originally 

permitted in Order No. 741. Socializing 

such losses to other market participants 

could lead to even more significant 

market disruption than merely the 

default of a single entity. The 

Commission therefore grants rehearing 

and finds that the limit on the use of 

unsecured credit should be no more 

than $50 million per entity, including 

the corporate family to which an entity 

belongs.15 This is the approach 

originally suggested by the Commission 

in its Notice of Proposed Rulemaking 16

and the Commission is persuaded it 

should return to this proposal. 

B. Elimination of Unsecured Credit for 

Financial Transmission Rights Markets 

1. Requests for Rehearing 

10. APPA, Midwest TDUs, and Six 

Cities request rehearing on the 

Commission’s elimination of unsecured 

credit in the FTR markets.17 They argue 

that the Commission erred in 

eliminating unsecured credit for all 

participants, particularly load-serving 

entities. 

11. APPA and Midwest TDUs argue 

that the elimination of unsecured credit 

in FTR markets will make it financially 

prohibitive for load-serving entities to 

obtain and hold long-term FTRs of ten 

years or more (LTTR).18 They contend 

that this is inconsistent with the 

Commission’s responsibilities, under 

section 217(b)(4) of the Federal Power 

Act (FPA) 19 and Order No. 681,20 to 

enable load-serving entities to secure 

firm transmission rights on a long-term 

basis for long-term power supply 

arrangements to serve their load. At a 

minimum, they contend, the 

Commission should direct RTOs and 

ISOs to implement Order No. 741 in 

compliance with section 217(b)(4) and 

Order No. 681. Further, APPA and 

Midwest TDUs argue that they be 

allowed to request exemptions under 

Order No. 741 to ensure that a loadserving entity’s access to LTTRs is not 

impaired. 

12. Midwest TDUs further argue that 

ISOs and RTOs manage risk in the FTR 

markets by determining the 

creditworthiness of individual FTR 

market participants. Moreover, Midwest 

TDUs contend that load-serving entities 

are less of a credit risk because their 

bond resolutions give explicit payment 


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10494 Federal Register / Vol. 76, No. 38 / Friday, February 25, 2011 / Rules and Regulations 

21Six Cities Request at 3, 10–12 (citing Petal Gas 

Storage, L.L.C. v. FERC, 496 F.3d 695, 698 (D.C. Cir. 

2007), and others). 

22The analysis in this paragraph, and the prior 

paragraph, explains why, as a generic matter, we 

will not allow exemptions from this requirement of 

Order No. 741. 

23Order No. 741, FERC Stats. & Regs. ¶ 31,317 at 

P 76. 

24 Id. P 116–22. The Commission also left open 

the possibility of setting credit requirements based 

on gross obligations. Id. 

25NYISO November 19, 2010 Request for 

Clarification or Rehearing at 4 (citing In re Peterson 

Distributing, Inc., 82 F.3d 956 (10th Cir. 1996), and 

other cases). The New York Transmission Owners 

support NYISO’s arguments. New York 

Transmission Owners December 8, 2010 Answer. 

26SCE November 22, 2010 Request for 

Clarification or Rehearing at 4 (SCE Request). 

27 Id. at 5–6. 

28Morgan Stanley Request at 6, generally 5–7. 

priority to energy and transmission 

market service providers over 

bondholders, in effect giving RTOs/ISOs 

a security interest in their accounts 

receivable. APPA also contends that, 

although the Commission noted the 

challenges in valuing FTRs, the 

Commission did not provide guidance 

in how to address that issue. 

13. Six Cities contends that the 

Commission should not have eliminated 

unsecured credit for all types and 

holders of FTRs. Six Cities notes that 

the CAISO has two types of FTRs: 

allocated CRRs, which are used by loadserving entities to hedge congestion 

costs for purchases to serve the needs of 

native load customers, and auctioned 

CRRs, which may be purchased by any 

entity that satisfies CAISO’s 

qualification criteria. Six Cities argues 

that CAISO should be allowed to 

differentiate between the two categories 

in setting credit requirements. 

Specifically, Six Cities argues that loadserving entities have no obligation to 

pay for allocated CRRs, thus cannot 

default. By eliminating unsecured credit 

for all FTRs without regard to the 

purpose for purchase, Six Cities argues 

that the Commission’s decision is not 

reasoned decision-making as required 

by the Administrative Procedures Act.21

2. Commission Determination 

14. The Commission denies rehearing. 

The Commission is not persuaded that 

the elimination of unsecured credit in 

the FTR markets is inconsistent with the 

statutory directive to facilitate access to 

long-term FTRs. While section 217(b)(4) 

directs us to exercise our authority 

under the FPA to ‘‘enable[ ] loadserving entities’’ to ‘‘secure’’ FTRs ‘‘on a 

long-term basis,’’ the statute does not 

require that we guarantee the 

availability of unsecured credit, and 

does not require that we ignore the risks 

posed by the use of unsecured credit. 

Denying unsecured credit does not 

prohibit load-serving entities from 

securing long-term FTRs, but rather 

merely requires use of some other form 

of financing, e.g., the use of secured 

credit or the posting of collateral. 

Moreover, there is nothing in the record 

to indicate that acquisition of long-term 

FTRs will be prohibitively expensive. 

Our reason for eliminating reliance on 

unsecured credit in the FTR markets is 

to reduce risk to market participants, 

including risk to those market 

participants that are load-serving 

entities. Those seeking rehearing on this 

issue have failed to demonstrate that 

this risk can and should be so readily 

discounted. 

15. Nor is the Commission persuaded 

that unsecured credit in FTR markets 

should be allowed for certain market 

participants based on the ‘‘purpose’’ of 

the entity engaging in the FTR market. 

The FTR market exists to hedge, i.e., 

manage, risk, but there are no 

guarantees that such hedges, even for 

load-serving entities, will themselves 

have no risk. The risk of adverse FTR 

market outcomes and potential effects 

on market participants led us to take 

these actions initially, and are no more 

or less applicable to some participants 

than others based on the ‘‘purpose’’ of 

the participant.22 Finally, to the extent 

that certain FTRs have inherently low 

risk, we expect that the RTO and ISO’s 

credit modeling will result in relatively 

low collateral requirements. 

16. As to the question of how FTRs 

are valued, as we stated in Order No. 

741, this issue is beyond the scope of 

this proceeding.23 Regarding the 

Midwest TDUs’ argument that where 

bond resolutions give explicit payment 

priority to energy and transmission 

market service providers over 

bondholders, in effect giving RTOs/ISOs 

a security interest in their accounts 

receivable, first, it is not clear that such 

payment priority would apply in the 

event of a default in an FTR market. 

Furthermore, we are not persuaded that 

giving such payment priority would 

provide a level of security comparable 

to the elimination of reliance on 

unsecured credit. 

C. Ability To Offset Market Obligations 

1. Requests for Rehearing 

17. Morgan Stanley, SCE, NYISO, and 

the New York Transmission Owners 

seek rehearing of the Commission’s 

directive that, if an ISO/RTO wishes to 

allow netting of amounts owed to a 

market participant against amounts 

owed by that participant, the ISO/RTO 

must revise its tariff to include one of 

the following options: (1) Establish a 

central counterparty; (2) require market 

participants to provide a security 

interest in their transactions in order to 

establish collateral requirements based 

on net exposure; or (3) propose another 

alternative, which provides the same 

degree of protection as the two abovementioned methods.24

18. NYISO requests clarification that 

the Commission intended that, in the 

absence of a counterparty, security 

interest, or other alternative, netting 

would only be prohibited across 

product or service categories. If the 

Commission does not grant the 

clarification, NYISO requests rehearing, 

arguing that an ISO/RTO be allowed to 

net amounts owed against amounts 

receivable if supported by the doctrine 

of recoupment. NYISO contends that, 

under the doctrine of recoupment, it is 

inequitable for a debtor to enjoy the 

benefits of a transaction without also 

meeting its obligations, so a market 

participant’s benefits from its sales 

within a category area are lawfully offset 

by its obligations related to its 

purchases within the same product 

category.25 NYISO argues that, in the 

event of a market participant’s 

bankruptcy, the bankruptcy court would 

allow netting within a product or 

service category under the doctrine of 

recoupment. 

19. SCE requests a similar 

clarification, and questions how ‘‘gross 

obligations’’ is defined. SCE states that 

the Commission was not clear whether 

requiring collateral posted to gross 

obligations would (i) allow for netting 

within a given market but not between 

markets, (ii) allow for netting for 

transactions deemed not to have 

participated in the markets (e.g. Eschedules), or (iii) disallow netting both 

within markets and across markets and 

require credit obligations to be 

determined on an absolute gross basis.26

20. SCE also requests that the 

Commission extend the time for 

compliance with this tariff revision 

until October 1, 2012, or alternatively, 

clarify that parties may move for an 

extension of time if needed.27

21. Morgan Stanley argues that ISOs 

and RTOs should not require market 

participants to post collateral to their 

gross obligations, especially if they are 

netting amounts owed against amounts 

receivable under their tariffs. Morgan 

Stanley contends that requiring 

collateral to gross obligations will be 

very expensive, without corresponding 

benefits. Morgan Stanley also asserts 

that ‘‘other less costly (and at least as 

effective) options are available.’’ 28

Morgan Stanley requests in the 


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Federal Register / Vol. 76, No. 38 / Friday, February 25, 2011 / Rules and Regulations 10495 

29Section 553 of the Bankruptcy Code, 11 U.S.C. 

553, provides that a creditor may offset payments 

owed to the debtor against payments owed by the 

debtor, under certain circumstances. 

30Testimony at Technical Conference on Credit 

Reforms in Organized Wholesale Electric Markets, 

Tr. 93:2–16 (May 11, 2010) (Mr. Stephen Dutton, 

Barnes & Thornburg). 

31 Id. at 93:20–94:17 (Mr. Harold Novikoff, 

Wachtell, Lipton, Rosen & Katz). 

32 Id. at 94:24–95:11 (Mr. Iskender H. Catto, 

Kirkland & Ellis on behalf of the Committee of Chief 

Risk Officers). 

33Order No. 741, FERC Stats. & Regs. ¶ 31,317 at 

P 131–34. 

34APPA Request at 4–9. 

35Twin Cities November 22, 2010 Request for 

Clarification or Rehearing at 5–7 (Twin Cities 

Request). 

36Six Cities Request at 3, 10–12. Financial 

Marketers echo these comments. Financial 

Marketers November 22, 2010 Request for 

Rehearing at 13 (Financial Marketers Request). 

37Financial Marketers Request at 3–4 (citing 

California Independent System Operator Corp., 107 

FERC ¶ 61,274 (2004), and others). 

38 Id. at 4–5. 

alternative that if the Commission 

retains this requirement, then it should 

allow higher levels of unsecured credit 

to ameliorate the effects of this 

provision. 

2. Commission Determination 

22. The Commission denies rehearing. 

In Order No. 741, the Commission 

established requirements to minimize 

risk in the event of bankruptcy (i.e., the 

options noted in paragraph 117 of Order 

No. 741, and described above in 

paragraph 17) out of concern that the 

effect of a default could be exacerbated 

by a bankruptcy court decision that does 

not allow netting. Those concerns exist 

whether netting is performed within a 

market product category or across 

market categories. A market 

administrator must have legal support to 

net transactions, whether it serves as a 

counterparty, has been granted a 

security interest in the transactions, or 

employs some other solution, in the 

event of a legal challenge to set-off 

during a bankruptcy proceeding.29 The 

record before us does not clearly 

demonstrate that the availability of 

netting will depend on whether it is 

within or across product categories, and 

therefore we deny rehearing on this 

issue. 

23. Our denial of rehearing is based in 

part on the testimony we received 

during the May 2010 technical 

conference. In response to questioning 

regarding set-off within product 

markets, Mr. Stephen Dutton suggested 

that a bankruptcy court would be most 

likely to allow netting within product 

categories if the ISO or RTO was acting 

in the same capacity with respect to 

amounts owed and amounts owing.30 In 

response to Mr. Dutton’s comments, Mr. 

Harold Novikoff asserted that the 

bankruptcy court would look at a 

different issue, specifically, whether the 

ISO or RTO is a party to the 

transaction.31 Mr. Iskender Catto 

reiterated Mr. Novikoff’s opinion, 

indicating that a court would look first 

to the identity of the counterparty, then 

the role served by the counterparty.32

Based on this testimony, we believe that 

netting within product categories may 

put an RTO or an ISO at risk, were it 

to not adopt one of remedies we 

specified in Order No. 741. 

24. The Commission also denies 

Morgan Stanley’s request for rehearing 

on the issue of posting collateral based 

on gross obligations; this was merely 

one option presented in Order No. 741. 

The Commission provided two other 

options to meet its requirements on this 

matter and expressed its willingness to 

consider yet others that can be shown to 

provide the same degree of protections 

as the two other options set out in Order 

No. 741. In the absence of the RTO or 

ISO taking advantage of such options, it 

is appropriate that credit requirements 

be set based on gross obligations in 

order to minimize the risk, and costs, of 

market participant default and a 

bankruptcy court decision refusing to 

allow netting; anything less would not 

adequately protect the market and 

participants in the markets. 

25. As to SCE’s request that the 

Commission delay the required filing 

date of a compliance filing regarding 

this requirement to October 1, 2012, we 

believe that such an extension is 

excessive. However, we will extend the 

date for filing tariff revisions to comply 

with this requirement related to the 

ability to offset market obligations to 

September 30, 2011, with the relevant 

tariff revisions to take effect January 1, 

2012. 

D. Minimum Criteria for Market 

Participation 

1. Requests for Rehearing 

26. APPA, Twin Cities, Six Cities, and 

Financial Marketers seek rehearing on 

the Commission’s determination that 

each ISO and RTO should include in its 

tariff language that sets forth specific 

minimum participation criteria to be 

eligible to participate in the organized 

wholesale electric market, such as 

requirements related to adequate 

capitalization and risk management 

controls.33

27. APPA requests that the 

Commission instruct RTOs and ISOs to 

avoid unreasonable or onerous 

conditions on load-serving entities or 

provide specific exemptions for them if 

needed. APPA states that smaller, 

public power load-serving entities 

present ‘‘minimal risk, and related 

costs,’’ so they should not have to 

comply with unreasonable or onerous 

minimum criteria to participate in the 

market. Also, a default by such a 

participant would not pose a risk of 

significant market disruption.34

28. Twin Cities request that the 

Commission provide stronger guidance 

on minimum criteria, and require that 

the criteria be uniform across ISOs and 

RTOs. Twin Cities state that market 

participants that participate in several 

markets are burdened by participating 

in multiple stakeholder processes and 

they risk being treated differently by 

different markets. Twin Cities request 

that the Commission establish the 

minimum participation criteria, similar 

to that of the Commodity Futures 

Trading Commission (CFTC) and 

Securities and Exchange Commission 

(SEC), based on tangible net worth. 

Similar criteria, established by the 

Commission to apply to all ISO and 

RTO markets, would provide regulatory 

certainty, reduce risk, and promote the 

goal of Order No. 741.35

29. Six Cities requests that the 

Commission require that minimum 

participation criteria be tiered or 

calibrated based on the magnitude of a 

market participant’s positions in the 

market. Because the size of a 

participant’s positions has an effect on 

the size of a risk that it poses, there 

should be a correlation between the 

market participant’s positions and the 

minimum criteria.36

30. Financial Marketers express 

concern that the minimum criteria will 

exclude small and mid-size companies, 

virtual traders, and new entrants from 

participating in the RTO/ISO markets. 

They contend that the Commission has 

praised such participants,37 and that 

customers in Midwest ISO have suffered 

higher prices since Midwest ISO began 

discouraging virtual trading by 

allocating high Revenue Sufficiency 

Guarantee (RSG) charges to virtual 

transactions.38 Financial Marketers 

further argue that the stakeholder 

process will not protect small 

companies or new entrants, because 

large utilities will be able to meet any 

minimum criteria and have a vested 

interest in excluding competition. 

31. Financial Marketers argue that 

most smaller companies are fully 

collateralized, and thus pose no threat. 

They contend that other markets rely on 

collateral requirements to curb market 


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10496 Federal Register / Vol. 76, No. 38 / Friday, February 25, 2011 / Rules and Regulations 

39 Id. at 29–31. 

40 Id. at 14–15. 

41 Id. at 32–33. 

42Order No. 741, FERC Stats. & Regs. ¶ 31,317 at 

P 132–33. 

43While we did indicate that criteria should 

apply to all market participants rather than only 

certain participants, see Order No. 741, FERC Stats. 

& Regs. ¶ 31,317 at P 133, our intent was that there 

be minimum criteria for all market participants and 

not that all market participants necessarily be held 

to the same minimum criteria. For some criteria, 

holding all market participants to the same 

minimum criteria may be appropriate. For other 

criteria, however, it may be appropriate to hold 

different participants to different minimum criteria, 

e.g., based on the size of the participants’ positions. 

44 Id. P 160–63. 

45 Id. P 184. The RFA definition of ‘‘small entity’’ 

refers to the definition provided in the Small 

Business Act, which defines a ‘‘small business 

concern’’ as a business that is independently owned 

and operated and that is not dominant in its field 

of operation. 5 U.S.C. 601(3) (citing section 3 of the 

Small Business Act, 15 U.S.C. 632). The Small 

Business Size Standards component of the North 

American Industry Classification System defines a 

small electric utility as one that, including its 

affiliates, is primarily engaged in the generation, 

transmission, and/or distribution of electric energy 

for sale and whose total electric output for the 

preceding fiscal years did not exceed 4 million 

MWh. 13 CFR 121.201 (2010). 

46 5 U.S.C. 601–12. 

47APPA Request at 10. 

48 Aeronautical Repair Station Ass’n, Inc. v. 

FAA, 494 F.3d 161 (D.C. Cir. 2007). 

49 Id. at 177. 

50Six Cities Request at 6–9. 

51Financial Marketers Request at 18–20. 

risk, and that the CFTC does not require 

minimum capitalization.39

32. Financial Marketers also note that 

ISO New England Inc. (ISO–NE) and 

PJM Interconnection, LLC (PJM) have 

previously considered minimum 

participation criteria, but abandoned 

their efforts after concluding that they 

would reduce competition, result in 

greater market power by existing large 

companies, and not provide any 

additional protections to the market.40

Financial Marketers conclude that 

market participants have developed 

businesses based on participation in the 

organized wholesale electric markets, 

and regulations that would prohibit 

their participation would result in a 

regulatory taking that would require 

compensation.41

2. Commission Determination 

33. The Commission denies rehearing. 

In Order No. 741, the Commission 

deferred to stakeholder processes the 

determination of reasonable minimum 

criteria for market participation.42

Because no market participation criteria 

have yet to be filed, the Commission 

cannot determine whether such criteria 

are or are not reasonable. However, we 

note that we did not mandate a single 

set of criteria for all participants in a 

market,43 and we see value in Six Cities’ 

suggestion that stakeholders consider 

whether some criteria can be tiered or 

calibrated based on, for example, the 

size of a market participant’s positions. 

Such an approach would allow for 

differentiation based on a market 

participant’s characteristics, but still 

reduce the market’s exposure to the risk 

of a default. We remind stakeholders 

that the Commission will review all 

criteria, including both market-wide 

criteria and any tiered or calibrated 

criteria, when such criteria are filed, to 

ensure that they are just and reasonable 

and not unduly discriminatory or 

preferential. 

E. Grace Period To ‘‘Cure’’ Collateral 

Posting 

1. Requests for Rehearing 

34. East Texas Cooperatives request 

rehearing on the Commission’s 

establishment of a two-day grace period 

to ‘‘cure’’ a collateral call.44 East Texas 

Cooperatives assert that the Commission 

should not have established a uniform 

two-day period because it was not 

supported by sufficient evidence and 

the requirement will be onerous for 

small market participants with small 

staffs and constrained budgets. East 

Texas Cooperatives argue that most ISOs 

and RTOs already have two- or threeday cure periods, and the matter should 

have been left to their discretion. 

Alternatively, the Commission could 

establish a uniform three-day ‘‘cure’’ 

period for all entities or, as a last resort, 

a three-day period for not-for-profit 

load-serving entities, such as 

cooperatives, municipalities, and other 

public power entities. 

2. Commission Determination 

35. The Commission denies rehearing. 

In establishing the two-day cure period 

in Order No. 741, the Commission 

carefully weighed the needs of market 

participants with the need for the 

mitigation of uncertainty when the 

organized electric wholesale markets are 

under stress. As we learned during the 

financial crisis, a market administrator 

may request additional collateral when 

the market is under stress. As a result, 

timely cure of a collateral deficiency is 

critical. We also note that the CFTC 

called for a one-day cure period, while 

others promoted a three-day cure 

period, and we found—and continue to 

find—that the two-day cure period 

strikes a reasonable balance between 

mitigating uncertainty in the market and 

providing for the needs of participants. 

F. Regulatory Flexibility Analysis 

1. Requests for Rehearing 

36. APPA, Six Cities, and Financial 

Marketers challenge the Commission’s 

conclusion that Order No. 741 ‘‘will not 

have a significant economic impact on 

a substantial number of small 

entities.’’ 45 They contend that the 

Commission should analyze the effect of 

Order No. 741 on small entities, as 

required by the Regulatory Flexibility 

Act (RFA).46

37. APPA and Six Cities argue that the 

Commission erred in determining that 

small utilities within the balancing 

authority area of an RTO have a choice 

as to whether to join the RTO. Because 

large transmission owners are part of the 

RTO, they argue, small utilities must 

join to obtain necessary transmission 

and ancillary services. APPA estimates 

that more than a thousand public power 

distribution systems, plus rural electric 

cooperatives, are located in states served 

by RTOs and are ‘‘small utilities’’ within 

the meaning of RFA. APPA also 

contends that public power systems 

have unique financial constraints and 

may not be able to meet the new 

financial requirements that RTOs might 

impose.47

38. In support of its argument, Six 

Cities cites Aeronautical Repair Station 

Ass’n,48 in which, they state, the court 

held that even though air carriers were 

the direct objects of the rule 

promulgated by the Federal Aviation 

Administration (FAA), the employees of 

the contractors and subcontractors were 

also subject to the rule. The D.C. Circuit 

concluded that the FAA was required to 

analyze the effect of the rule on the 

contractors and subcontractors.49 Six 

Cities argues that the ISOs and RTOs are 

analogous to air carriers, and market 

participants can be compared to the 

contractors and subcontractors which 

are also directly regulated by the 

agency’s rule.50

39. Financial Marketers argue that the 

Commission did not properly analyze 

the effect of minimum participation 

criteria on small financial traders under 

the RFA. Financial Marketers contend 

that the Commission’s directives will 

push small financial traders out of ISO/ 

RTO markets and prevent market entry 

by smaller companies.51

2. Commission Determination 

40. The RFA requires that, when 

promulgating a final rule, an agency 

must conduct an analysis that includes, 

among other things, ‘‘(3) a description of 

and an estimate of the number of small 

entities to which the rule will apply or 

an explanation of why no such estimate 


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Federal Register / Vol. 76, No. 38 / Friday, February 25, 2011 / Rules and Regulations 10497 

52 5 U.S.C. 604(a)(3), (5). 

53 Mid-Tex Electric Cooperative v. FERC, 773 

F.2d 327, 343 (D.C. Cir. 1985); see also Cement Kiln 

Recycling Coalition v. EPA, 255 F.3d 855, 868–69 

(D.C. Cir. 2001). 

54White Eagle Cooperative Association v. Conner, 

553 F.3d 467, 480 (7th Cir. 2009). 

55 Id. 

56Cement Kiln Recycling Coalition, 255 F.3d at 

869. 

57Aeronautical Repair Station Ass’n, Inc, 494 

F.3d at 177. 

58 Mid-Tex Electric Cooperative, 773 F.2d at 342 

(citing 5 U.S.C. § 603(b)(4) and related legislative 

history). 

59Order No. 741, FERC Stats. & Regs. ¶ 31,317 at 

P 50. 

60 Id. P 161. 

61See supra P 33. 

62Order No. 741, FERC Stats. & Regs. ¶ 31,317 at 

P 165. We also note that a market participant retains 

its right to individually seek an exemption under 

section 206 of the FPA. 

63 5 CFR 1320.11. 

is available; * * * and (5) a description 

of the steps the agency has taken to 

minimize the significant economic 

impact on small entities consistent with 

the stated objectives of applicable 

statutes * * *.’’ 52

41. Under the RFA, an agency must 

consider the economic impact on 

entities directly affected and regulated 

by the subject regulations. The D.C. 

Circuit has held that Congress did not, 

however, intend to require that the 

agency ‘‘consider every indirect effect 

that any regulation might have on small 

businesses in any stratum of the 

national economy.’’ 53 More recently, the 

Seventh Circuit compared the holdings 

in several cases considering the RFA, 

including Aeronautical Repair Station 

Ass’n, and described the rule as follows: 

‘‘Small entities directly regulated by the 

proposed statute—whose conduct is 

circumscribed or mandated—may bring 

a challenge to the RFA analysis or 

certification of an agency. * * * 

However, when the regulation reaches 

small entities only indirectly, they do 

not have standing to bring an RFA 

challenge.’’ 54 The court further stated 

that, where the regulation ‘‘expressly’’ 

addresses an entity’s actions, that entity 

is subject to an RFA analysis, and that, 

although the regulation may affect the 

actions of other entities, those other 

entities are not subject to an RFA 

analysis.55

42. We note at the outset that the 

regulations adopted in this proceeding 

directly apply to RTOs and ISOs only, 

not small entities, thus the Commission 

is not required to assess the impact of 

the rule on small entities.56 In contrast 

to Aeronautical Repair Station Ass’n, in 

which the regulations expressly 

required certain actions by small 

entities, in this rulemaking, the 

regulations require specific actions only 

by the RTOs and ISOs.57 Further, the 

relevant impact considered under the 

RFA is the impact of compliance, 

including ‘‘the projected reporting, 

recordkeeping and other compliance 

requirements of the proposed rule.’’ 58

Those obligations are directly imposed 

on RTOs and ISOs only, and not market 

participants. 

43. Additionally, in issuing Order No. 

741, the Commission focused on 

protecting the organized wholesale 

electric markets from default by a 

market participant. In the event of a 

default by a market participant, the 

losses related to that default must be 

socialized among all other market 

participants, potentially leading to 

cascading defaults, all leading to 

adverse effects on customers. The 

Commission sought to balance measures 

intended to protect the market and 

market participants from the risk of a 

default against the effect of the measures 

on market participants. For instance, in 

establishing the cap on unsecured 

credit,59 setting the two-day cure 

period,60 and, on rehearing, allowing 

RTOs/ISOs to consider a market 

participant’s level of participation in the 

market in setting minimum criteria,61

the Commission has sought to protect 

the markets and market participants 

from the risk of a default, while 

providing consideration of the needs of 

the market participants themselves. 

44. The Commission thus has sought 

to accommodate market participants’ 

concerns while still meeting its 

responsibility to protect markets to 

ensure that the resulting rates are just 

and reasonable and not unduly 

discriminatory or preferential under 

FPA sections 205 and 206; however, we 

are not obligated to conduct a further 

analysis under the RFA. The regulations 

promulgated in Order No. 741 and here 

direct the actions of the ISOs and RTOs 

in administering the organized 

wholesale electric markets. While the 

regulations may indirectly affect other 

entities—market participants, including 

investor-owned utilities, municipalities 

and cooperatives, and financial 

marketers, as well as customers of all 

kinds—we are not required to conduct 

an analysis under the RFA on such 

entities in this proceeding. 

45. Furthermore, by requiring tariff 

revisions to protect the markets and 

market participants from the risk and 

resulting cost of default by others, we 

are not only protecting market 

participants from the risk and resulting 

costs of default by others, but we are, in 

particular, protecting those smaller 

market participants that are least able to 

withstand a default. Smaller market 

participants have fewer resources 

available to them to deal with a default 

when one occurs, and thus it is 

particularly important for smaller 

market participants that the 

Commission put in place measures that 

minimize the risk of a default and the 

resulting cost of a default. 

46. Further, we note that ISOs and 

RTOs are in the best position, in the first 

instance, to assess to what extent credit 

practices, as implemented in their 

markets, will have an adverse effect on 

their market participants, as well as the 

potential harm to the market in the 

event of a default. Thus, as noted in 

Order No. 741, ISOs and RTOs may, 

through their stakeholder processes, 

propose specific exemptions for 

individual entities whose participation 

is such that a default would not risk 

significant market disruptions.62 We 

also note that, as the ISOs and RTOs 

submit their compliance filings, 

interested persons will have an 

opportunity to contest the various 

revisions as filed for individual tariffs, 

and the Commission remains open to 

comments on the particular revisions at 

that time. The Commission, however, 

will not, at this time, adopt any 

exemptions. 

III. Information Collection Statement 

47. The Office of Management and 

Budget (OMB) regulations require that 

OMB approve certain information 

collection requirements imposed by an 

agency.63 The revisions in Order No. 

741 to the information collection 

requirements for ISOs and RTOs were 

approved under OMB Control Nos. 

1902–0096. While this order clarifies 

and revises aspects of the existing 

information collection requirements, it 

does not add to these requirements. 

Accordingly, a copy of this order will be 

sent to OMB for informational purposes 

only. 

IV. Document Availability 

48. In addition to publishing the full 

text of this document in the Federal 

Register, the Commission provides all 

interested persons an opportunity to 

view and/or print the contents of this 

document via the Internet through the 

Commission’s Home Page (http:// 

www.ferc.gov) and in the Commission’s 

Public Reference Room during normal 

business hours (8:30 a.m. to 5 p.m. 

Eastern time) at 888 First Street, NE., 

Room 2A, Washington, DC 20426. 

49. From the Commission’s Home 

Page on the Internet, this information is 

available in the Commission’s document 

management system, eLibrary. The full 


srobinson on DSKHWCL6B1PROD with RULES
10498 Federal Register / Vol. 76, No. 38 / Friday, February 25, 2011 / Rules and Regulations 

text of this document is available on 

eLibrary in PDF and Microsoft Word 

format for viewing, printing, and/or 

downloading. To access this document 

in eLibrary, type ‘‘RM10–13’’ in the 

docket number field. 

50. User assistance is available for 

eLibrary and the Commission’s website 

during normal business hours. For 

assistance, please contact FERC Online 

Support at 1–866–208–3676 (toll free) or 

202–502–6652 (e-mail at 

FERCOnlineSupport@FERC.gov), or the 

Public Reference Room at 202–502– 

8371, TTY 202–502–8659 (e-mail at 

public.referenceroom@ferc.gov). 

V. Effective Date 

51. Changes to Order No. 741 adopted 

in this order on rehearing will become 

effective March 28, 2011. 

List of Subjects in 18 CFR Part 35 

Electric power rates, Electric utilities, 

Reporting and recordkeeping 

requirements. 

By the Commission. 

Kimberly D. Bose, 

Secretary. 

In consideration of the foregoing, the 

Commission amends part 35, subchapter 

B, chapter I, title 18, Code of Federal 

Regulations, as follows: 

PART 35—FILING OF RATE 

SCHEDULES AND TARIFFS 

■ 1. The authority citation for part 35 

continues to read as follows: 

Authority: 16 U.S.C. 791a–825r, 2601– 

2645; 31 U.S.C. 9701; 42 U.S.C. 7101–7352. 

■ 2. Section 35.47 is amended by 

revising paragraph (a) to read as follows: 

§ 35.47 Tariff provisions regarding credit 

practices in organized wholesale electric 

markets. 

* * * * * 

(a) Limit the amount of unsecured 

credit extended by an organized 

wholesale electric market to no more 

than $50 million for each market 

participant; where a corporate family 

includes more than one market 

participant participating in the same 

organized wholesale electric market, the 

limit on the amount of unsecured credit 

extended by that organized wholesale 

electric market shall be no more than 

$50 million for the corporate family. 

* * * * * 

[FR Doc. 2011–4088 Filed 2–24–11; 8:45 am] 

BILLING CODE 6717–01–P 

DEPARTMENT OF STATE 

22 CFR Part 62 

[Public Notice: 7346] 

RIN 1400–AC67 

Exchange Visitor Program—Fees and 

Charges 

AGENCY: Department of State. 

ACTION: Final rule. 

SUMMARY: The Department of State is 

amending its regulations regarding fees 

and charges for Exchange Visitor 

Program services. The fees permit the 

Department to recoup the cost of 

providing such Exchange Visitor 

Program services. 

DATES: Effective Date: This rule is 

effective 30 days from February 25, 

2011. 

FOR FURTHER INFORMATION CONTACT: 

Stanley S. Colvin, Deputy Assistant 

Secretary for Private Sector Exchange, 

U.S. Department of State, SA–5, Floor 5, 

2200 C Street, NW., Washington, DC 

20522, 202–632–2805, or e-mail at 

jexchanges@state.gov. 

SUPPLEMENTARY INFORMATION: The 

Department published a proposed rule, 

Public Notice 7077 at 75 FR 60674– 

60679, October 1, 2010, with a request 

for comments, amending § 62.17 (‘‘Fees 

and Charges’’) containing all of the fees 

and charges for Exchange Visitor 

Program services. As explained in the 

proposed rule, the Department is 

increasing user fees charged for 

Exchange Visitor Program services in 

order to recoup the full cost of such 

services which are requested and 

performed for the benefit of foreign 

nationals or U.S. corporate entities. 

These costs were calculated by an 

independent certified public accounting 

firm in full compliance with the Office 

of Management and Budget directives 

regarding such user fee calculations as 

set forth in OMB Circular A–25. 

The Department received three 

comments and is now promulgating a 

final rule with no changes from the 

proposed rule. Thus, the fee charged to 

foreign nationals for a request for 

individual program services, such as 

change of program category, program 

extensions and reinstatements, will 

decrease to $233.00. The fee charged to 

U.S. corporate entities for requests for 

program designation, redesignation and 

amendments to program designation 

will increase to $2,700.00 in order to 

recoup the full cost of such services. 

Comment Analysis 

The Department received three 

comments. One comment suggested that 

the Exchange Visitor Program be closed 

and that the fees be increased to $10,991 

for application fees and $5,945 for 

individual program services. The 

Department rejected this comment as 

there is no basis or justification for such 

a proposal. The comment was not 

responsive to the proposed rule 

concepts. Another comment was from 

an academic institution and opined that 

a 54% increase in fees was such a 

financial burden on academic 

institutions that the redesignation 

period should also be increased. As no 

other academic institutions presented 

this view, we find that this comment 

does not represent the views of the 

higher academic community or its 

ability to pay this bi-annual 

redesignation fee. A further comment 

was from a private sector organization 

that combined comments to both 

opposition of the final secondary school 

student rule and the proposed fee rule 

and does not believe that the increase in 

fees will help the Department with its 

oversight responsibilities. This 

comment was not responsive to the 

proposed rule which discussed neither 

secondary school student exchanges nor 

oversight initiatives or duties of 

designated program sponsors. 

Regulatory Findings 

Administrative Procedure Act 

The Department of State is of the 

opinion that the Exchange Visitor 

Program is a foreign affairs function of 

the U.S. Government and that rules 

implementing this function are exempt 

from section 553 (Rulemaking) and 

section 554 (Adjudications) of the 

Administrative Procedure Act (APA). 

The U.S. Government supervises 

programs that invite foreign nationals to 

come to the United States to participate 

in exchange visitor programs, either 

directly or through private sector 

program sponsors or grantees. When 

problems occur, the U.S. Government 

often has been, and likely will be, held 

accountable by foreign governments for 

the treatment of their nationals, 

regardless of who is responsible for the 

problems. 

The purpose of this rule is to set the 

fees that will fund the services provided 

by the Exchange Visitor Program Office 

of Designation, which provides services 

to 1,226 sponsor organizations and 

350,000 Exchange Visitor Program 

participants. These services include 

oversight and compliance with program 

requirements as well as the monitoring 

of programs to ensure the health, safety 

and well-being of foreign nationals 

entering the United States (many of 

these exchange programs and 


srobinson on DSKHWCL6B1PROD with RULES