65942 Federal Register / Vol. 75, No. 207 / Wednesday, October 27, 2010 / Rules and Regulations 

1For purposes of this Final Rule, organized 

wholesale electric markets include energy, 

transmission and ancillary service markets operated 

by independent system operators (ISO) and regional 

transmission organizations (RTO). These entities are 

responsible for administering electric energy and 

financial transmission rights markets. As public 

utilities, they have on file as jurisdictional tariffs 

the rules governing such markets. The organized 

wholesale electric markets currently include the 

markets administered by the following RTOs and 

ISOs: PJM Interconnection, L.L.C. (PJM), New York 

Independent System Operator, Inc. (NYISO), 

Midwest Independent Transmission System 

Operator, Inc. (Midwest ISO), ISO New England Inc. 

(ISO–NE), California Independent Service Operator 

Corporation (CAISO), and Southwest Power Pool, 

Inc. (SPP). 

2 16 U.S.C. 824d, 824e (2006). 

Bluffton, OH, Bluffton, VOR RWY 23, Amdt 

7A 

Baker City, OR, Baker City Muni, Takeoff 

Minimums and Obstacle DP, Amdt 2 

Medford, OR, Rogue Valley Intl-Medford, 

RNAV (RNP) RWY 32, Orig 

Portland, OR, Portland Intl, ILS OR LOC 

RWY 10R, ILS RWY 10R (SA CAT I), ILS 

RWY 10R (CAT II), ILS RWY 10R (CAT III), 

Amdt 33A 

Hondo, TX, Hondo Muni, Takeoff Minimums 

and Obstacle DP, Orig 

Lancaster, TX, Lancaster Rgnl, NDB RWY 31, 

Amdt 3 

Lancaster, TX, Lancaster Rgnl, RNAV (GPS) 

RWY 31, Amdt 1 

Victoria, TX, Victoria Rgnl, ILS OR LOC/ 

DME RWY 12L, Amdt 11 

Fillmore, UT, Fillmore Muni, RNAV (GPS) 

RWY 4, Orig 

Fillmore, UT, Fillmore Muni, RNAV (GPS) 

RWY 22, Orig 

Fillmore, UT, Fillmore Muni, Takeoff 

Minimums and Obstacle DP, Orig 

Price, UT, Carbon County Rgnl/Buck Davis 

Field, ILS OR LOC/DME RWY 36, Orig-A 

Pasco, WA, Tri-Cities, ILS OR LOC/DME 

RWY 21R, Amdt 12 

Pasco, WA, Tri-Cities, RNAV (GPS) RWY 3L, 

Amdt 1 

Pasco, WA, Tri-Cities, RNAV (GPS) RWY 12, 

Amdt 1 

Pasco, WA, Tri-Cities, RNAV (GPS) RWY 

21R, Amdt 1 

Pasco, WA, Tri-Cities, RNAV (GPS) RWY 30, 

Amdt 2 

Pasco, WA, Tri-Cities, VOR/DME RWY 21R, 

Amdt 6 

Pasco, WA, Tri-Cities, VOR/DME RWY 30, 

Amdt 4 

Richland, WA, Richland, RNAV (GPS) RWY 

26, Amdt 1 

Seattle, WA, Boeing Field/King County Intl, 

ILS RWY 13R, Amdt 30 

Spokane, WA, Spokane Intl, ILS OR LOC 

RWY 3, ILS RWY 3 (SA CAT I), ILS RWY 

3 (CAT II), ILS RWY 3 (CAT III), Amdt 6 

Spokane, WA, Spokane Intl, RNAV (GPS) Y 

RWY 3, Amdt 2 

Spokane, WA, Spokane Intl, RNAV (GPS) Y 

RWY 7, Amdt 2 

Spokane, WA, Spokane Intl, RNAV (GPS) Y 

RWY 21, Amdt 1 

Spokane, WA, Spokane Intl, RNAV (GPS) Y 

RWY 25, Amdt 3 

Spokane, WA, Spokane Intl, VOR RWY 3, 

Amdt 13 

On September 15, 2010 (75 FR 178) the 

FAA published an Amendment in Docket 

No. 30743, Amdt 3390 to Part 97 of the 

Federal Aviation Regulations under section 

97.23 and 97.33. The following entries that 

were effective November 18, 2010, are 

changed to effective December 16, 2010: 

Fort Lauderdale, FL, Fort Lauderdale/ 

Hollywood Intl, ILS OR LOC RWY 9L, 

Amdt 21 

Fort Lauderdale, FL, Fort Lauderdale/ 

Hollywood Intl, ILS OR LOC RWY 27R, 

Amdt 9 

Fort Lauderdale, FL, Fort Lauderdale/ 

Hollywood Intl, LOC RWY 9R, Amdt 5 

Fort Lauderdale, FL, Fort Lauderdale/ 

Hollywood Intl, LOC/DME RWY 13, 

Amdt 1 

[FR Doc. 2010–26949 Filed 10–26–10; 8:45 am] 

BILLING CODE 4910–13–P 

DEPARTMENT OF ENERGY 

Federal Energy Regulatory 

Commission 

18 CFR Part 35 

[Docket No. RM10–13–000; Order No. 741] 

Credit Reforms in Organized 

Wholesale Electric Markets 

Issued October 21, 2010. 

AGENCY: Federal Energy Regulatory 

Commission, DOE. 

ACTION: Final rule. 

SUMMARY: Pursuant to section 206 of the 

Federal Power Act, the Federal Energy 

Regulatory Commission amends its 

regulations to improve the management 

of risk and the subsequent use of credit 

in the organized wholesale electric 

markets. Each Regional Transmission 

Organization (RTO) and Independent 

System Operator (ISO) will be required 

to submit a compliance filing including 

tariff revisions to comply with the 

amended regulations or to demonstrate 

that its existing tariff already satisfies 

the regulations. 

DATES: Effective Date: This Final Rule 

will become effective on November 26, 

2010. 

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. 

I. Introduction 

1. This Final Rule adopts reforms to 

credit policies used in organized 

wholesale electric power markets.1

2. The Commission has a statutory 

mandate to 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 clear 

and consistent credit practices are an 

important element of those rates. The 

management of risk and credit 

necessarily involves balance. If access to 

credit is too restrictive, competition 

suffers because fewer entities are 

eligible to participate, which can 

potentially reduce competition. 

Conversely, if more risk is tolerated and 

access to credit is too easy to obtain, 

then the market is more susceptible to 

defaults and customers bear the burden 

of the costs that flow from such defaults. 

In organized wholesale electric markets, 

defaults not supported by collateral are 

socialized among all other market 

participants. 

3. The organized wholesale electric 

markets have developed their own 

individual credit practices through their 

own tariff revisions crafted through 

their stakeholder processes. This 

evolutionary process has led to varying 

credit practices among the organized 

markets. Because the activity of market 

participants is not confined to any one 

region/market and because the credit 

rules differ, a default in one market 

could weaken that participant and have 

ripple effects in another market. In this 

way, the credit practices in all ISOs and 

RTOs may be only as strong as the 

weakest credit practice. Moreover, rapid 

market changes can quickly escalate the 

costs of the transmission and sale of 

electric energy. 

4. For these reasons, and in light of 

recent experiences in both the broader 

economy and the organized wholesale 

electric markets, the Commission has 

revisited the risk and credit procedures 

pertaining to the organized wholesale 


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3References to FTR markets in this rule also 

include the Transmission Congestion Contracts 

(TCC) markets in NYISO and the Congestion 

Revenue Rights (CRR) markets in CAISO. 

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, 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). 

5See Electric Creditworthiness Standards, Notice 

of Technical Conference, Docket No. AD04–8–000 

(issued May 28, 2004). 

6See Testimony in Technical Conference on 

Electric Creditworthiness Standards, Docket No. 

AD04–8–000, Tr. 120:2–6 (Mr. Alan Yoho, CAISO) 

(stating that CAISO was in favor of the Commission 

standardizing a number of credit practices among 

ISOs and RTOs); Id. at Tr. 128:22–129:11 (Mr. Dan 

Doyle, Vice President and CFO, American 

Transmission Company) (stating that the 

Commission should initiate a generic rulemaking 

proceeding to standardize credit practices among 

ISOs and RTOs). 

7Policy Statement on Electric Creditworthiness, 

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

8 In the technical conference hosted by 

Commission staff in May 2010, Mr. Vincent Duane 

of PJM stated that PJM feared it was within 24 hours 

of default that would cost $100 million or more. 

Testimony at Technical Conference on Credit 

Reforms in Organized Wholesale Electric Markets, 

Tr. 32 (May 11, 2010) (Mr. Vince Duane, General 

Counsel and Vice President, PJM). Additional 

testimony was submitted at the Commission’s 

technical conference in January 2009. Testimony at 

Technical Conference on Credit and Capital Issues 

Affecting the Electric Power Industry, Docket No. 

AD09–2–000, presentation of Robert Ludlow, Vice 

President and CFO, ISO–NE at 3 (‘‘Several recent 

‘near misses’ with one of the largest investment 

grade players in the region publicly announcing 

that without financial relief bankruptcy was 

imminent.’’); Id. at 9 (‘‘we believe concerns of a 

damaging drop of market liquidity are much more 

likely to occur given a major uncovered default’’); 

Id. at Tr. 93:24–25; 94:1–2 (Jan. 13, 2009) (Mr. 

Robert Ludlow, CFO ISO–NE) (‘‘we believe further 

damage from drops in liquidity and therefore 

people not clearing their transactions could 

exacerbate the problems and put the markets 

themselves in jeopardy.’’). 

9A review of commercial bond spreads for 

creditworthy entities versus three-month Treasury 

bill (T–Bill) yields indicates the ability to obtain 

commercial credit: the wider the spread, the harder 

it is to obtain commercial credit. According to 

Bloomberg, the spread for 90 day T–Bills to 90 day 

commercial paper was 448 basis points on October 

13, 2008, compared to an average spread of 53 basis 

points between April 1, 1997 and December 31, 

2009. 

10Technical Conference on Credit and Capital 

Issues Affecting the Electric Power Industry, Docket 

No. AD09–2–000, held January 13, 2009. 

11 Id. at Tr. 100:22–101:13 (Mr. Philip Leiber, 

Chief Financial Officer and Treasurer, CAISO). 

12 Id. at Tr. 91:23–25 (Mr. Robert Ludlow, Vice 

President and Chief Financial Officer, ISO–NE); see 

also Id. at Tr. 126–162 (question and answer). 

13Credit Reforms in Organized Wholesale Electric 

Markets, Notice of Proposed Rulemaking, 75 FR 

4310 (Jan. 27, 2010), FERC Stats. & Regs. ¶ 32,651 

(2010) (NOPR). 

markets under its jurisdiction. The 

Commission is thus issuing this Final 

Rule, requiring shortened settlement 

timeframes, restrictions on the use of 

unsecured credit, elimination of 

unsecured credit in all financial 

transmission rights (FTR) or equivalent 

markets,3 steps to address the risk that 

RTOs and ISOs may not be allowed to 

use netting and set-offs, the 

establishment of minimum criteria for 

market participation, clarification 

regarding the organized market 

administrators’ ability to invoke 

‘‘material adverse change’’ to demand 

additional collateral from participants, 

adopting a standardized grace period for 

‘‘curing’’ collateral calls, and 

establishing a general policy with regard 

to the differentiation in the applicability 

of these standards and reforms. 

II. Background 

A. Development of Credit Practices in 

Organized Wholesale Electric Markets 

5. The Commission has long been 

actively interested in the credit 

practices of the wholesale electric 

markets. In crafting the pro forma Open 

Access Transmission Tariff (OATT) in 

Order No. 888, the Commission directed 

that each transmission provider’s tariff 

include reasonable creditworthiness 

standards.4 However, in response to the 

credit downgrades in the energy 

industry of 2001–2002,5 and the 

resulting severe contraction in the credit 

markets, the Commission held a 

technical conference in which it 

received significant testimony that it 

should take action regarding credit 

practices in the organized electricity 

markets.6

6. This led the Commission to issue 

a Policy Statement on Electric 

Creditworthiness,7 which provided 

market participants and market 

administrators with guidance to develop 

more robust credit practices. 

7. Since it was issued, the ISOs and 

RTOs have made incremental progress 

in implementing the suggestions 

contained in the Policy Statement. 

However, the results of these efforts 

have been varied, leading to a wide 

range of risk management and 

creditworthiness practices among ISOs 

and RTOs. Because currently a default 

by one market participant is routinely 

socialized among all of the others in an 

ISO or RTO, this variable development 

of risk management practices has left 

many utilities at risk for a disruption in 

the market. 

B. Credit Crunch of 2008 and 

Subsequent Events 

8. During the autumn of 2008, large 

disruptions in the financial markets 

affected the credit markets and reduced 

the availability of credit. The electricity 

markets were vulnerable to the effects of 

this broader financial crisis as concern 

grew that default in the organized 

markets could lead to a damaging drop 

in market liquidity placing the markets 

themselves in jeopardy.8 And one of the 

other effects of the crisis in the financial 

markets at that time was that credit 

went from being relatively plentiful and 

inexpensive to relatively scarce and 

expensive.9

9. The Commission held a technical 

conference in January of 2009 to 

investigate the role of credit in light of 

the recent financial crisis.10 While the 

organized wholesale electric markets 

had generally functioned well overall, 

there were representations that 

improvements could be made based on 

the recent experience. Mr. Philip Leiber 

of CAISO stated that defaults in the PJM 

FTR markets spurred credit reforms at 

CAISO, but the threat of problems from 

larger market participants, especially 

related to a Bear Stearns subsidiary, also 

‘‘tested our concerns.’’ 11 Others testified 

about ‘‘recent near-misses’’ in the 

organized wholesale markets and 

suggested that the Commission should 

consider improvements in credit 

practices.12

10. In light of these events, the 

Commission proposed that the different 

credit practices among the organized 

wholesale electric markets must be 

strengthened. 

C. Notice of Proposed Rulemaking on 

Credit Reforms in Organized Wholesale 

Electric Markets 

11. On January 21, 2010, the 

Commission issued a NOPR pursuant to 

the Commission’s responsibility under 

section 206 of the Federal Power Act 

(FPA).13 The Commission proposed the 

following reforms related to the 

administration of credit in the organized 

markets: (1) Implementation of a billing 

period of no more than seven days and 

a settlement period of no more than 

seven days; (2) reduction in the 

allocation of unsecured credit to no 

more than $50 million per market 

participant and a further aggregate cap 

per corporate family; (3) elimination of 

unsecured credit for FTR markets, (4) 

clarification of the ISOs/RTOs’ status as 

a party to each transaction so as to 

eliminate any ambiguity or question as 

to their ability to net and manage 

defaults through the offset of market 

obligations; (5) establishment of 

minimum criteria for market 

participation; (6) clarification of when 


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65944 Federal Register / Vol. 75, No. 207 / Wednesday, October 27, 2010 / Rules and Regulations 

14 Id. P 9. 

15Committee of Chief Risk Officers (CCRO) 

submitted comments about the credit practices of 

electricity markets outside the United States, such 

as NordPool Clearing ASA (Scandinavian 

countries), Powernext (France), NEMMCO 

(Australia), SEMO (Ireland), Elexon (Britain), and 

EMC (Singapore). CCRO March 29, 2010 Comments 

at 4 and Attachment B at 25–26. See also, e.g., 

Market Reform, ‘‘PJM Credit and Clearing Analysis 

Project Findings and Recommendations’’ (June 

2008), for a review of other markets, at http:// 

www.pjm.com//media/committees-groups/ 

committees/mc/20080626/20080626-item-03dcrmsc-market-reform-credit-recommendations.ashx; 

and CME market requirements at http:// 

www.cmegroup.com/clearing/financial-andcollateral-management. 

16The commenters are listed in an appendix to 

this Final Rule. 

17Notice Establishing Date for Comments, 75 FR 

27552 (May 17, 2010). 

18Some parties sought clarification of the 

Commission’s definition of ‘‘settlement cycle’’ in the 

NOPR, recognizing that settlement encompasses 

both the billing period and the additional time for 

final payment of the billed amount. The 

Commission will therefore refer to each period 

separately as the ‘‘billing period’’ and the 

‘‘settlement period.’’ 

19Policy Statement, 109 FERC ¶ 61,186, at P 21. 

20 ISO New England, Inc. and New England Power 

Pool, 132 FERC ¶ 61,046 (2010). 

21Midwest ISO March 29, 2010 Comments at 4. 

22PJM March 29, 2010 Comments at 21. 

23SPP March 29, 2010 Comments at 3. 

24CAISO March 29, 2010 Comments at 8. 

25Northeast ISOs March 29, 2010 Comments at 

n.17; NYISO OATT at section 2.7.3.2. 

26NOPR, FERC Stats. & Regs. ¶ 32,651 at P 14 & 

n.20 (citing PJM Credit & Clearing Analysis Project: 

Findings & Recommendations (June 2008) (found 

on Dec. 31, 2009 at: http://www.pjm.com/∼/media/ 

committees-groups/committees/mc/20080626/ 

20080626-item-03d-crmsc-market-reform-creditrecommendations.ashx)). 

27See Policy Statement, 109 FERC ¶ 61,186, at P 

22 (citing Memorandum to NEPOOL Participants 

Committee re: Amendments to Billing Policy and 

Financial Assurance Policies to Implement Weekly 

Billing, Paul Belval and Scott Myers, NEPOOL 

Counsel, Feb. 21, 2004). 

28SESCO Enterprises LLC, Jump Power LLC, 

Energy Endeavors LP, Big Bog Energy LP, Silverado 

Energy LP, Gotham Energy Marketing LP, Rockpile 

Energy LP, Coaltrain Energy LP, Longhorn Energy 

LP, and GRG Energy LLC. 

the ISO or RTO may invoke a ‘‘material 

adverse change’’ clause in requiring 

additional collateral; and (7) 

establishment of a standard grace period 

to ‘‘cure’’ collateral calls. 

12. The Commission reasoned that the 

proposed reforms were necessary to 

address the lack of standardized credit 

practices and the potential for 

mutualized default risk.14

D. The Need for Credit Reform in the 

Organized Wholesale Electric Markets 

13. Sound credit practices are 

necessary to prevent a disruption in the 

system, and it is not acceptable to wait 

until after a disruption to implement the 

necessary standards. The Commission 

acknowledges the short-term costs of 

compliance with the credit practices 

required in this Final Rule but finds that 

they are outweighed by the stability that 

those credit practices provide to the 

markets and their participants. 

Therefore, in compliance filings to be 

submitted providing tariff revisions to 

comply with the Final Rule, ISOs and 

RTOs should apply these standards to 

market participants. 

14. The Commission has considered 

the comments submitted, as well as the 

practices of electricity markets outside 

the United States and in other 

commodity markets.15 The Commission 

has used the experience of these 

markets in addition to its own review of 

the organized markets in issuing this 

Final Rule. 

15. Comments were due on or before 

March 29, 2010.16 Commission staff 

held a subsequent technical conference 

on May 11, 2010 on whether ISOs and 

RTOs should adopt tariff revisions to 

clarify their status as a party to each 

transaction so as to eliminate ambiguity 

regarding their ability to ‘‘set-off’’ market 

obligations. Additional comments on 

that subject were due on or before June 

8, 2010.17

III. Discussion 

A. Shortening the Settlement Cycle 

16. As noted above, in developing this 

Final Rule, the Commission has 

considered the practices of other 

commodity markets, as well as 

electricity markets around the world. 

While we note that many other 

commodity markets employ risk 

management practices that are useful in 

minimizing the risk of a socialized 

default among other participants in 

those markets, we are also mindful of 

the importance of the continued reliable 

delivery of electricity and that some 

market participants have ‘‘provider of 

last resort’’ obligations that require them 

to continue transacting in a market, 

even under challenging financial 

conditions. 

17. The Commission and participants 

in the electric industry have recognized 

a correlation between a reduction in the 

‘‘settlement cycle’’ 18 and a reduction in 

costs attributed to a default. As the 

Commission noted in its Policy 

Statement, ‘‘the size of credit risk 

exposure is, in large part, a function of 

the length of time between completion 

of various parts of electricity 

transactions, i.e., the provision of 

service, the billing for service, and the 

payment of service.’’ 19

18. Currently, each ISO and RTO has 

its own time period for billing and 

settlement. ISO–NE has weekly billing 

(soon to be twice-weekly), with payment 

due no later than the second business 

day after the invoice is issued.20

Midwest ISO has weekly billing, with 

payment due seven days after the 

weekly invoice is issued.21 PJM has 

weekly billing and settlement.22 SPP has 

weekly billing, with payment due the 

Wednesday after the invoice is issued.23

CAISO has semi-monthly billing, with 

five additional days for settlement.24

NYISO has monthly billing, with 

payment due by the first banking day 

common to all parties after the 15th day 

of the month that the invoice is 

rendered by the ISO.25

19. To minimize the risk associated 

with the duration of the settlement 

period, the Commission proposed in the 

NOPR to require no more than seven 

days for each ISO/RTO market billing 

period plus no more than seven 

calendar days for settlement. The 

Commission cited a PJM study that 

found that movement from monthly to 

weekly billing would reduce credit risk 

exposure by $2.1 billion (68 percent), 

and that necessary financial security 

provided by members would be reduced 

by $700 million (73 percent).26 Further, 

the Commission’s earlier Policy 

Statement cited an ISO–NE report that 

its movement to a weekly billing period 

resulted in a 67 percent reduction in 

financial assurances that had to be 

produced by its market participants.27

The Commission also sought comment 

on the practicality of moving organized 

wholesale electric markets to daily 

billing within one year of 

implementation of weekly billing. 

20. The Commission recognized that 

net buyers in organized markets might 

incur cash management costs because 

they would be obligated to pay their 

debts on a seven-day basis, but receive 

cash from retail sales on a 30-day basis. 

In the NOPR, the Commission thus 

recognized that cash management 

facilities to facilitate more frequent 

payments might be necessary and 

sought comments on this particular 

issue. 

21. The Commission also noted that 

ISOs and RTOs may need to make 

software changes to accommodate a 

shortened settlement cycle and 

encouraged ISOs and RTOs to use 

software that is already in use in 

markets that are currently operating on 

a seven-day settlement cycle. 

1. Comments 

22. Parties in favor of the proposal 

include a number of the ISOs and RTOs, 

as well as financial entities such as 

‘‘Financial Marketers,’’ 28 Citigroup 

Energy (Citigroup), J.P. Morgan Ventures 

Energy Corporation (J.P. Morgan), and 


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29Although the comments submitted by CFTC 

staff were focused on the FTR markets, they also 

recommend requiring each ISO or RTO to establish 

daily settlement as soon as practicable. CFTC staff 

March 29, 2010 Comments at 5. 

30New York Suppliers March 29, 2010 Comments 

at 7; Calpine March 29, 2010 Comments at 1; 

Dominion March 29, 2010 Comments at 2; Mirant 

March 29, 2010 Comments at 3–4; Powerex March 

29, 2010 Comments at 4–5. 

31CCRO March 29, 2010 Comments at 3. 

32New York Suppliers March 29, 2010 Comments 

at 9. 

33 Id. at 9–10. 

34 IPPNY March 29, 2010 Comments at 12–13. 

35Powerex March 29, 2010 Comments at 6–7. 

36CAISO March 29, 2010 Comments at 7–8. 

37The ‘‘Six Cities’’ include the cities of Anaheim, 

Azusa, Banning, Colton, Pasadena, and Riverside, 

all located in California. 

38City of New York March 29, 2010 Comments 

at 6–7; NYPSC March 29, 2010 Comments at 3–4. 

39NYPSC March 29, 2010 Comments at 7–8; 

NYSCPB March 29, 2010 Comments at 3. 

40 Indiana Municipal Power Agency, Madison Gas 

& Electric Company, Missouri River Energy 

Services, Southern Minnesota Municipal Power 

Agency and WPPI Energy. 

41Midwest TDU March 29, 2010 Comments at 7– 

9; Consolidated Edison Solutions March 29, 2010 

Comments at 3–4. 

42PG&E March 29, 2010 Comments at 2. 

43 J.P. Morgan Comments at 6; MSCG Comments 

at 2–3. 

44CFTC staff Comments on 5. 

45Calpine Comments at 4 & n.8 (citing ISO New 

England, Inc. and New England Power Pool March 

26, 2010 filing, Docket No. ER10–942–000). 

46Calpine Comments at 4. 

47 Id. at 5. 

48CAISO Comments at 9; IRC Comments at 4–5; 

MISO Comments at 5; PJM Comments at 21–23. 

49APPA Comments at 17; NRECA Comments at 

10; NYAPP Comments at 10; PPANJ Comments at 

10–11. 

50Basin Electric Comments at 3. 

Morgan Stanley Capital Group (Morgan 

Stanley). The staff of the Division of 

Clearing & Intermediary Oversight at the 

Commodity Futures Trading 

Commission (CFTC staff) also supports 

moving the billing cycle to, at most, 

seven days.29

23. Many industry participants who 

are normally ‘‘net sellers’’ of supply such 

as Constellation, NRG, Calpine, 

Dominion, Mirant, and Powerex also 

support the proposed shortened billing 

time-period.30 CCRO supports a 

standard seven-day billing period as 

‘‘consistent’’ with its review of best 

practices in the electric industry.31 The 

New York Suppliers note that NYISO is 

the lone organized market in the nation 

with a monthly billing period.32 The 

New York Suppliers contend that 

allowing NYISO—or CAISO which 

currently has a two-week billing cycle— 

to remain out of step with a weekly 

standard elsewhere increases the risks 

to participants in New York and 

California.33 The Independent Power 

Producers of New York (IPPNY) 

comments that, since the beginning of 

weekly billing in ISO–NE, the number 

of market participants has increased in 

every sector and the total number of 

market participants increased by over 60 

percent,34 suggesting that not only was 

liquidity enhanced by shorter billing but 

the change did not pose a barrier to 

entry. 

24. Powerex states that moving to a 

weekly standard for billing will lower 

the amount of financial security 

required which should address concerns 

of smaller or municipal market 

participants. Powerex also agrees with 

the Commission’s suggestion that ISOs 

and RTOs should use existing software 

that can accommodate this billing cycle, 

in order to minimize any transition 

delays.35

25. CAISO, alone among the 

organized markets, doubts that moving 

to a weekly billing standard would 

result in significant benefits as it would 

reduce aggregated outstanding liabilities 

by only an additional 10 percent. CAISO 

expresses concern that weekly billing 

could significantly affect market 

participants given that it has already 

shortened the cycle from 90 days and 

that going further now might be 

disruptive. Nevertheless, CAISO also 

explains that its future plans are to 

move to weekly billing.36

26. Parties opposing the proposal 

include the City of New York, the New 

York State Public Service Commission 

(NYPSC) and ‘‘Six Cities.’’ 37 Indeed, the 

City of New York and the NYPSC argue 

that the Commission should not impose 

a shorter settlement period just for the 

sake of uniformity and that the 

Commission should give deference to 

the policies adopted through ISO and 

RTO governance processes.38 The 

NYPSC and the New York State 

Consumer Protection Board (NYSCPB) 

further contend that weekly billing 

could result in a wealth transfer from 

some market participants to others.39

27. Other parties oppose movement to 

weekly billing based on data concerns, 

including net sellers such as Midwest 

Transmission Dependent Utilities 

(Midwest TDU) 40 and Consolidated 

Edison Solutions.41 This point was 

similar to the concerns of Bonneville 

Power Administration (BPA) who, while 

supportive of weekly billing, has 

concerns about the ability of CAISO to 

effectively manage the resulting 

increased demands. PG&E argues 

against reducing billing cycles in the 

organized wholesale market without a 

similar billing period in the bilateral 

market, because it would create an 

opportunity for sellers to operate with 

reduced need for working capital and 

shifts liquidity risk from sellers to 

buyers.42

28. Regarding the Commission’s 

request for comment on the practicality 

of organized wholesale electric markets 

implementing daily settlement periods 

within one year of implementation of 

weekly settlement periods, there was 

very little commenter support for this 

proposal. Most of the support for this 

proposal came from financial entities. 

CFTC staff, J.P. Morgan and Morgan 

Stanley support this proposal.43 CFTC 

staff argues that routine and frequent 

settlement imposes discipline on 

participants, in that it discourages 

participants from entering into new 

positions without first ensuring that 

they have adequate liquidity to support 

such positions. CFTC staff also states 

that the collection of payments from 

FTR market participants should happen 

promptly, within hours or overnight.44

29. Calpine also supports daily 

settlement. Calpine notes that this is 

achievable, as shown by ISO–NE in its 

plans to implement twice weekly 

billing.45 Calpine also notes that some 

stakeholders oppose compression of the 

settlement cycle, arguing that 

operational issues and the quality of 

data available do not support daily 

settlements. Calpine states that these 

concerns may be true for the real time 

market (RTM), but they do not apply to 

the day-ahead market (DAM).46 Calpine 

requests that the Commission consider 

moving towards daily billing by 

requiring ISOs/RTOs to split the DAM 

from other markets and settle the DAM 

daily.47

30. However, many stakeholder group 

members opposed daily settlement. 

CAISO, the IRC, Midwest ISO, and PJM 

do not support daily invoicing. CAISO, 

Midwest ISO and PJM all cite financial 

and logistical concerns as reasons to 

oppose daily billing. The IRC does not 

believe the Commission should mandate 

a move to daily settlement periods, but 

should allow ISOs/RTOs to work with 

stakeholders to research the proposal 

further to evaluate the daily costs and 

benefits. PJM states that stakeholder 

discussions should occur prior to 

determining whether such a change 

would be cost beneficial to the market 

participants in the PJM region. PJM also 

states that its current settlement system 

does not have the flexibility to issue 

daily invoices.48

31. APPA, NRECA, NYAPP, and New 

Jersey Public Power cite the cost of daily 

settlements as their reason not to 

support it.49 Basin Electric believes 

daily settlements would be 

administratively burdensome.50


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65946 Federal Register / Vol. 75, No. 207 / Wednesday, October 27, 2010 / Rules and Regulations 

51Midwest TDUs Comments at 11–12. 

52NRECA Comments at 10. 

53WAPA Comments at 5–6. 

54Policy Statement, 109 FERC ¶ 61,186, at P 24. 

55See, e.g., Market Reform, ‘‘PJM Credit and 

Clearing Analysis Project Findings and 

Recommendations’’ (June 2008) see http:// 

www.pjm.com/∼/media/committees-groups/ 

committees/mc/20080626/20080626-item-03dcrmsc-market-reform-credit-recommendations.ashx; 

NEPOOL Participants Committee, Weekly Billing 

Presentation, (January 9, 2004). 

56SPP March 29, 2010 Comments at 4. 

57CAISO March 29, 2010 Comments at 10–11 and 

PJM Tariff at Sixth Revised Sheet No. 523G. 

58Midwest ISO March 29, 2010 Comments at 6 

and Exhibit IA (ISO New England Financial 

Assurance Policy) of ISO New England Inc. 

Transmission, Markets and Services Tariff. 

59NYISO March 29, 2010 Comments at 10. 

60The Northeast ISOs refer to joint comments 

filed by ISO–NE, PJM, and NYISO. 

Midwest TDUs state that daily 

settlements are unworkable now and in 

the foreseeable future, and should be 

addressed by the individual ISOs/ 

RTOs.51 NRECA also points out that the 

movement to shortened settlement 

cycles would occur at the same time 

utilities implement ‘‘smart grid’’ 

applications and NRECA questions 

whether all metering and computer 

hardware and software systems can be 

done at the same time.52 Western Area 

Power Administration (WAPA) believes 

daily settlements are impractical and it 

would not allow the opportunity to 

correct errors which could use up all 

available funds unnecessarily in a 

matter of a few days. WAPA is 

concerned about daily settlements and 

the timing of the CAISO invoices, which 

are issued at midnight, because it would 

unfairly shorten the daily settlement 

processing period to less than 24 

hours.53

2. Commission Determination 

32. In this Final Rule, the Commission 

adopts the NOPR proposal to direct each 

ISO and RTO to submit a compliance 

filing that includes tariff revisions to 

establish billing periods of no more than 

seven days and settlement periods of no 

more than seven days after issuance of 

bills. This compliance filing must be 

submitted by June 30, 2011, with the 

tariff revisions to take effect October 1, 

2011. While the Commission has, in the 

past, not required shortened billing 

periods, in order to promote market 

liquidity,54 we find it is a necessary 

component of a package of reforms 

designed 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. We find unpersuasive 

comments that shortened billing and 

settlement cycles will compromise the 

liquidity of the organized wholesale 

electric markets. 

33. The basic premise for shorter 

billing periods is that the reduced 

amount of unpaid debt left outstanding 

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. 

In addition, the reduction in 

outstanding obligation also decreases 

the amount of collateral that market 

participants must post, which mitigates 

the affect on market participants of 

reducing the amount of unsecured 

credit the ISOs and RTOs can extend. 

The Commission’s decision is supported 

by the studies performed by ISO–NE 

and PJM.55

34. The Commission does not agree 

with the statement of the NYPSC or the 

City of New York that the movement to 

a weekly billing period will be a ‘‘wealth 

transfer’’ from buyers to sellers. The 

Commission is focused on the benefits 

of reduced risk afforded to all market 

participants by a minimum standard of 

weekly billing. While short-run working 

capital costs may be shifted, the result 

is that the overall cost of default will be 

lower for every market participant. 

Thus, all participants will benefit in this 

circumstance. 

35. The Commission also disagrees 

that there may be problems verifying 

data. ISO–NE, SPP, and Midwest ISO 

have shown that they can administer 

weekly billing without significant 

incident. The experience of these 

markets suggests that data handling and 

verification should not pose 

insurmountable challenges. Regarding 

PG&E’s discussion of reduction of 

billing time in the bilateral markets, the 

Commission believes that individual 

counterparties to bilateral contracts may 

negotiate their own billing terms. 

36. As for parties that urged the 

Commission to not mandate a ‘‘one size 

fits all’’ approach in establishing 

minimum billing periods or that the 

Commission should defer to 

stakeholders in this matter, the 

Commission disagrees. Nothing in this 

record suggests that any of the organized 

wholesale electric markets is differently 

situated in a manner that warrants 

deviating from this minimum standard 

for billing periods. 

37. Recognizing the benefits that will 

flow from requiring billing to be at least 

weekly, and balancing the incremental 

benefits and incremental burdens of 

daily billing, we will not require daily 

billing at this time. Instead we will 

require, as discussed above, weekly 

billing. 

B. Use of Unsecured Credit 

38. The use of unsecured credit varies 

among the organized markets. SPP 

currently limits extensions of unsecured 

credit to any single entity or affiliated 

group of entities to $25 million.56

CAISO and PJM extend no more than 

$50 million per market participant.57

Midwest ISO and ISO–NE allow up to 

$75 million per market participant,58

and NYISO extends up to $150 million 

per market participant.59

39. In the NOPR, the Commission 

proposed to require each ISO and RTO 

to revise its tariff provisions to reduce 

the extension of unsecured credit to no 

more than $50 million per market 

participant. The Commission sought 

comment on whether there should be a 

further corporate cap to cover an entire 

corporate family. Consideration of an 

overall corporate family cap on the use 

of unsecured credit was based on 

experience in the RTO and ISO markets 

where many entities have multiple 

subsidiary companies operating in the 

same market. Since these entities often 

use the same balance sheet for credit 

purposes, limits on the entire corporate 

family would ensure that multiple, 

related market participants could not 

defeat the purpose of limiting unsecured 

credit. Finally, the Commission sought 

comment on whether it should 

eliminate the extension of unsecured 

credit in connection with adopting daily 

settlements. 

1. Comments 

a. Individual Market Participant Cap 

40. Many commenters support the 

proposal to limit the extension of 

unsecured credit to no more than $50 

million per participant, but make more 

nuanced comments in how the credit 

limit should be applied. CAISO, the 

Northeast ISOs,60 and the ISO–RTO 

Council (IRC) favor a generic $50 

million ‘‘cap’’ on the use of unsecured 

credit per participant, rather than a 

mandated limit of $50 million per 

participant, such that individual ISOs or 

RTOs may file with the Commission to 

establish lower limits on unsecured 

credit as appropriate. 

41. The proposed limit on unsecured 

credit is supported by financial 

participants (Citigroup Energy Inc., 

Financial Marketers), some public 

power participants (Northern California 

Power Agency, Public Power 

Association of New Jersey and Madison, 

New Jersey (New Jersey Public Power), 

and Basin Electric), some retail 

providers (Direct Energy), and suppliers 

(the Electric Power Supply Association 


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Federal Register / Vol. 75, No. 207 / Wednesday, October 27, 2010 / Rules and Regulations 65947 

61New Jersey Public Power Comments at 10. 

62Powerex March 29, 2010 Comments at 7–8. 

63CPUC March 29, 2010 Comments at 3. 

64 Id. at 3–4. 

65AMP, APPA, CES, EEI, MSCG, NIPSCO, SPP, 

Midwest TDUs, and Wisconsin parties. 

66NSCG March 29, 2010 Comments at 4. 

67Consolidated Edison Solutions March 29, 2010 

Comments at 4. 

68APPA March 29, 2010 Comments at 4. 

69Northeast ISOs March 29, 2010 Comments at 6– 

7. 

70Basin Electric March 29, 2010 Comments at 3. 

71NRECA March 29, 2010 Comments at 11. 

72Shell Energy March 29, 2010 Comments at 7. 

73Morgan Stanley March 29, 2010 Comments at 

4–5. 

74EPSA March 29, 2010 Comments at 7. 

75SDG&E March 29, 2010 Comments at 4. 

76While Lehman Brothers was not itself a public 

utility, it was in many ways no different from other 

financial institutions that are or are affiliated with 

public utilities. In a June 17, 2009 email to market 

participants, PJM indicated that Lehman Brothers 

Commodity Services, Inc., defaulted on $18.1 

million in obligations to PJM. http:// 

www.pjm.com//media/about-pjm/member-services/ 

default-notification/lbcs-default-update.ashx. 

(EPSA)). While they support the 

proposed limit on unsecured credit, 

New Jersey Public Power state that there 

may come a time when a $50 million 

cap is not adequate and preventing full 

participation in PJM markets so the 

Commission should provide flexibility 

to allow municipal utility participation 

without such an unsecured credit cap.61

One party, DC Energy, does not believe 

that the use of unsecured credit should 

be allowed in any market. Powerex 

suggests that, not only should the 

Commission adopt a $50 million limit 

on the use of unsecured credit, the 

Commission should attempt to 

determine if the amount could be 

further reduced as a consequence of a 

minimum standard on billing periods.62

The National Rural Electric Cooperative 

Association (NRECA) specifically does 

not oppose the proposed limit on 

unsecured credit. Hess Corporation 

(Hess) states that the limit of unsecured 

credit should be no more than $50 

million and should apply to all market 

participants. 

42. The CPUC asserted that the 

Commission should not arbitrarily limit 

unsecured credit. To the extent the 

Commission decides to limit unsecured 

credit, CPUC suggests limiting 

unsecured credit to a level that 

corresponds to the settlement cycle.63

When determining the amount of 

unsecured credit for a given entity, the 

CPUC recommends using a process 

which is based on a consistent, 

systematic, and non-discriminatory 

approach. The CPUC states that market 

participants with higher credit ratings 

should be allowed to have higher 

unsecured credit.64

43. A number of commenters support 

the continued use of unsecured credit, 

and state that the Commission should 

allow each ISO/RTO, through the 

stakeholder process, to determine a 

formula or method to limit the amount 

of unsecured credit.65 EEI states that the 

Commission should require the ISO/ 

RTO to justify the maximum amount of 

unsecured credit that the ISO/RTO 

permits to any participants using a 

formula. Morgan Stanley states that 

credit should be extended based upon 

an application of objective financial 

criteria to evaluate carrying capacity 

and default probabilities.66

Consolidated Edison Solutions states 

that a national cap would not recognize 

the creditworthiness of financially 

strong companies and may set the level 

too low for regions with high energy 

costs.67 APPA believes that each RTO 

should tailor their credit policies to take 

into account the respective financial 

strengths and business models of the 

various market participants.68

44. Similarly, Consumers Energy 

indicates that a uniform $50 million cap 

would be an illusory goal given the 

differing methods for analyzing credit in 

the ISOs/RTOs. 

b. Aggregate Corporate Family Cap 

45. Most parties also support an 

aggregate family cap but debate whether 

it should be mandated by the 

Commission or determined by each ISO/ 

RTO through a stakeholder process. The 

Northeast ISOs argue that, due to 

regional variations, market operators 

should have flexibility in determining 

the appropriate level of any aggregate 

corporate cap.69 Basin Electric agrees 

with this approach, but argues that the 

criteria should be consistently 

applied.70

46. NRECA indicates it does not 

oppose an aggregate cap on corporate 

families and suggests an unsecured 

credit limit of $100 million per 

corporate family.71 Shell Energy, on the 

other hand, agrees with the proposal to 

have an aggregate corporate cap but 

suggests that it be the same as the $50 

million cap suggested in the NOPR for 

an individual participant.72

47. Morgan Stanley opposes an 

aggregate cap and further urges the 

Commission to explicitly mandate that, 

in determining how much credit to 

extend to a market participant, the ISOs 

and RTOs consider the parent company 

guarantees of a market participant’s 

market activity.73 EPSA states that an 

aggregate cap does not make sense for a 

holding company that holds both 

regulated utility subsidiaries and 

unregulated market participants.74 San 

Diego Gas & Electric (SDG&E) also 

opposes an aggregate cap, stating that it 

is both unnecessary in California and 

would frustrate the CPUC affiliate 

transaction rules, which ‘‘requires that a 

parent backing its affiliates be subject to 

a $50 million maximum unsecured 

credit limit.’’ 75

c. Different Cap for Markets of Different 

Size 

48. In the NOPR, the Commission 

asked whether the caps on unsecured 

credit should differ as a result of 

differing market size. BP Energy 

specifically notes that the size of the 

market should make a difference in 

terms of the amount of unsecured credit 

allowed and that the Commission 

should not mandate a particular 

amount. MidAmerican agrees and states 

that any limit should be formulaic. 

Mirant favors avoiding a ‘‘one size fits 

all’’ approach to setting unsecured credit 

limits. PSEG suggests that the cap 

should be based upon the risk of each 

individual market participant and 

factors unique to each ISO/RTO. 

Consequently, PSEG argues, this issue is 

best left to each ISO/RTO and its 

stakeholders. 

2. Commission Determination 

49. The Commission adopts the NOPR 

proposal to require each ISO and RTO 

to revise its tariff provisions to reduce 

the extension of unsecured credit to no 

more than $50 million per market 

participant. 

50. The Commission is concerned that 

RTOs and ISOs, even after analyzing the 

creditworthiness of market participants, 

have allowed large amounts of 

unsecured credit in their markets 

(during the financial crisis in fall 2008, 

ranging from 50 to 80 percent). The 

Commission recognizes that unsecured 

credit may provide increased liquidity 

in the organized wholesale electric 

markets and is only extended after the 

ISO/RTO has performed a credit 

analysis of the market participant 

receiving the unsecured credit. 

However, the Commission is concerned 

that the assumptions upon which any 

credit analysis is made can change 

rapidly. For instance, Lehman Brothers 

was rated as ‘‘investment grade’’ by all 

ratings agencies on Friday, September 

12, 2008, only to file for bankruptcy on 

Monday, September 15, 2008.76 The 

Commission considered several factors, 

as well as the comments, in establishing 

the $50 million cap on unsecured credit 

per market participant. We note that 

CAISO and PJM have adopted a $50 


jdjones on DSK8KYBLC1PROD with RULES
65948 Federal Register / Vol. 75, No. 207 / Wednesday, October 27, 2010 / Rules and Regulations 

77To date, the Power Edge LLC default of $51.7 

million in PJM was the most significant in total 

value in an organized wholesale electric market. 

PJM Interconnection, L.L.C. v. Accord Energy, LLC, 

127 FERC ¶ 61,007, Enforcement Staff Report at 1 

n.5 (2009). 

78NOPR, FERC Stats. & Regs. ¶ 32,651 at P 17 

(citing California Independent System Operator 

Corp., 129 FERC ¶ 61,142 at P 14 (2009) (adopting 

limit of $50 million of unsecured credit per market 

participant); PJM Interconnection, L.L.C., 127 FERC 

¶ 61,017 at P 5 (2009) (adopting limit of $50 million 

for a member company and $150 million for an 

affiliated group)). 

79For instance, Lehman Brothers declared 

bankruptcy as a corporate family, disrupting the 

financial markets. See Report of Anton R. Valukas, 

Examiner, submitted in In re Lehman Brothers 

Holdings Inc., et al., (Bankr. S.D.N.Y., Mar. 11, 

2010), found at: http://lehmanreport.jenner.com/ 

VOLUME%201.pdf. A similar default by a market 

participant could result in a significant disruption 

in an organized wholesale electric market. 

80A firm transmission right or FTR is a ‘‘financial 

instrument[] used to hedge the risk of transmission 

congestion by entitling the holders of [this] 

instrument[] to compensation for transmission 

congestion charges.’’ PJM Interconnection, LLC, 127 

FERC ¶ 61,025, at P 2 (2009). 

81A ‘‘prevailing flow’’ FTR is one in which the 

historic movement of power from a lower priced 

area to a higher priced area occurs under normal 

transmission system operation. This is normally 

defined over a period of years by the ISO/RTO and 

may reflect contractual obligations that predate ISO 

or RTO establishment. 

million cap on unsecured credit for a 

single market participant, indicating 

that this level has already been accepted 

and incorporated into the business 

practices of market participants 

throughout the country. Most 

importantly, based on experience with 

past defaults, we are persuaded that the 

organized wholesale electric markets 

could withstand a default of this 

magnitude by a single market 

participant.77 The Commission further 

believes that this cap on unsecured 

credit per market participant balances 

the interests of market participants by 

not raising costs by an unreasonable 

amount while still protecting the 

markets and their participants from 

unacceptable disruption. 

51. Moreover, as noted in the NOPR, 

as the timeframe of settlement shrinks, 

so does the amount of unsecured credit 

that a participant may need. This is 

because the number of outstanding 

transactions and the size of the amounts 

outstanding become smaller, thus 

minimizing the credit exposure to any 

market participant.78 Reducing the 

amount of unsecured credit extended 

before there is a crisis, combined with 

a shortened settlement cycle, should 

reduce the risk of a mutualized default 

and any potential market disruption. 

52. As discussed earlier, the 

Commission must balance the needs of 

market liquidity with overall risk. To 

achieve this balance, the Commission 

directs each ISO and RTO to submit a 

compliance filing that includes tariff 

revisions to establish a limit on 

unsecured credit of no more than $50 

million per market participant. This 

compliance filing must be submitted by 

June 30, 2011, and the tariff revisions 

will take effect October 1, 2011. In 

response to commenters who argue that 

markets that are a different size should 

have different caps on unsecured credit, 

we note that the $50 million limit on 

unsecured credit is a ceiling, not a 

mandated amount. Any organized 

wholesale electric market may establish 

a lower limit, either for individual 

market participants or based on the 

market administrator’s credit analysis of 

a particular market participant. 

53. The Commission further 

establishes, for each organized 

wholesale electric market, a maximum 

level of $100 million of unsecured 

credit for all entities within a corporate 

family. This level would allow multiple 

market participants within one 

corporate family to each have access to 

a significant level of unsecured credit, 

up to $50 million in each organized 

wholesale electric market as indicated 

above, to conduct business. Adoption of 

an overall corporate family cap of $100 

million of unsecured credit in each 

organized wholesale electric market 

reflects our experience in the RTO and 

ISO markets where many entities have 

multiple subsidiary companies 

operating in the same market. By 

implementing a cap on a corporate 

family, the Commission avoids a 

scenario in which multiple market 

participants within one corporate family 

have $50 million in unsecured credit 

per participant, and a bankruptcy of the 

entire corporate family results in a 

significant default in an organized 

wholesale electric market.79 As 

indicated by Mr. Duane’s testimony at 

the technical conference, a default of 

$100 million in an organized wholesale 

electric market would be significant, 

even in a market the size of PJM. 

Moreover, we believe that this level of 

unsecured credit strikes a balance by 

not raising costs for market participants 

by an unreasonable amount while still 

protecting the markets and their 

participants from unacceptable 

disruption. 

54. The Commission thus directs each 

ISO and RTO to submit a compliance 

filing that includes tariff revisions to 

establish an aggregate cap on unsecured 

credit per corporate family of no more 

than $100 million. This compliance 

filing likewise must be submitted by 

June 30, 2011, and the tariff revisions 

will take effect October 1, 2011. Similar 

to the cap on individual market 

participants, each ISO or RTO may 

establish a lower level for the aggregate 

cap. 

55. The Commission views the limits 

as an upper ceiling or limit which will 

allow for varied amounts below the $50 

million and $100 million thresholds. 

The Commission agrees that limits 

below the Commission-prescribed levels 

can be set depending on relative market 

size, the price of energy, the number of 

megawatt hours, and the size and 

number of the members, for example. 

56. The Commission also believes that 

the contention of Morgan Stanley, that 

ISOs and RTOs should explicitly 

consider parent guarantees in their 

evaluation of credit, is contrary to the 

point of this rulemaking. Parent 

guarantees are simply another form of 

unsecured credit that will not 

necessarily protect a market from 

default by market participants if the 

parent company experiences financial 

distress, and the Commission directs 

ISOs and RTOs to not take them into 

account in establishing the appropriate 

level of unsecured credit for a market 

participant or aggregate cap. 

57. The Commission further disagrees 

that an aggregate cap is not needed in 

a corporate family structure that has 

both unregulated entities and regulated 

utilities. Regulated entities, even those 

with cost-of-service rates, do not 

necessarily have a revenue stream 

guaranteed to cover wholesale market 

costs, and thus should not be assumed 

to be without risk of default. 

C. Elimination of Unsecured Credit for 

Financial Transmission Rights Markets 

58. The proposal to eliminate the 

allocation of unsecured credit in FTR 

markets or their equivalent is based on 

the unique nature of FTRs.80 The value 

of the FTR can vary widely over very 

short periods of time. Further, owing to 

the relationship to the physical state of 

the electric grid, the state of which is 

known to all market participants, there 

are few if any participants who would 

be willing to ‘‘step into’’ the shoes of a 

party that is nearing default as a FTR 

position deteriorates financially. FTR 

markets entail obligations that are 

normally active over a long period of 

time, often a year or more, and their 

potential change in value over this time 

frame is quite large. 

59. The value of so-called ‘‘prevailing 

flow’’ FTRs 81 are generally predictable 

when there are no substantial changes 

in fuel prices or the physical state of the 

electric grid. However, outages on the 

transmission system and substantial 

changes in fuel prices can cause 


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Federal Register / Vol. 75, No. 207 / Wednesday, October 27, 2010 / Rules and Regulations 65949 

82 Division of Market Oversight, Federal Energy 

Regulatory Comm’n, 2009 State of the Markets 

Report at 20 (April 15, 2010), available at http:// 

www.ferc.gov/market-oversight/st-mkt-ovr/som-rpt2009.pdf. 83SPP March 29, 2010 Comments at 5–6; Basin 

Electric March 29, 2010 Comments at 4; OMS 

March 29, 2010 Comments at 3; Calpine March 29, 

2010 Comments at 7; Citigroup March 29, 2010 

Comments at 4; DC Energy March 29, 2010 

Comments at 9; Dominion March 29, 2010 

Comments at 7; Shell Energy March 29, 2010 

Comments at 6; Northeast ISOs March 29, 2010 

Comments at 7; NYTO March 29, 2010 Comments 

at 8; NEMA March 29, 2010 Comments at 6; and 

J.P. Morgan March 29, 2010 Comments at 10. 

84A fixed-price TCC is a series of TCCs, each with 

a duration of one year, renewed annually for a 

period of at least five years at a fixed price that is 

obtained through the conversion of expired or 

expiring Existing Transmission Agreements. NYISO 

OATT, Section 1.6 Definitions—F. These are legacy 

obligations that predate the ISO. 

85NYISO March 29, 2010 Comments at 12–13. 86CAISO March 29, 2010 Comments at 12–14. 

87CPUC March 29, 2010 Comments at 4. 

88 Joint Commenters include Constellation Energy 

Commodities Group, Inc., Constellation 

NewEnergy, Inc., and Integrys Energy Services, Inc. 

89 Joint Commenters March 29, 2010 Comments at 

12. 

90EEI March 29, 2010 Comments at 11. 

91Wisconsin Parties March 29, 2010 Comments at 

6–7. 

92MidAmerican March 29, 2010 Comments at 7. 

93SDG&E March 29, 2010 Comments at 3–4. 

94APPA March 29, 2010 Comments at 6. 

95First Energy March 29, 2010 Comments at 3. 

96 Id. at 5. 

97MidAmerican March 29, 2010 Comments at 

6–7; PSEG March 29, 2010 Comments at 12. 

98Midwest TDUs March 29, 2010 Comments at 

13–14; NRECA March 29, 2010 Comments at 13; 

NYAPP March 29, 2010 Comments at 12; NCPA 

March 29, 2010 Comments at 6–7, 9. 

unforeseen flow patterns and result in a 

rapid and dramatic drop in the value of 

an FTR position.82 For example, a large 

transformer or major transmission line 

can fail, thus changing flows of 

electricity and causing increased 

congestion in other areas. This will 

happen nearly instantaneously and the 

effect on the flows of electricity will 

remain in effect for whatever period of 

time it takes to repair or replace the 

equipment. In some cases, this could be 

months or longer. Thus the use of 

unsecured credit in a market with risk 

that is difficult to quantify can lead to 

unforeseen and substantial costs in the 

event of a default. 

60. In the NOPR, the Commission 

proposed to revise its regulations to 

require that each RTO and ISO include 

in the credit provisions of its tariff 

provisions that eliminate unsecured 

credit in financial transmission rights 

markets. 

1. Comments 

61. The response to the Commission’s 

proposal to eliminate the use of 

unsecured credit in FTR markets is 

mixed. Parties that support the proposal 

include SPP, Basin Electric, the 

Organization of Midwest ISO States 

(OMS), Calpine, Citigroup, DC Energy, 

Dominion, Shell Energy, the Northeast 

ISOs, the New York Transmission 

Owners (NYTO), National Energy 

Marketers Association (NEMA), and J.P. 

Morgan.83

62. NYISO states general support for 

the elimination of unsecured credit for 

its TCC84 market but argues that the 

Commission should clarify that those 

holding ‘‘fixed price’’ TCCs should be 

exempt.85 Similarly, CAISO states that it 

supports the elimination of unsecured 

credit for FTRs, but asserts that a variety 

of specific practices would meet this 

requirement.86 CAISO allows netting of 

collateral posted for their equivalent 

FTR market participation and the 

auction of these rights, which CAISO 

suggests eases capital burdens while 

mitigating risk. Additionally, CAISO 

does not distinguish between credit for 

their FTR equivalent market and all 

other markets. Consequently, collateral 

posted for all markets can effectively be 

used interchangeably. 

63. The CPUC advises against 

elimination of unsecured credit in FTRs 

because load serving entities (LSE) use 

FTRs for hedging congestion risk on 

behalf of consumers, and elimination of 

unsecured credit in FTRs could result in 

higher costs passed on to ratepayers.87

64. Joint Commenters,88 Wisconsin 

Public Service Corporation and Upper 

Peninsula Power Company (Wisconsin 

Parties), and the Edison Electric 

Institute (EEI) state that risks associated 

with FTRs are not addressed by simply 

requiring FTR market participants to be 

fully collateralized. The Joint 

Commenters suggest that the 

Commission should instead direct the 

ISOs and RTOs to work together to 

develop a set of ‘‘Best Practices’’ for 

valuing FTRs and, to the extent 

possible, standardize valuation 

methodologies across ISOs and RTOs.89

Similarly, EEI states that the 

Commission should require ISOs and 

RTOs to reassess their methodology for 

valuing FTRs and report back to the 

Commission in one year.90 The 

Wisconsin Parties do not take a position 

with regard to the issue but note that the 

real credit issue relates to calculating 

the FTRs’ future value and the resulting 

future liability exposure.91

65. Similarly, MidAmerican and 

PSEG state that the NOPR proposal to 

eliminate unsecured credit in FTR 

markets is misguided because it does 

not address valuation of FTRs. 

MidAmerican states that, if the 

Commission is intent on eliminating 

unsecured credit for FTRs, it should 

require each ISO/RTO to allow a market 

participant to offer the ISO/RTO a 

security interest in receivables from 

non-FTR market activities as an 

acceptable form of collateral for FTR 

market activity.92

66. SDG&E also states that eliminating 

unsecured credit in the FTR market will 

require even LSEs to post collateral 

which increases costs. SDG&E argues in 

favor of allowing such entities to be 

exempt from the prohibition on 

unsecured credit in FTRs and adds that 

CAISO should provide for a transparent 

mechanism to calculate collateral for 

FTR positions on a daily or weekly 

basis.93

67. Midwest ISO states that the 

Commission should avoid applying the 

same approach to all market 

participants, regardless of their business 

model. APPA also opposes any 

standardized Commission action in this 

regard, arguing that elimination of 

unsecured credit for LSEs holding FTRs 

could deal a fatal blow to the ability of 

public power systems to secure longterm FTRs. However, APPA favors FTR 

collateral requirements for RTO market 

participants that are not participating in 

FTR markets to hedge congestion 

associated with physical transmission 

service taken to serve their loads, but 

instead are doing so for speculative 

reasons.94

68. First Energy, EMCOS, IMEA, 

Midwest TDUs, NRECA, NYAPP, NCPA, 

Western, CPUC, MSCG, MidAmerican, 

PSEG, and SCE oppose the 

Commission’s proposal to eliminate 

unsecured credit in the FTR markets. 

First Energy Service Company (First 

Energy) argues that defaults that 

occurred in the PJM market in December 

2007 were not due to the use of 

unsecured credit, but rather the abuse of 

FTR markets.95 First Energy 

recommends that the Commission not 

eliminate unsecured credit, but instead 

use independent market monitors that 

are in place in each ISO/RTO, in 

addition to the enforcement capabilities 

granted to the Commission in the 

Energy Policy Act of 2005, to ensure 

that no market manipulation is taking 

place.96 MidAmerican and the PSEG 

state that the Commission’s proposal is 

misguided and should be abandoned 

because it fails to address the most 

important underlying issue with respect 

to FTRs, which is one of valuation.97 In 

addition, Midwest TDUs, NRECA, 

NYAPP, and NCPA state that the 

elimination of unsecured credit for 

FTRs could create unnecessary 

collateral obligations on LSEs.98

69. Some parties such as Northern 

Indiana Public Service Company 


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65950 Federal Register / Vol. 75, No. 207 / Wednesday, October 27, 2010 / Rules and Regulations 

99NIPSCO March 29, 2010 Comments at 6; Xcel 

March 29, 2010 Comments at 12. 

100For a financial transmission right, an 

unexpected outage can cause unforeseen congestion 

or movement in flows and the resulting charges or 

credits can swing very substantially either way. 

101PJM Interconnection, L.L.C., 127 FERC 

¶ 61,017 at P 36. 

102PJM Interconnection, L.L.C., 122 FERC 

¶ 61,279 at P 26 n.10 (2008) (citing defaults by 

Excel and Power Edge in PJM’s financial 

transmission rights market). 

103PJM Interconnection, L.L.C., 127 FERC 

¶ 61,017 at P 8, 36. 

104 In 2008, dramatic changes in fuel prices at 

mid-year led to FTR values that differed 

dramatically from realized day-ahead congestion 

values. Division of Market Oversight, Federal 

Energy Regulatory Comm’n, 2008 State of the 

Markets Report at 18 (2009), available at http:// 

www.ferc.gov/market-oversight/st-mkt-ovr/2008- 

som-final.pdf. In 2009, changes in demand similarly 

led to divergence of FTR values and day-ahead 

congestion values. Division of Market Oversight, 

Federal Energy Regulatory Comm’n, 2009 State of 

the Markets Report at 20 (April 15, 2010), available 

at http://www.ferc.gov/market-oversight/st-mkt-ovr/ 

som-rpt-2009.pdf. 

105PJM Interconnection, L.L.C., 131 FERC 

¶ 61,017 at P 31–34, order on reh’g, 132 FERC 

¶ 61,180 (2010). 

(NIPSCO), and Xcel Energy Services 

(Xcel) did not oppose elimination of 

unsecured credit for FTR markets per se. 

NIPSCO and Xcel suggested that a 

stakeholder process develop an 

unsecured credit policy appropriate to 

each ISO/RTO.99

2. Commission Determination 

70. The Commission adopts the NOPR 

proposal to eliminate unsecured credit 

for FTR positions. The Commission 

understands the value that FTR markets 

provide to market participants that need 

to hedge congestion risk. Nevertheless, 

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.100

Moreover, financial transmission rights 

are relatively illiquid, adding to the 

inherent risk in their valuation.101

71. For example, PJM suffered a 

significant default in December 2007 in 

its FTR market 102 and moved to 

eliminate the use of unsecured credit in 

that market due to its risk.103 That 

default illustrates the unique risk of 

FTRs. Given a change in market 

conditions, a set of FTR positions 

became highly unprofitable. Because 

FTR obligations cannot be terminated 

prior to the expiration of the contract, 

from one month to several years, losses 

can mount to the point that the FTR 

holder goes bankrupt. 

72. It is difficult to quantify, and 

therefore limit, the risks inherent in FTR 

markets, as evidence by the substantial 

difference between FTR auction values 

and realized day ahead congestion value 

experienced over the past few years.104

For instance, the outage of a transformer 

at a key node in a network system 

during a peak season can have 

enormous financial consequences. Such 

an outage may be prolonged because 

replacement parts are expensive and not 

standardized, and thus not likely to be 

readily available. Under such 

circumstances, FTRs that had been 

‘‘prevailing flow’’ or ‘‘in the money’’ may 

suddenly be counter-flow during an 

entire peak season or longer with costs 

that continue to widen depending on 

usage, flows, temperature and other 

factors. Because FTR market 

participants are all aware of large 

transmission events affecting FTR 

values, an FTR that is suddenly ‘‘out of 

the money’’ will be difficult to sell or 

liquidate. Thus the owner can be stuck 

with a financial position that continues 

to be a burden and that could force a 

large default. While elimination of 

unsecured credit may not necessarily 

have prevented previous defaults, 

requiring collateral to support all FTR 

transactions, rather than continued 

reliance on unsecured credit, will 

reduce the risk, and resulting costs, of 

defaults that are mutualized across all 

market participants. 

73. As for the assertion of the CPUC 

that the elimination of unsecured credit 

should be avoided as it will raise the 

costs of LSEs who use FTRs for hedging 

congestion risk, the Commission 

acknowledges this possibility. However, 

as discussed above, even LSEs using 

FTRs to hedge costs are not without 

risk. Further, just as there are costs 

associated with the reduction of 

unsecured credit in energy transactions, 

the overall savings to all parties can be 

significant. The Commission is 

persuaded that the benefits of the 

elimination of unsecured credit over the 

long term, through reducing risk and 

minimizing the effect of defaults that 

would be socialized among all market 

participants, will compensate all parties 

for the short-term costs of fully securing 

FTR transactions.105

74. As for those that argue against a 

uniform, nationwide prohibition on the 

use of unsecured credit in FTR markets, 

the Commission notes that there has 

been no evidence to suggest that the 

generation mix or transmission system 

of any particular ISO or RTO is 

inherently unique in its physical 

performance or equipment that would 

allow it to avoid the risks discussed 

above. In response to those that argue 

that the nature of the participants and 

their business model should exempt 

those participants from this aspect of 

the Final Rule, the Commission 

addresses this issue below. 

75. Thus, the Commission directs 

each ISO and RTO to submit a 

compliance filing that includes tariff 

revisions to eliminate the use of 

unsecured credit in its FTR, or FTRequivalent, markets. This compliance 

filing must be submitted by June 30, 

2011, and the tariff revisions will take 

effect October 1, 2011. 

76. The Commission acknowledges 

the parties that suggest that valuation of 

FTRs is important to protecting against 

the risk to participants associated with 

possible defaults. While the 

Commission agrees that ISOs and RTOs 

may face challenges in valuing FTRs, 

those comments are beyond the scope of 

this rulemaking proceeding. 

77. The Commission disagrees with 

commenters that assert that LSEs using 

FTRs to hedge for congestion should be 

exempt from the prohibition on the use 

of unsecured credit in the FTR market. 

Even an LSE with generation backing 

the FTR may encounter changes in the 

system that outstrip (perhaps 

substantially outstrip) the hedge, as in 

the transmission outage example used 

above. Similarly, municipal utilities that 

hold an FTR position can find that their 

position is ‘‘out of the money’’ due to an 

unforeseen, but large, transmission 

outage. The Commission also notes that 

low risk activities may be subject to 

lower security and collateral 

requirements for FTR positions. Thus, if 

LSEs, municipal utilities and other 

entities are engaged in ‘‘low-risk’’ 

transactions in the FTR markets, then 

this lower risk will be reflected in the 

credit analysis done by the market 

administrator in setting security and 

collateral requirements for their 

transactions in the FTR market, in 

contrast to higher requirements that may 

be established for those engaged in highrisk speculative transactions. 

78. The Commission also disagrees 

with the assertion of CAISO and MidAmerican that ‘‘netting’’ of credit 

requirements between FTR and nonFTR activity should be allowed. 

Intermingling credit for these distinctly 

different markets would defeat the 

purpose of the Commission’s attempt to 

reduce market-disrupting risk. Such a 

practice could lead to reduction in the 

daily market activity, for example, to 

engage in more speculative activity in 


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Federal Register / Vol. 75, No. 207 / Wednesday, October 27, 2010 / Rules and Regulations 65951 

106PJM March 29, 2010 Comments at 18–19. 

107 Id. at 10–11. 

108CFTC March 29, 2010 Comments at 2 n.7. 

109Midwest ISO has adopted an approach similar 

to this, discussed below. 

110 In the NOPR, the Commission cited the Mirant 

bankruptcy and resulting default in the CAISO 

market as support for its proposal that ISOs/RTOs 

clarify their ability to offset market obligations. 

NOPR, FERC Stats. & Regs. ¶ 32,651 at P 24 (2010). 

Mirant argued in bankruptcy that CAISO would not 

be able to show the mutuality required to establish 

a right of setoff under section 553 of the bankruptcy 

code. Memorandum by Wachtell, Lipton, Rosen & 

Katz to PJM regarding Setoffs and Credit Risk of 

PJM in Member Bankruptcies at 10–11 (Mar. 17, 

2008) (found on Sept. 7, 2010 at http:// 

www.pjm.com/∼/media/committees-groups/ 

committees/crmsc/20080423/20080423-wachtellnetting-memo.ashx). CAISO has since clarified that 

Mirant settled with CAISO, thus no court ever ruled 

on Mirant’s arguments. Joint Comments of CAISO 

and Midwest ISO, March 15, 2010 Comments at 2– 

3. 

111Shell Energy March 29, 2010 Comments at 8. 

112MidAmerican Energy March 29, 2010 

Comments at 7–8. 

113 Dominion March 29, 2010 Comments at 7–10. 

114NYISO March 29, 2010 Comments at 15. 

FTR markets. This would serve to have 

the effect of ‘‘loosening’’ credit in an area 

where the Commission desires to see 

less risk. 

79. Additionally, the Final Rule does 

not provide exemptions for holders of 

‘‘fixed price TCCs,’’ or other products, 

from the prohibition on the use of 

unsecured credit in this market as they 

may vary in value despite being called 

‘‘fixed price.’’ 

D. Ability To Offset Market Obligations 

80. In order to help market 

participants manage their capital as 

efficiently as possible, market 

participants who are buying and selling 

energy and other products to and from 

the organized wholesale electric markets 

seek to net those transactions against 

each other for the purpose of 

determining the collateral requirement, 

thereby reducing the amount of 

collateral that a market participant must 

hold with the ISO/RTO. In this way, the 

ISO/RTO can administer the market, 

while imposing fewer demands on the 

limited capital of its participants. 

81. However, if a market participant 

files for bankruptcy protection, it may 

assert that the ability of the ISO/RTO to 

offset accounts receivable against 

accounts payable is not valid and seek 

a claim to amounts owed to the market 

participant by the ISO/RTO. To ensure 

that ISOs/RTOs are not left owing the 

market participant without the ability to 

net amounts owed by the market 

participant, there must be an adequate 

legal basis to protect the ISOs/RTOs in 

the bankruptcy context. 

82. This concern provided the basis 

for the Commission’s proposal in the 

NOPR to clarify the ISO’s/RTO’s legal 

status to take title to transactions, 

thereby becoming the central 

counterparty for transactions in an effort 

to establish mutuality in the 

transactions as legal support for set-off 

in bankruptcy. 

1. Comments 

83. PJM supports the Commission’s 

approach. Besides providing certainty, 

PJM argues that credit clearing solutions 

could provide attractive opportunities to 

RTO market participants to optimize the 

credit value of off-setting the positions 

that these companies hold in different 

market or trading environments, 

including across several RTOs.106 In 

addition, PJM argues that the 

Commission’s approach is not without 

precedent. In support, it notes that 

Elexon, the company that serves the 

balancing and settlement function in the 

United Kingdom, created a whollyowned subsidiary to act as the 

counterparty to trading charge and 

reconciliation charge transactions to 

address the same type of mutuality 

concern. PJM also states that ISO–NE 

has effectively identified itself as 

counterparty to FTR transactions that 

are undertaken in its markets by 

defining itself as a forward contract 

merchant and/or swap participant 

within the meaning of the Bankruptcy 

Code.107

84. Similarly, CFTC staff believes that 

the proposal would materially reduce 

credit risk for ISOs and RTOs. CFTC 

staff also states that it is unusual to rely 

on credit arrangements that are not ironclad and that the legal theory 

underlying Mirant’s claims is wellknown and easily available to any 

similarly-situated debtor in the 

future.108

85. J.P. Morgan supports the 

Commission’s proposal because it will 

provide an ability to manage defaults, 

offset market obligations in instances of 

bankruptcy, and minimize the collateral 

requirements of market participants. J.P. 

Morgan agrees with the Commission 

that there is legitimate uncertainty as to 

whether the netting provisions will 

withstand a challenge in a bankruptcy 

proceeding because of the ambiguity 

related to the identity of the 

counterparty. In addition, J.P. Morgan 

notes that some ISOs and RTOs have 

tried to address the concern by requiring 

market participants to assign the ISO or 

RTO a perfected security interest in the 

receivables from the ISO or RTO.109 J.P. 

Morgan is concerned that this approach 

is a substantial administrative burden 

that, if not executed flawlessly, might 

not fully protect against the bankruptcy 

of a market participant. 

86. CCRO explains that it reviewed 

this issue through a designated 

subcommittee of member companies 

that conducted a comprehensive study 

on netting. It asserts that it is emerging 

‘‘best practice’’ in intra-ISO netting for 

an ISO to create or designate a central 

counterparty entity through which 

market participants may execute 

transactions. CCRO encourages the 

Commission to formulate policy and 

regulations which enable cost-effective 

implementation of this best practice. In 

addition, it encourages the Commission 

to support innovations in netting 

consistent with emerging best practice. 

87. Many commenters voice strong 

views in opposition to this proposal. 

CAISO and Midwest ISO note that the 

argument that transactions between a 

market participant and ISO/RTO are not 

mutual, and therefore cannot be set-off 

in bankruptcy, has only been raised 

once and that there may be reasons why 

the argument has not been raised 

again.110 They encourage consideration 

of less burdensome alternatives. 

88. Other commenters question 

whether, absent steps taken in this 

rulemaking, there will really be a 

problem in upholding netting in the 

bankruptcy context. For instance, Shell 

Energy urges the Commission to more 

clearly define the problem and that a 

speculative problem is not an adequate 

basis to change the fundamental nature 

and role of an RTO.111 NRECA also 

asserts that the bankruptcy set-off risk to 

RTOs is largely hypothetical. 

MidAmerican Energy concurs with the 

joint comments of CAISO and Midwest 

ISO and asserts that the Mirant 

bankruptcy proceeding only marginally 

supports the proposition that an ISO or 

RTO may not be able to offset market 

participant obligations due to lack of 

mutuality.112

89. Dominion argues that the set-off 

risk has not yet been demonstrated and 

asserts that the proposal is 

unreasonable.113 In addition, NYISO 

states that it has found no case law 

supporting the proposition that a 

creditor must be a central counter-party 

in a transaction to set-off payment 

obligations.114 EPSA does not take a 

position on the proposal and instead 

asks the Commission to more clearly 

define the problem that it is trying to 

solve. 

90. In contrast, NYISO argues that, 

because ISO and RTO tariffs specifically 

establish a contractual obligation of 

payment to the ISO or RTO, a 

bankruptcy court would likely allow an 

ISO or RTO to set-off the obligations of 

a market participant. Moreover, NYISO 


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65952 Federal Register / Vol. 75, No. 207 / Wednesday, October 27, 2010 / Rules and Regulations 

115 ‘‘In bankruptcy, both recoupment and setoff 

are sometimes invoked as exceptions to the rule 

that all unsecured creditors of a bankrupt stand on 

equal footing for satisfaction. Recoupment or setoff 

sometimes allows particular creditors preference 

over others. Setoff is allowed in only very narrow 

circumstances in bankruptcy. But a creditor 

properly invoking the recoupment doctrine can 

receive preferred treatment even though setoff 

would not be permitted. A stated justification for 

this is that when the creditor’s claim arises from the 

same transaction as the debtor’s claim, it is 

essentially a defense to the debtor’s claim against 

the creditor rather than a mutual obligation, and 

application of the limitations on setoff in 

bankruptcy would be inequitable.’’ Newbery Corp. 

v. Fireman’s Fund Ins. Co., 95 F.3d 1392, 1400 (9th 

Cir. 1996) (quoting In re B & L Oil Co., 782 F.2d 

155, 157 (10th Cir. 1986)). 

116NYISO March 29, 2010 Comments at 16–17. 

117Six Cities March 29, 2010 Comments at 6. 

118Citigroup March 29, 2010 Comments at 5. 

119OMS March 16, 2010 Comments at 4–5. 

120Testimony at Technical Conference on Credit 

Reforms in Organized Wholesale Electric Markets, 

Tr. 13:5–7 (May 11, 2010) (Mr. Vince Duane, 

General Counsel and Vice President, PJM). 

121 Id. at Tr. 15:25–16:1; 16:12–16 (Mr. Vince 

Duane, General Counsel and Vice President, PJM). 

122 Id. at Tr. 72:2–4; 72:15–16 (Mr. Harold S. 

Novikoff, Esquire, Wachtell, Lipton, Rosen & Katz). 

123 Id. at Tr. 18:1–20:2 (May 11, 2010) (Mr. 

Michael Holstein, Chief Financial Officer, Midwest 

ISO). 

124 Id. at Tr: 45:18–48:13. 

125 Id. at Tr: 87: 6–25 (Mr. Stephen J. Dutton; 

Barnes & Thornburg). 

believes that a bankruptcy court may, 

for policy reasons, defer to the 

Commission-approved tariff provisions 

of the ISO or RTO, or uphold ISO or 

RTO netting under the doctrine of 

recoupment,115 thereby circumventing a 

challenge for mutuality.116

91. Many commenters argue that it 

could increase costs, raise jurisdictional 

concerns, and create legal issues and tax 

implications. They recommend that the 

Commission consider alternative 

solutions, allowing ISOs and RTOs to 

work through their stakeholder 

processes, or requiring each ISO and 

RTO to report back to the Commission 

concerning their rights to net 

transactions and what rights they would 

assert in bankruptcy proceedings. 

92. Six Cities urges the Commission to 

not adopt the proposal because it could 

increase the complexity of the 

settlement process and potentially 

create additional costly obligations and 

liabilities for market operators that 

market participants would have to pay. 

Six Cities believes that other 

mechanisms, such as net invoicing as 

utilized by CAISO, can be used to 

protect market participants.117

93. Citigroup agrees that netting, and 

set-off in bankruptcy, is an important 

tool for managing risk, but states that 

the proposal presents many complex 

issues related to netting, offsets, defaults 

and bankruptcy that will be different for 

each ISO and RTO. Citigroup states that 

each ISO and RTO has its own unique 

tariff terms and markets, thus 

implementation would have to be 

tailored to each market.118 Therefore, 

Citigroup argues that each ISO and RTO 

should consider these issues through its 

stakeholder process. OMS is of two 

minds on this issue in that it supports 

the Commission’s desire to clarify the 

legal foundation for the ISO/RTO to net, 

but believes that it is important that the 

proposal does not expose the ISOs and 

RTOs to unforeseen ramifications, such 

as increased liability or the incurrence 

of additional obligations.119

2. Technical Conference 

94. The Commission held a technical 

conference to delve further into the 

issues raised by its proposal. The 

technical conference provided 

additional evidence on the ISOs and 

RTOs ability to net obligations and 

conduct setoff in the bankruptcy 

context. Mutuality was identified by 

several participants as important in 

allowing the ISOs and RTOs to perform 

this vital function, who asserted that 

mutuality was most easily achieved by 

the market administrator ‘‘taking title’’ or 

being the buyer to all sellers and seller 

to all buyers in all transactions in the 

market. Mr. Duane from PJM supported 

the Commission’s proposal by stating: 

‘‘* * * the obvious and direct way to 

establish mutuality is simply to be a 

contract party to the transactions that 

you’re setting up.’’ 120 Mr. Duane further 

stated: ‘‘I would regard the 

Commission’s initiatives here as 

overdue’’ and ‘‘the proposal here would 

remove a real disability that is a cloud 

over the enforcement of a broad set of 

rights that the RTOs have in outside 

forums, particularly beyond this 

Commission.’’ 121 According to Mr. 

Novikoff a ‘‘best practice’’ is ‘‘to create 

mutuality by using a central 

counterparty and have that counterparty 

deal with all of the participants.’’ 122

95. However, the Midwest ISO 

participant and the CAISO participant 

represented two different ways in which 

their organizations sought to deal with 

the issue, as opposed to the PJM 

proposal to change its tariff to allow an 

entity to explicitly take title and act as 

the central counterparty to achieve 

mutuality. 

96. At the technical conference, Mr. 

Holstein of Midwest ISO discussed the 

‘‘first short-pay, then uplift’’ system used 

by Midwest ISO, stating that it works 

well and is revenue neutral in all 

transactions. Mr. Holstein stated that, if 

a market participant doesn’t pay a 

charge that it owes, which is the net 

charge of the invoice, Midwest ISO 

short-pays the other market participants 

who are net-owed funds in that billing 

cycle, thus remaining revenue neutral 

for that billing cycle. Midwest ISO later 

makes up the difference by ‘‘uplifting’’ 

the default to all market participants, 

that is, charging extra in the next billing 

cycle and redistributing the proceeds to 

those who were initially short-paid.123

Further, any party in Midwest ISO who 

wishes to net their obligations across its 

various markets (e.g., real time, day 

ahead, reserves, etc.) must provide 

Midwest ISO a security interest in these 

transactions. By doing this, Midwest 

ISO asserts that it is able to safely set 

credit exposure to a net, rather than a 

gross, obligation. Midwest ISO stated 

that ten percent of its market 

participants grant Midwest ISO a 

security interest, but certain public 

power entities are not able to use that 

approach.124 During the technical 

conference, participants noted the 

difficulties raised by using the security 

interest approach given that many 

lending agreements prohibit granting 

liens and some entities, such as 

municipalities, cannot engage in such 

practices.125 For these reasons 

stakeholders in Midwest ISO decided 

against mandatory requirements of 

security interest and opted for voluntary 

use of security interest. 

97. Mr. Daniel Shonkwiler of CAISO 

did not perceive a potential inability to 

offset market participants’ claims and 

obligations as a risk, because CAISO’s 

ordinary monthly settlements involve 

net invoices. Under CAISO’s tariff, 

CAISO asserts that market participants 

only have the right to receive the net 

payment from CAISO for market sales, 

with no competing claims and 

obligations. CAISO indicates that a legal 

issue arises where a market participant 

fails to pay an invoice, but in a 

subsequent month, has a payment due 

back to it. In such a situation, CAISO 

states that its tariff allows it to recoup 

that later payment to pay the previous 

month’s default. CAISO does not see a 

material risk because it does not assume 

a right to set-off when it is calculating 

the amount of financial security 

required. CAISO further states that its 

market is not at risk because it ensures 

that its market participants are 

adequately secured; many market 

participants are exclusively buyers or 

sellers, and thus netting their invoices 

would not reduce their exposure; 

litigating the issue would be so 

expensive as not to be worthwhile for a 

market participant in bankruptcy; and 

bankruptcy is rare in the CAISO 


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126 Id. at Tr: 21:22–26:14 (Mr. Daniel J. 

Shonkwiler, Senior Counsel, CAISO). 

127 Id. at Tr: 89: 1–25–90: 1–19 (Mr. Harold 

Novikoff, Wachtell, Lipton, Rosen & Katz). 

128NYISO June 8, 2010 Comments at 11; CAISO 

June 8, 2010 Comments at 5; Dominion June 8, 2010 

Comments at 8; Midwest ISO June 8, 2010 

Comments at 3. 

129 Id. at Tr: 101:1–12 (Mr. Harold Novikoff, 

Wachtell, Lipton, Rosen & Katz). 

130Constellation June 8, 2010 Comments at 4. 

131CAISO July 23, 2010 Comments at 6. 

market.126 CAISO’s method of ‘‘net 

invoicing’’ characterizes a market 

participant’s monthly bill as one 

transaction with multiple line items. 

One bankruptcy expert testified that 

such a ‘‘tariff’’ approach to the problem 

is weaker than the establishment of 

mutuality and even weaker than the use 

of ‘‘collateral’’ or security interest to 

allow netting, and that a hostile 

creditors committee would be unlikely 

to agree to claims made on the basis of 

a tariff, rather than established 

mutuality.127

98. The Commission also invited 

parties to submit further comment in 

response to the issues discussed in the 

technical conference. 

3. Comments Submitted After the 

Technical Conference 

99. Several commenters assert that it 

is unlikely that a bankruptcy court 

would refuse an ISO/RTO’s netting a 

market participant’s obligations and 

therefore the Commission’s concern 

does not justify the Commission’s 

central counterparty proposal.128

Dominion states that CAISO has 

identified a number of practical reasons 

why the risk is minimal, such as that 

many market participants are unlikely 

to be in a position to use setoff because 

they are not both a buyer and seller in 

a given market. Dominion and SPP state 

that most market participants that want 

to continue to operate post-bankruptcy 

require transmission service and 

therefore will work with the ISO/RTO 

during bankruptcy proceedings. 

According to Midwest ISO, only an 

estimated 20 percent of its market 

participants are not dependent on 

transmission service, and thus do not 

net any transactions, and potentially 

would challenge the ISO’s/RTO’s ability 

to off-set. NYISO believes that its credit 

exposure is limited because most market 

participants in New York are not both 

buyers and sellers of energy in NYISOadministered markets. 

100. CCRO acknowledges that a 

market participant going into 

bankruptcy and challenging the ISO’s/ 

RTO’s ability to net transactions is a low 

probability event, but it argues that the 

Commission cannot ignore such 

potentially high risk events. However, 

CAISO believes that the Commission 

needs additional evidence regarding the 

scope of the risk. CAISO suggests that 

the Commission first determine the 

number of market participants that 

likely would challenge set-off and then 

gather historical data about the 

difference between their net position 

and gross credits. NYISO also questions 

the scope of the risk, and asserts that it 

would have sufficient collateral 

available to recover the market 

participant’s payment obligations to the 

NYISO because it calculates distinct 

credit requirements for each of its 

markets without assuming that it will be 

able to net across markets in a 

bankruptcy proceeding. NYISO also 

asserts that its tariff allows it to draw 

from its pre-funded working capital 

fund to facilitate timely payment to 

market participants and maintain the 

liquidity of the NYISO-administered 

markets. 

101. Many commenters argue that the 

central counterparty approach does not 

definitively eliminate the risk that a 

bankruptcy court would refuse an ISO/ 

RTO’s netting obligations between the 

ISO/RTO and the debtor market 

participant. For instance, Eastern 

Massachusetts, Dominion and NYISO 

believe that a bankruptcy court that is 

hostile to set-off would question 

whether the ISO/RTO is the central 

counterparty in form only and not 

substance. NYISO explains that taking 

title is just one factor that a bankruptcy 

court may consider in determining 

whether there is mutuality between the 

ISO/RTO and the market participant. 

NYISO points out that under PJM’s 

proposal, PJM is only obligated to pay 

market sellers to the extent of its 

collections from market buyers. Thus, 

NYISO argues that PJM may not truly be 

taking on the debt obligation for market 

purchases, but rather be acting as an 

agent for many different buyers. 

Although NYISO acknowledges that this 

argument is unlikely to succeed, it 

demonstrates that the risk is not 

eliminated. In addition, Dominion 

points to Midwest ISO’s argument that 

the central counterparty model does not 

defend against a challenge based on the 

absence of mutuality in netting across 

commodities and services. However, 

bankruptcy counsel noted that there 

would have to be a major change in case 

law for a challenge to an identified 

central counterparty to be successfully 

upheld regarding its ability to set-off in 

a bankruptcy.129

102. Numerous commenters oppose 

the central counterparty proposal 

because they believe that it will require 

the ISOs/RTOs to expend significant 

resources to implement it and may have 

negative consequences for the ISOs/ 

RTOs and their market participants. 

According to Dominion, EPSA, Shell 

Energy, and SPP, the proposal is not a 

clarification in status, but instead is a 

radical departure from the current 

business model used for ISO/RTO 

transactions. Shell Energy believes that, 

as a result of the clarification, existing 

ISOs/RTOs will be administrators only 

and the new central counterparty will 

be a new public utility that should be 

treated similar to other public utilities. 

Thus, Shell Energy argues that 

implementing central counterparty 

status will require a radical 

restructuring of ISOs/RTOs. 

103. As for potential consequences 

and impacts on the ISOs/RTOs, 

Constellation cites Midwest ISO’s Chief 

Financial Officer’s comment that if an 

ISO/RTO is the central counterparty to 

energy market transactions, then its 

revenue neutrality may be jeopardized 

and liquidity and insolvency risk is 

introduced to the market.130 Similarly, 

EPSA states that Midwest ISO believes 

that it would be obligated to pay for 

defaults in the event other parties to the 

transaction could not pay, and that an 

event like this potentially could 

bankrupt the ISO/RTO. Eastern 

Massachusetts highlights CAISO’s 

comments regarding the potential for 

increased cost of credit used to fund 

market operations. 

104. CAISO also states that, by 

becoming a central counterparty to 

transactions within its market, it could 

become a ‘‘point of regulation’’ under 

greenhouse gas regulatory schemes. 

CAISO states that the Air Resources 

Board of California is regulating 

greenhouse gas emissions which extend 

to electricity produced and/or 

consumed within California. CAISO is 

concerned that if it is required to take 

title to the transactions, it will be 

subject to greenhouse gas regulations 

with no ability to procure alternative, 

non-carbon intensive fuels in the power 

pool. In fact, CAISO states that such a 

construct could provide an incentive for 

electricity exporters into California to 

dump the energy onto CAISO’s system 

prior to entering California, so the 

exporters would not be subject to the 

greenhouse gas regulations. CAISO 

further states that national clearing 

could take place without ISOs and RTOs 

becoming the counterparty to 

transactions within their markets.131

105. Dominion, NYISO, Shell Energy 

and SPP argue that the central 

counterparty model potentially exposes 

ISOs/RTOs to new requirements, risks 


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65954 Federal Register / Vol. 75, No. 207 / Wednesday, October 27, 2010 / Rules and Regulations 

132CAISO June 8, 2010 Comments at 6–7. 133Policy Statement, 109 FERC ¶ 61,186 at P 29. 

and costs associated with complying 

with generally acceptable accounting 

principles requirements, loss of legal 

status, indemnification, and tax 

liability. They also believe that there 

may be unintended consequences that 

could cause significant harm, such as 

the imposition of state and local sales 

taxes on ISOs/RTOs, implications 

regarding the independence of an ISO/ 

RTO, regulatory uncertainty resulting 

from potential multi-agency 

jurisdictional oversight of ISOs/RTOs, 

negative impacts on financing options, 

and increases in financing costs. In light 

of these uncertainties, Constellation 

argues that the Commission should 

develop a full record, particularly 

regarding the consequences for ISOs/ 

RTOs. 

106. PG&E also believes that CAISO 

already is considering and 

implementing numerous changes and 

improvements to its tariffs and markets 

and therefore does not have sufficient 

time to undertake additional effort. 

107. Eastern Massachusetts argues 

that the central counterparty proposal 

could result in interference with the 

ability of eligible municipal market 

participants to continue existing tax 

exempt financing or to use such 

financing to expand productive assets. 

Although NEPOOL does not take a 

formal position in its comments, it also 

believes that the central counterparty 

proposal could have profound and 

unintended consequences on market 

participants. SPP is concerned that, if 

the ISOs/RTOs operate as 

clearinghouses, then market participants 

such as cooperatives or municipalities 

will be unable to meet credit 

requirements. 

108. CCRO generally supports the 

Commission’s proposal and believes 

that any approved procedure should be 

standardized across the ISOs/RTOs to 

the extent practical. CCRO also 

encourages the Commission to adopt 

rules that do not deter the development 

of innovations that can further limit 

credit exposure, such as the advent of 

netting of transactions across all the 

ISOs/RTOs and the over-the-counter 

markets. 

109. Some commenters argue that 

there are less costly approaches that 

ISOs/RTOs can employ to address the 

Commission’s concerns without 

adopting the central counterparty 

proposal.132

110. Eastern Massachusetts argues 

that other changes in credit policies 

proposed under the NOPR may reduce 

the magnitude of any potential exposure 

without any need to adopt a central 

counterparty provision. Dominion and 

Midwest ISO believe the risk has been 

significantly mitigated by other risk 

management tools that ISOs/RTOs 

already have implemented, including 

shorter settlement periods. Dominion 

urges the Commission to fine tune these 

tools before making any radical changes 

to the ISO/RTO structure. Along those 

lines, Shell Energy argues that the better 

solution is to rely on a combination of 

a cap on unsecured credit and a sevenday billing cycle. 

111. Other comments identify 

different approaches to addressing the 

Commission’s concerns. EPSA believes 

that, in addition to the central 

counterparty proposal, there are two 

other possible solutions, including 

creating a collateral arrangement that 

will reach the same economic result and 

rewriting tariffs so that they establish a 

net obligation, rather than a gross 

obligation. EPSA argues that the 

Commission either should conduct a 

more thorough exploration of these 

three options or allow each ISO/RTO to 

work with its stakeholders to create a 

regionally tailored solution. 

112. CAISO, NYISO, and SPP also 

point to Midwest ISO’s voluntary 

security interest approach as an 

alternative to the central counterparty 

approach. Although CAISO believes that 

Midwest ISO’s approach is less costly 

and simpler to implement, it also 

believes it would require a long lead 

time to facilitate discussions between 

market participants and their lenders. 

SPP notes concerns with the security 

interest approach, because it may be 

difficult for most market participants to 

supply such a security interest due to 

existing financing arrangements and the 

burden of perfecting a security interest. 

113. Dominion argues that it may not 

be necessary to amend ISO/RTO tariffs 

because there are existing defenses of 

netting under the current ISO/RTO 

structure that moot the need for the 

NOPR proposal. For instance, SPP notes 

that a bankruptcy court may be hesitant 

to set aside a Commission-approved 

tariff that requires payment netting or 

set-off. Dominion points to Midwest 

ISO’s and NYISO’s comments that the 

tariff, which market participants agree 

to be bound by, satisfies the mutuality 

of party requirement. 

114. NYISO also argues that its 

existing tariff may provide sufficient 

protection in the event a market 

participant raises the mutuality 

argument. According to NYISO and 

SPP, the commercial relationship 

between ISOs/RTOs and their market 

participants is distinguishable from the 

typical scenarios in which parties have 

successfully challenged setoff rights in a 

bankruptcy proceeding. According to 

NYISO, the important distinction is that 

the net obligations are between NYISO 

and a specific debtor market participant 

directly and NYISO is acting in the 

same capacity on both sides of market 

transactions. 

115. As an alternative to seeking setoff 

in bankruptcy, CAISO, NYISO and SPP 

believe that a bankruptcy court likely 

would allow it to net obligations under 

the equitable defense of recoupment. 

According to NYISO, a bankruptcy court 

would likely uphold the NYISO’s right 

to recoupment within each market 

because it would be inequitable for a 

market participant to benefit from its 

participation in a single market without 

also having to meet its obligations 

related to its transactions in that market. 

4. Commission Determination 

116. Organized wholesale electric 

markets typically arrange for settlement 

and netting of transactions entered into 

between market participants and the 

market administrator, but do not take 

title to the underlying contract position 

of a participant at the time of settlement. 

The Commission is concerned that, if a 

market participant files for bankruptcy 

protection, it may argue against settingoff amounts owed against amounts to be 

paid to an ISO or RTO, which could 

lead to a larger default in the market 

that must be socialized among all other 

participants. The Commission supports 

netting, which allows ISOs and RTOs to 

collect less collateral from market 

participants,133 but netting must be 

established in a way that helps ensure 

that market participants are protected 

from a substantial default should a 

participant file for bankruptcy 

protection. 

117. While the Commission, in 

response to what it still considers to be 

a legitimate concern, originally 

proposed requiring ISOs and RTOs to 

establish themselves as the central 

counterparty to transactions with 

market participants, the Commission is 

open to considering other solutions to 

this concern. The Commission directs 

each ISO and RTO to submit a 

compliance filing that includes tariff 

revisions to include one of the following 

options: 

• Establish a central counterparty as 

discussed above. 

• Require market participants to 

provide a security interest in their 

transactions in order to establish 

collateral requirements based on net 

exposure. 


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Federal Register / Vol. 75, No. 207 / Wednesday, October 27, 2010 / Rules and Regulations 65955 

134Testimony at Technical Conference on Credit 

Reforms in Organized Wholesale Electric Markets, 

Tr: 65: 23–25 (May 11, 2010) (Mr. Harold Novikoff, 

Wachtell, Lipton, Rosen & Katz). 

135Chevron Products Co. v. SemCrude, L.P., 428 

B.R. 590, at 594 (D. Del. 2010) (quoting In re 

SemCrude, L.P., 399 B.R. 388, 397–398 (Bankr. D. 

Del. 2009)). The court goes on to note that a 

‘‘contract exception’’ does not exist under section 

553, 11 U.S.C. 553, which governs set-off under the 

bankruptcy code. Id. 

136 Id. at Tr. 84:5–25, 85:1–22 (Iskender H. Catto; 

Kirkland & Ellis on behalf of the Committee of Chief 

Risk Officers). 

137 Id. at Tr: 73:16–21 (May 11, 2010) (Mr. Harold 

Novikoff, Wachtell, Lipton, Rosen & Katz). 

138As to the effect on costs of establishing a 

counterparty in each ISO or RTO, experience with 

PJM to date suggests costs will not increase. See, 

e,g., PJM Interconnection, L.L.C., 132 FERC 

¶ 61,207, at P 47 (2010) (noting that, in establishing 

PJM Settlement as a counterparty, PJM is not 

changing its administrative charges and ‘‘that the 

costs that PJM Settlement will incur are costs that 

PJM already incurs today.’’) 

• Propose another alternative, which 

provides the same degree of protection 

as the two above-mentioned methods. 

• Choose none of the three above 

alternatives, and instead establish credit 

requirements for market participants 

based on their gross obligations. 

118. This compliance filing must be 

submitted by June 30, 2011, with the 

tariff revisions to take effect October 1, 

2011. 

119. Evidence put before the 

Commission has demonstrated the need 

for establishing better protection against 

loss due to bankruptcy of a market 

participant. Allowing netting without 

adequate protection could pose a risk to 

the ISO and RTO markets and 

particularly their participants who 

would be assessed any shortfall. The 

ability for an ISO or RTO to net amounts 

owed to and owed by a market 

participant that has filed for bankruptcy 

protection is not clear. At the technical 

conference, Mr. Novikoff testified that 

‘‘bankruptcy courts are quite hostile to 

setoff.’’ 134 The Commission also notes 

that a recent court decision affirmed a 

bankruptcy court’s finding that, ‘‘the 

mutuality required by Section 553, 

‘cannot be supplied by a multi-party 

agreement contemplating a triangular 

setoff.’ ’’ 135 Our effort to limit the 

amount of unsecured credit extended in 

ISO and RTO is less meaningful if an 

ISO or RTO establishes a collateral 

requirement based on net exposure that 

can not withstand a challenge in 

bankruptcy court. As to the view that 

there is a low probability that a market 

participant will file for bankruptcy and 

then challenge an ISO’s/RTO’s ability to 

net, the Commission agrees with CFTC 

staff and the CCRO that that this low 

probability is balanced by a high cost to 

market participants and the stability of 

the market if it does occur. 

120. While we continue to believe 

that the NOPR proposal provides a 

sound approach to this issue, we are 

open to considering other solutions. 

Two alternatives to the central 

counterparty solution were presented; 

one proposed by the CAISO and one 

proposed by Midwest ISO, described in 

more detail in the comment section 

above. The Commission is convinced 

that Midwest ISO’s approach, in which 

market participants grant a security 

interest in their transactions to Midwest 

ISO, provides a basis for the ISO or RTO 

to net market obligations. A security 

interest is a form of collateral which 

provides certain protection in the 

bankruptcy context, but it may be 

unworkable under some lender 

agreements.136 The Commission notes 

that not all parties may be able to grant 

a security interest in their transactions, 

however, this method provides an 

alternative for ISOs and RTOs that wish 

to allow market participants to continue 

to net their transactions. However, the 

Commission is concerned that CAISO’s 

method of ‘‘net invoicing,’’ which treats 

all events on a market participant’s 

monthly invoice as one transaction, may 

not be adequate in the context of a 

bankruptcy.137 Because of the 

uncertainties about the viability of 

CAISO’s theory under bankruptcy law, 

the Commission does not believe that 

market participants should be allowed 

to net their financial obligations based 

on CAISO’s ‘‘net invoicing’’ solution. 

121. Some participants have 

suggested that the Commission direct 

that all ISO/RTO tariffs have explicit 

language allowing these markets to 

perform netting and set-off to provide 

legal cover in bankruptcy. While RTOs 

and ISOs may propose such tariff 

language as an additional measure, the 

Commission believes that it is not 

sufficient protection to simply direct the 

ISOs and RTOs to include the ability to 

net in their tariff. Based on testimony 

cited above, the Commission is 

concerned that, if the issue were raised 

in bankruptcy court, the existence of a 

Commission-approved tariff, even with 

such language, may not persuade a 

bankruptcy court to allow the set-off of 

financial obligations between an ISO/ 

RTO and a market participant who is in 

bankruptcy. For this reason, the 

Commission will require more than 

mere tariff language to ensure the right 

of an ISO/RTO to net in the bankruptcy 

context. In the absence of a central 

counterparty, security interest, or 

another method that provides the same 

degree of protection to support netting, 

the remaining solution is to establish 

credit requirements to gross market 

obligations rather than net obligations. 

122. Many parties also state that the 

Commission should not pursue the 

counterparty model due to tax and 

administrative costs. Given that ISOs 

and RTOs already function in ways 

similar to a central counterparty, it is 

not clear how it will lead to increased 

administrative costs.138 As to possible 

tax implications, no specific evidence 

has been presented showing that the 

central counterparty model will lead to 

increased tax obligations. However, we 

need not decide these points here, and 

RTOs and ISOs may consider these 

points in deciding how to comply with 

this Final Rule. 

E. Minimum Criteria for Market 

Participation 

123. The Commission has always 

been wary of unnecessary barriers to 

entry to market participants, with a goal 

of ensuring sufficient participation, 

adequate liquidity, and competitive 

results. However, this consideration 

must be balanced with protecting the 

market from risks posed by undercapitalized participants without 

adequate risk management procedures 

in place. Having minimum criteria in 

place can help minimize the dangers of 

mutualized defaults posed by 

inadequately prepared or undercapitalized participants. 

124. Consequently, the Commission 

proposed that each ISO and RTO have 

tariff language to specify minimum 

participant criteria for all market 

participants. The Commission sought 

comment on the type of process used to 

arrive at the criteria and 

recommendations on what the criteria 

should be. 

1. Comments 

125. The proposal to require 

minimum participation criteria has 

widespread support. Parties such as 

Citigroup Energy, Dynegy, NEMA, 

NEPOOL, and PG&E favor the proposal. 

The OMS suggests requiring market 

participants in FTR markets to have a 

minimum net worth. CFTC staff 

suggests something similar; participants 

in FTR markets should have a minimum 

capitalization. CFTC staff also states that 

the Commission should establish a 

system to evaluate the risk management 

capabilities of each prospective 

participant at the time of admission and 

of each participant on a periodic basis 

after admission. 

126. DC Energy suggests that the 

CFTC and Securities and Exchange 

Commission (SEC) requirements for 

participation in their markets could be 

a basis for determining minimum 


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65956 Federal Register / Vol. 75, No. 207 / Wednesday, October 27, 2010 / Rules and Regulations 

139 J.P. Morgan Comments at 14 (referring to the 

Commodity Exchange Act definition of Eligible 

Contract Participant. 7 U.S.C. 1a(12)). Examples of 

criteria-determined Eligible Contract Participants 

include financial institutions, insurance companies, 

mutual funds, and corporations with assets in 

excess of $10 million. 

140Midwest TDUs, NYTOs, Consumers Energy, 

Wisconsin Parties and Financial Marketers. 

141Financial Marketers March 29, 2010 

Comments at 2–3. 

142As noted above, Lehman Brothers was rated as 

‘‘investment grade’’ by all ratings agencies on 

Friday, September 12, 2008, only to file for 

bankruptcy on Monday, September 15, 2008. 

requirements. J.P. Morgan, likewise, 

recommended that every market 

participant in the ISO/RTO markets 

meet the requirements of an ‘‘Eligible 

Contract Participant’’ as defined in the 

Commodity Exchange Act.139

127. APPA supports development of 

ISO/RTO rules that limit the activities of 

‘‘financial-only’’ market participants, 

including maximum position and credit 

limits for financial-only ISO/RTO 

market participants and suggests a 

follow-on NOPR dealing specifically 

with these issues. NRECA suggests that 

ISOs/RTOs should be encouraged to 

develop minimum participation criteria 

for cooperative utilities that would be 

different than investor-owned utilities. 

128. Morgan Stanley agrees that 

certain risk management capabilities 

and minimum capital requirements be 

established but cautioned against 

making these criteria too onerous. 

Moreover, Morgan Stanley stated that 

criteria applied only to financial-only 

participants should be avoided. A 

similar argument was made by the 

Western Power Trading Forum (WPTF), 

which states that objective criteria 

should apply to all market participants. 

WPTF further states that, if the 

Commission seeks to ‘‘enhance certainty 

and stability in the markets,’’ then it 

should require each ISO/RTO to apply 

their credit policies to all market 

participants. 

129. Many parties, such as Detroit 

Edison, Direct Energy, PSEG and SCE, 

recommend that the stakeholder process 

should determine appropriate criteria in 

each ISO and RTO. On the other hand, 

Dominion asserts that the proper forum 

for establishing such criteria is the 

current rulemaking proceeding, and not 

the ‘‘popular vote’’ of market 

participants with competing interests in 

the stakeholder process. 

130. Other parties did not agree on the 

need for minimum criteria.140 Midwest 

TDUs suggest the Commission is not 

well positioned to design such criteria. 

The NYTOs argue the need for such 

criteria has not been established. 

Consumers Energy states that, as long as 

each RTO accurately determines 

creditworthiness, there is no need to 

further specify minimum criteria for 

participation. Financial Marketers argue 

that erecting barriers to market entry 

through the establishment of market 

participation criteria, such as minimum 

net worth or minimum size 

requirements, would be anticompetitive, 

unjust, and unreasonable.141

2. Commission Determination 

131. The Commission is persuaded 

that each ISO and RTO should include 

in its tariff language to specify 

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. This will help protect the 

markets from risks posed by undercapitalized participants or those who do 

not have adequate risk management 

procedures in place. Minimum criteria 

for market participation 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. 

132. However, the Commission will 

not specify criteria at this time, and 

instead directs that each ISO and RTO 

develop these criteria through their 

stakeholder processes. Consequently, 

the Commission directs each ISO and 

RTO to submit a compliance filing that 

includes tariff revisions to establish 

minimum criteria for market 

participation. Each ISO and RTO will 

need to consider the minimum criteria 

that are most applicable to its markets, 

this compliance filing must be 

submitted by June 30, 2011 and to take 

effect by October 1, 2011. 

133. In taking this approach, the 

Commission is aware that stakeholder 

groups with competing interests may 

disagree on these criteria, and so the 

Commission will review proposed tariff 

language to ensure that it is just and 

reasonable and not unduly 

discriminatory. The Commission 

believes that such standards might 

address adequate capitalization, the 

ability to respond to ISO/RTO direction 

and expertise in risk management. The 

Commission directs that these criteria 

apply to all market participants rather 

than only certain participants. 

134. The Commission does not agree 

with the argument that minimum 

criteria are not necessary if ISOs and 

RTOs apply vigorous standards in 

determining the creditworthiness of 

each market participant. While 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 ISO/RTO market. 

Moreover, the ISOs’ and RTOs’ ability to 

accurately assess a market participant’s 

creditworthiness is not infallible, and 

this additional safeguard should not be 

unduly burdensome compared to the 

need to protect the stability of the 

organized markets. 

F. Use of ‘‘Material Adverse Change’’ 

135. Events in credit markets can 

change the fortunes of a participant very 

quickly.142 Consequently, risk 

management is not a static endeavor. 

Every market administrator needs to 

perform frequent risk analysis on its 

participants to ensure that existing 

collateral and creditworthiness 

standards are sufficient. Nevertheless, 

even with such scrutiny, events may 

transpire that require the market 

administrator to invoke a ‘‘material 

adverse change’’ clause to justify 

changing the risk assessment of a 

participant and requiring additional 

collateral. 

136. The Commission is concerned 

that ambiguity as to when an ISO or 

RTO may invoke a ‘‘material adverse 

change’’ clause could itself have 

damaging effects on a market 

administrator’s ability to manage risk on 

behalf of all the participants. If a market 

administrator is concerned about when 

it may invoke a ‘‘material adverse 

change’’ clause, it could delay requests 

for collateral or orders for the cessation 

of a participant’s right to transact, which 

could further endanger the other 

participants and, in extreme cases, the 

market function itself. 

137. In addition, material adverse 

change clauses need to be sufficiently 

forward-looking to allow market 

administrators to request additional 

collateral before a crisis starts. The 

Commission is concerned that any 

attempt to acquire additional collateral 

during or after a crisis has begun would 

either fail or destabilize the party asked 

to provide additional credit. 

Specifically, news that a market 

participant was unable to secure 

additional collateral could negatively 

affect the perception of the market 

participant’s viability and potentially 

undermine confidence in an organized 

market’s viability. 

138. The Commission therefore 

proposed in the NOPR to require ISOs 


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Federal Register / Vol. 75, No. 207 / Wednesday, October 27, 2010 / Rules and Regulations 65957 

143 IRC March 29, 2010 Comments at 9. 

144CAISO’s current ‘‘material adverse change’’ 

clause is as follows: 

CAISO may review the Unsecured Credit Limit 

for any Market Participant whenever the CAISO 

becomes aware of information that could indicate 

a Material Change in Financial Condition. In the 

event the CAISO determines that the Unsecured 

Credit Limit of a Market Participant must be 

reduced as a result of a subsequent review, the 

CAISO shall notify the Market Participant of the 

reduction, and shall, upon request, also provide the 

Market Participant with a written explanation of 

why the reduction was made. 

Material negative information in these areas may 

result in a reduction of up to one hundred percent 

(100%) in the Unsecured Credit Limit that would 

otherwise be granted based on the six-step process 

described in Section 12.1.1.1 of the ISO Tariff. A 

Market Participant, upon request, will be provided 

a written analysis as to how the provisions in 

Section 12.1.1.1 and this section were applied in 

setting its Unsecured Credit Limit. 

‘‘Material Change in Financial Condition,’’ CAISO 

Tariff Appendix A at Original Sheet No. 894. 145APPA March 29, 2010 Comments at 35. 

and RTOs to include in their tariffs 

language to more clearly specify 

circumstances when the market 

administrator may invoke a ‘‘material 

adverse change’’ clause. 

1. Comments 

139. CAISO, Midwest ISO, NYISO, 

SPP, California Department of Water 

Resources State Water Project (SWP), 

Midwest TDUs, NRECA, Detroit Edison, 

EPSA, Mirant, NIPSCO, Powerex, Xcel, 

and IRC state that the Commission 

should preserve the authority for each 

ISO/RTO to maintain flexibility as to 

when to request a collateral call for 

unforeseen events. IRC presents an 

example of language of such a material 

adverse change provision: 

A ‘‘Material Change’’ in financial status 

may include, but is not limited to, the 

following: 

(i) A downgrade from any rating by any 

rating agency; 

(ii) Being placed on credit watch with 

negative implication by any rating agency; 

(iii) A bankruptcy filing or other 

insolvency; 

(iv) A report of a significant quarterly loss 

or decline of earnings; 

(v) The resignation of key officer(s); or 

(vi) The filing of a material lawsuit that 

could materially adversely impact current of 

future financial results.143

140. Hess states that the material 

adverse change clauses in the ISO/RTO 

tariffs must include non-exclusive 

illustrative lists of potential material 

change events, and require ISO/RTO 

credit officers to exercise caution prior 

to invoking the ‘‘material adverse 

change’’ clause. 

141. CFTC staff notes that it is critical 

for a market administrator to have the 

ability to call for additional collateral in 

unusual or unforeseen circumstances. 

Therefore, CFTC staff recommends 

either: (1) Removing any requirement 

for a market administrator to wait until 

a participant experiences a ‘‘material 

adverse change’’ in credit status before 

calling for additional collateral to 

support FTR positions; or (2) permit a 

market administrator to define ‘‘material 

adverse change’’ in a manner that would 

allow a market administrator to have 

broad discretion in calling for additional 

collateral to support FTR positions. 

142. CPUC, Dynegy, and SCE state 

that they support clear guidelines on the 

definition of ‘‘material adverse change.’’ 

CPUC and SCE argue that CAISO’s 

current tariff provision specifying under 

what circumstances a market 

administrator may invoke a ‘‘material 

adverse change’’ clause to require 

additional collateral is adequate.144

Therefore, CPUC requests that the 

Commission adopt guidelines that 

would allow the CAISO to maintain the 

status quo. Shell Energy also states that 

the Commission should propose a 

generic material adverse change 

provision, then allow the ISOs and 

RTOs to work with stakeholders to 

produce an illustrative list of instances 

where material adverse change 

provisions would or should be triggered 

and to file that language with the 

Commission. However, even then, the 

tariff language should still allow a 

market administrator to act in the event 

that special circumstances arise. 

143. EEI states that the ISO/RTO 

should be able to explain its procedures 

and provide the types of circumstances 

under which it would invoke the 

‘‘material adverse change’’ clause that 

requires a market participant to post 

collateral within two days. EEI also 

states that the procedures that the ISO/ 

RTO employs should, at a minimum, 

provide written notice of the reasons for 

its action within thirty days and an 

opportunity to appeal to the Chief 

Executive Officer of the ISO/RTO. 

Additionally, EEI states that the 

Commission should require the ISOs/ 

RTOs to incorporate in their tariffs 

examples of the conditions under which 

they will invoke a ‘‘material adverse 

change’’ clause with the explicit 

requirement that the ISO/RTO put the 

rationale for its determination in writing 

and allow the market participant an 

opportunity for an appeal. 

144. MidAmerican states that it is not 

practical nor prudent to require a 

comprehensive and all-inclusive list of 

circumstances in which an ISO/RTO 

may invoke a material adverse change, 

but the required justification provided 

by an ISO/RTO for invoking a material 

adverse change provision should 

include reasonable, objective evidence 

of the occurrence of an identifiable 

event or condition with respect to the 

affected market participant. 

MidAmerican also states that the 

Commission should require each ISO/ 

RTO to specify a reasonable process for 

resolving any disagreement between the 

ISO/RTO and market participants with 

respect to the impact of any identified 

event or condition on the ability of the 

market participant to continue as a 

going concern or otherwise honor its 

obligations to the ISO/RTO. 

145. APPA proposes a committee on 

‘‘material adverse changes,’’ that is, a 

balanced advisory group of RTO 

employees dealing with credit issues 

and their counterparts from 

representatives of various types of RTO 

market participants. This group would 

be responsible for developing ‘‘model’’ 

protocols, to be the subject of a 

subsequent NOPR, which would guide 

an RTO in invoking the material adverse 

change provisions of the credit 

provisions of its tariff and business 

practices.145

146. Because ‘‘material adverse 

change’’ is ambiguous and could be 

inconsistently and inappropriately 

applied, PG&E recommends that it not 

be incorporated into ISO/RTO tariff 

language. However, if the Commission 

does incorporate such language, PG&E 

recommends an initiative to develop 

clearer definitions. In addition, PG&E 

states that invocation of a ‘‘material 

adverse change’’ clause should be 

selective and limited to only adverse 

conditions due to a participant’s 

financial strength or ability to meet its 

contractual obligations, but not the 

requirements of the customers and/or 

the regulators. 

2. Commission Determination 

147. We adopt the NOPR proposal to 

require ISOs and RTOs to specify in 

their tariffs the conditions under which 

they will request additional collateral 

due to a material adverse change. 

However, we are persuaded by 

commenters that this list should not be 

exhaustive and the tariff provisions 

should allow the ISOs and RTOs to use 

their discretion to request additional 

collateral in response to unusual or 

unforeseen circumstances. We are also 

persuaded that a market participant 

should receive a written explanation 

explaining the invocation of the 

material adverse change clause. 

148. While market participants are 

generally familiar with ‘‘material 

adverse change’’ clauses, a market 

administrator’s right to invoke such a 


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65958 Federal Register / Vol. 75, No. 207 / Wednesday, October 27, 2010 / Rules and Regulations 

146We will leave to the discretion of the 

individual ISOs and RTOs how much notice may 

be reasonable in particular circumstances. 

147NYISO Tariff, Attachment K (June 30, 2010) 

Section 26.8.3 for wholesale transmission service 

charges (virtual transactions and demand side 

resources offering ancillary services policies differ 

and may be result in shorter required response 

times); PJM Interconnection Tariff (6th Revised 

Version), Seventh Revised Sheet No. 523K. 

148Midwest ISO Tariff (4th Revision), Sheet No. 

2481. 

149California Independent System Operator 

Corporation, Fifth Replacement FERC Electric 

Tariff, Section 12.4; Southwest Power Pool, Fifth 

Revised Electric Tariff, Original Sheet No. 717. 

150 ISO New England Inc. Transmission, Markets 

and Services Tariff at 106–09 (Aug. 30, 2010). 

151 IRC March 29, 2010 Comments at 9. 

152NIPSCO March 29, 2010 Comments at 9. 

153APPA March 29, 2010 Comments at 33–35. 

154The ISO–NE Financial Assurance Policy 

includes credit review procedures to assess the 

ability of an applicant or of a market participant to 

pay for service transactions under the Tariff, 

identifies alternative forms of security deemed 

acceptable to the ISO, and provides the conditions 

under which the ISO will conduct business in a 

non-discriminatory way so as to avoid the 

possibility of failure of payment and to deal with 

market participants who are delinquent. ISO–NE 

Tariff, Section I, Exhibit IA. 

clause must be clarified in order to 

avoid any confusion, particularly during 

times of market duress, as to when such 

a clause may be invoked. Specifically, 

the Commission is concerned that a 

market participant in financial straits 

could 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,’’ and so delay, or even prevent 

entirely, actions that would insulate the 

market from unnecessary damage. 

149. The Commission therefore 

directs each ISO and RTO to submit a 

compliance filing that includes tariff 

revisions to establish and clarify when 

a market administrator may invoke a 

‘‘material adverse change’’ clause to 

compel a market participant to post 

additional collateral, cease one or more 

transactions, or take other measures to 

restore confidence in the participant’s 

ability to safely transact. The tariff 

revisions should state examples of 

which circumstances entitle a market 

administrator to invoke a ‘‘material 

adverse change’’ clause, but this list 

should be illustrative, rather than 

exhaustive. The tools used to determine 

‘‘material adverse change’’ should be 

sufficiently forward looking to allow the 

market administrator to take action prior 

to any adverse effect on the market, but 

provide the market participants with 

notice as to what events could trigger a 

collateral call or a change in activity in 

the market. We believe that the language 

proposed by the IRC is a good start, but 

note that it generally includes items that 

potentially lag the events that constitute 

a material adverse change. For instance, 

credit ratings tend to change slowly. As 

discussed above, the several ISOs have 

noted that they were concerned about 

large, destabilizing defaults from 

investment-grade companies. Other 

criteria, like large changes in the price 

for a collateralized debt security, are 

potentially more forward looking and 

would allow the ISO or RTO to request 

collateral before a market participant is 

in financial distress. 

150. The Commission agrees with 

those parties that suggest that it would 

be short-sighted to limit the discretion 

of the market administrator to only 

those specified instances when it could 

invoke a ‘‘material adverse change’’ 

clause to compel certain actions. 

Experience has demonstrated that 

unforeseen circumstances can arise, 

which will require action to protect the 

markets from ongoing disruption. We 

are not adopting a pro forma list 

ourselves, but allowing the ISOs and 

RTOs to develop their own ‘‘material 

adverse change’’ clauses. Nevertheless 

the compliance filing related to this 

directive must be submitted by June 30, 

2011 to take effect no later that October 

1, 2011. 

151. The Commission is also sensitive 

to the need for a record of the market 

administrator’s actions when exercising 

this discretion. Therefore, the 

Commission directs the ISOs and RTOs 

to provide reasonable advance notice 146

to a market participant, when feasible, 

when the ISOs and RTOs are compelled 

to invoke a ‘‘material adverse change’’ 

clause. The notification should be in 

writing, contain the reasoning behind 

invocation of the ‘‘material adverse 

change’’ clause, and be signed by a 

person with authority to represent the 

ISO/RTO in such actions. This will 

allow for a timely remedy for continued 

market participation, but also provide 

for a possible dispute to be resolved 

after the fact. 

G. Grace Period to ‘‘Cure’’ Collateral 

Posting 

152. Under certain circumstances, a 

market administrator may require the 

market participant to post additional 

collateral in order to continue to 

transact. Currently the organized 

wholesale electric markets vary as to the 

amount of time they allow a market 

participant to post additional collateral 

to ‘‘cure’’ its position. NYISO and PJM 

allow two days to provide additional 

collateral.147 Midwest ISO allows two to 

three days (the market participant gets 

an additional business day if notice of 

invocation of the material adverse 

change clause occurs after noon Eastern 

Daylight Time).148 CAISO and SPP 

allow three days.149 In general, ISO–NE 

requires almost immediate remedy from 

market participants who exceed all of 

the credit tests. By 10 a.m. the next 

morning, all typical market functions of 

the market participant are suspended 

(some functions are lost immediately). 

In the event that this credit test failure 

was caused by the market participant or 

a guarantor dropping a single rating 

grade or from a bank issuing a letter of 

credit being downgraded, however, it 

may have five to ten days to ‘‘cure’’ this 

situation.150

153. Establishing a brief but standard 

time period to ‘‘cure’’ a collateral posting 

will bring certainty to the market which 

can stabilize the market and its prices, 

while controlling the risk and costs of 

a default. However, the Commission is 

aware of the importance of the 

continued reliable delivery of electricity 

and that some market participants have 

‘‘provider of last resort’’ obligations. 

Consequently, the Commission 

attempted to strike a balance that allows 

an entity who is required to post 

additional collateral a reasonable 

chance to find a provider of capital—a 

bank or similar creditworthy 

institution—to assist in maintaining that 

participant’s activity, while at the same 

time not posing a risk to the market. The 

Commission therefore proposed in the 

NOPR a two-day time limit for entities 

to post additional collateral and sought 

comment on the appropriate time limit. 

1. Comments 

154. The IRC agrees that establishing 

an outer limit on the amount of time 

granted for the posting of additional 

collateral will promote confidence in 

the ISO/RTO markets by limiting default 

exposure and by shortening collateral 

posting periods.151 The Joint 

Commenters, EEI, PSEG, and Wisconsin 

Parties support standardization across 

the ISOs/RTOs, while NRECA, NIPSCO, 

and SCE support allowing the ISOs/ 

RTOs and their stakeholders discretion 

to decide whether to revise their tariffs’ 

time periods for curing collateral calls. 

NIPSCO claims that the Commission 

and ISOs/RTOs should be mindful that 

shortening the time a market participant 

has to react to margin calls could result 

in a higher rate of defaults.152 APPA 

believes the time period to cure 

collateral calls should be referred to the 

working group APPA recommends for 

Material Adverse Changes.153 NEPOOL 

argues that the ISO–NE Financial 

Assurance Policy 154 currently provides 

a suitable level of protection and urges 

that the Commission not issue any final 


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Federal Register / Vol. 75, No. 207 / Wednesday, October 27, 2010 / Rules and Regulations 65959 

155NEPOOL March 29, 2010 Comments at 20. 

156SWP March 29, 2010 Comments at 8. 

157Basin Electric March 29, 2010 Comments at 6. 

158New Jersey Public Power March 29, 2010 

Comments at 15. 

159CAISO, NCPA, CPUC, the Six Cities, and 

PG&E. 

160Six Cities March 29, 2010 Comments at 6–7. 

161Calpine March 29, 2010 Comments at 11–12. 

162Midwest ISO March 29, 2010 Comments at 21. 

163NRECA March 29, 2010 Comments at 19. 

164Morgan Stanley March 29, 2010 Comments at 

10; NYTO March 29, 2010 Comments at 10. 

165Midwest TDUs March 29, 2010 Comments at 

20–21. 

166 J.P. Morgan March 26, 2010 Comments at 13. 

167CFTC staff notes its comments are focused on 

FTRs even though they may be applicable to other 

markets as well. CFTC staff March 29, 2010 

Comments at 2. 

168 Id. at 10. 

169See Midwest ISO March 29, 2010 Comments 

at 21. 

170NRECA March 29, 2010 Comments at 19. 

171NOPR, FERC Stats. & Regs. ¶ 32,651 at P 8. 

rule that would require changes to that 

policy.155

155. Certain parties believe there 

should be different time periods for 

certain market participants. For 

example, while SWP supports a 

standardized time period across ISOs/ 

RTOs, it believes the time period should 

also recognize the differences in market 

participants. SWP states that entities 

that participate in markets on a purely 

financial basis should post additional 

collateral within two days, but entities 

with an obligation to serve should have 

a minimum of three days.156 Basin 

Electric believes the length of the cure 

period should be related to the severity 

of the material adverse change giving 

rise to the need to cure.157 New Jersey 

Public Power suggests that a longer, 

sixty-day period is more appropriate for 

municipal utilities.158

156. Regarding the appropriate time 

period to post additional collateral, 

several parties from California 159

support keeping the current CAISO rule 

of a three-day cure period. These parties 

express concerns about the burdens of a 

shorter time period. For example, Six 

Cities argue that the internal review and 

authorization processes applicable to 

collateral commitments for Six Cities 

would make it difficult to post 

additional collateral within two 

business days, so the current three-day 

period should remain in effect, at least 

for governmental entities.160

157. Other parties, however, believe a 

two-day period to post additional 

collateral is more appropriate. Calpine 

requests that the Commission require 

ISOs and RTOs to adopt a standardized 

two-day cure period.161 DC Energy, 

Direct Energy, Dominion, and Dynegy 

all support a standardized two-day cure 

period across all ISOs/RTOs. Midwest 

ISO and NRECA support a two-day cure 

period. Midwest ISO states that it views 

this proposal as generally being a 

standard practice in wholesale electric 

markets.162 NRECA acknowledges that 

the standard financial industry practice 

allows two business days to post 

additional collateral after receipt of the 

demand, but the ISO/RTO stakeholder 

process is the best vehicle for 

addressing this on a regional basis.163

Morgan Stanley and the NYTOs find 

that the current two-day period is 

sufficient in PJM and NYISO, 

respectively.164 OMS, Consumers 

Energy, EPSA, FirstEnergy, Shell 

Energy, and CEI and MidAmerican state 

that two days is a reasonable amount of 

time to post additional collateral. 

158. Additional parties have various 

opinions on the appropriate time period 

to post additional collateral. While SPP 

currently requires market participants to 

post additional security within three 

days, it states a two-day period strikes 

a reasonable balance between the need 

to reduce identified risk and the 

challenges a demand for collateral might 

place on a market participant. Midwest 

TDUs state that the Commission should 

not adopt a limit to the time period for 

collateral calls, but if it does, three 

business days would be appropriate and 

two days is the minimum.165 J.P. 

Morgan supports a cure period of one or 

two business days, recognizing that 

market participants have the ability to 

post cash immediately and then 

subsequently replace such cash deposits 

with permitted financial instruments of 

their choosing (e.g., letters of credit).166

159. Finally, CFTC staff believes that 

a two-day cure period may be too long 

for collateral calls.167 CFTC staff states 

that a cure period of more than one day 

is inconsistent with the purpose of such 

a call, since the risk exposure of the 

ISO/RTO is diminished by the posting 

of additional collateral.168

2. Commission Determination 

160. The Commission adopts the 

NOPR proposal to require each ISO and 

RTO to include in the credit provisions 

of its tariff language to limit the time 

period allowed to post additional 

collateral. In addition, we require each 

ISO and RTO to allow no more than two 

days to ‘‘cure’’ a collateral call. The 

Commission directs each ISO and RTO 

to submit a compliance filing that 

includes tariff revisions to establish a 

two-day limit to post additional 

collateral due to invocation of a 

‘‘material adverse change’’ clause or 

other provision of an ISO/RTO tariff. 

This compliance filing must be 

submitted by June 30, 2011, and the 

tariff revisions will take effect October 

1, 2011. 

161. The Commission recognizes the 

difficult position parties can find 

themselves in when additional 

collateral is required on short notice. 

Nevertheless, the time allowed for a 

‘‘cure’’ needs to be short to minimize 

uncertainty as to a participant’s ability 

to participate in the market, and to 

minimize the risk and costs of a default 

by a participant (which, as noted 

elsewhere, affects other participants). 

The Commission also understands the 

rationale presented by CFTC staff when 

they suggest that any period longer than 

a day can be hazardous to the market. 

We thus seek to strike a balance: to 

minimize the potential for market 

disruptions and the risk and costs of a 

default, while allowing participants 

sufficient time to obtain additional 

capital so that they can continue to 

participate in the market. The 

Commission is persuaded that a limit of 

no more than two days to cure a 

collateral call achieves the desired 

balance. 

162. Two days should be sufficient for 

a market participant which is called 

upon to ‘‘cure’’ to arrange reasonable 

capital requirements. In reaching this 

determination, we note that some of the 

ISO/RTO markets already have a twoday cure period, so it should not prove 

overly burdensome to mandate this 

standard for all markets.169

Additionally, commenters point out that 

a two-day limit is a standard financial 

industry practice.170

163. We disagree with the argument 

that the Commission should not apply 

the same limit to all the ISO/RTO 

markets. We see no distinction between 

the ISO/RTO markets that warrant 

differentiation. 

H. General Applicability 

164. When the Commission issued the 

NOPR, we requested comment ‘‘on 

whether the credit practices discussed 

below should be applied in the same 

way to all market participants or 

whether they should be applied 

differently to certain market participants 

depending on their characteristics.’’ 171

The Commission received substantial 

comment on this question both for 

uniform applicability of credit practices 

and against uniform application but 

received little in the way of verifiable 

evidence to support either contention. 

The Commission has also reviewed 

historic and recent developments in 

debt markets which tend to reflect risk 

of default—a central element of this 


jdjones on DSK8KYBLC1PROD with RULES
65960 Federal Register / Vol. 75, No. 207 / Wednesday, October 27, 2010 / Rules and Regulations 

172 44 U.S.C. 3507(d). 173Regulations Implementing the National 

Environmental Policy Act, Order No. 486, 52 FR 

47897 (Dec. 17, 1987), FERC Stats. & Regs. ¶ 30,783 

(1987). 

rulemaking process—in order to obtain 

additional information to consider the 

question asked in the NOPR. 

165. Based on, among other things, a 

review of comments, Commission 

experience, and our review of the 

historic and recent developments in the 

debt markets, the Commission 

determines that the credit practices in 

this Final Rule will apply to all market 

participants. In making this 

determination, the Commission is aware 

that ISOs and RTOs may, through their 

stakeholder processes, ask for specific 

exemptions based on their experience 

and appropriate supporting evidence, 

particularly for individual entities 

whose participation is such that a 

default would not risk significant 

market disruptions. The Commission, 

however, will not, at this time in this 

generic rulemaking, adopt any 

exemptions. 

IV. Information Collection Statement 

166. The Office of Management and 

Budget’s (OMB) regulations require 

approval of certain information 

collection requirements imposed by 

agency rules. Upon approval of a 

collection(s) of information, OMB will 

assign an OMB control number and an 

expiration date. Respondents subject to 

the filing requirements of a rule will not 

be penalized for failing to respond to 

these collections of information unless 

the collections of information display a 

valid OMB control number. 

167. This Final Rule amends the 

Commission’s regulations pursuant to 

section 206 of the Federal Power Act, to 

reform credit practices of organized 

wholesale electric markets to limit 

potential future market disruptions. To 

accomplish this, the Commission 

requires RTOs and ISOs to adopt tariff 

revisions reflecting these credit reforms. 

Such filings would be made under Part 

35 of the Commission’s regulations. The 

information provided for under Part 35 

is identified as FERC–516. 

168. Under section 3507(d) of the 

Paperwork Reduction Act of 1995,172

the reporting requirements in this 

rulemaking will be submitted to OMB 

for review. In their notice of March 18, 

2010, OMB took no action on the NOPR, 

instead deferring their approval until 

review of the Final Rule. 

169. The Commission solicited 

comments on the need for this 

information, whether the information 

will have practical utility, the accuracy 

of provided burden estimates, ways to 

enhance the quality, utility, and clarity 

of the information to be collected, and 

any suggested methods for minimizing 

the respondent’s burden, including the 

use of automated information 

techniques. The Commission did not 

receive any specific comments regarding 

its burden estimates. The Public 

Reporting burden for the requirements 

contained in the Final Rule is as 

follows: 

Data collection Number of 

respondents 

Number of 

responses 

Hours per 

response 

Total annual 

hours 

FERC–516: 

Transmission Organizations with Organized Electricity Markets ........................................................................................ 6 1 100 600 

Information Collection Costs: The 

Commission has projected the average 

annualized cost of all respondents to be 

the following: 

600 hours @ $300 per hour = $180,000 

for respondents. No capital costs are 

estimated to be incurred by 

respondents. 

Title: FERC–516, Electric Rate 

Schedule Tariff Filings. 

Action: Information Collection. 

OMB Control No: 1902–0096. 

Respondents: Businesses or other for 

profit and/or not-for-profit institutions. 

Necessity of the Information: The 

information from FERC–516 enables the 

Commission to exercise its wholesale 

electric power and transmission 

oversight responsibilities in accordance 

with the Federal Power Act. The 

Commission needs sufficient detail to 

make an informed and reasonable 

decision concerning the appropriate 

level of rates, and the appropriateness of 

non-rate terms and conditions, and to 

aid customers and other parties who 

may wish to challenge the rates, terms, 

and conditions proposed by the utility. 

170. This Final Rule amends the 

Commission’s regulations to ensure that 

credit practices currently in place in 

organized wholesale electric markets 

reasonably protect consumers against 

the adverse effects of default. To 

promote confidence in the markets, the 

Commission believes it is appropriate to 

adopt specific requirements regarding 

credit practices for organized wholesale 

electric markets. These requirements 

include shortening of billing and 

settlement periods and reducing the 

amount of unsecured credit. The 

Commission believes these actions will 

enhance certainty and stability in the 

markets, and in turn, ensure that costs 

associated with market participant 

defaults do not result in unjust or 

unreasonable rates. 

171. Internal Review: The 

Commission has reviewed the 

requirements pertaining to organized 

wholesale electric markets and 

determined the proposed requirements 

are necessary to its responsibilities 

under section 206 of the Federal Power 

Act. 

172. These requirements conform to 

the Commission’s plan for efficient 

information collection, communication 

and management within the energy 

industry. The Commission has assured 

itself, by means of internal review, that 

there is specific, objective support for 

the burden estimates associated with the 

information requirements. 

173. Interested persons may obtain 

information on this information 

collection by contacting the following: 

Federal Energy Regulatory Commission, 

888 First Street, NE., Washington, DC 

20426, Attention: Ellen Brown, Office of 

the Executive Director, phone: (202) 

502–8663, fax: (202) 273–0873, e-mail: 

DataClearance@ferc.gov. 

174. Comments concerning this 

information collection can be sent to the 

Office of Management and Budget, 

Office of Information and Regulatory 

Affairs, Washington, DC 20503 

[Attention: Desk Officer for the Federal 

Energy Regulatory Commission, phone: 

(202) 395–4650, fax: (202) 395–7285]. 

V. Environmental Analysis 

175. The Commission is required to 

prepare an Environmental Assessment 

or an Environmental Impact Statement 

for any action that may have a 

significant adverse effect on the human 

environment.173 The Commission 

concludes that neither an 

Environmental Assessment nor an 

Environmental Impact Statement is 


jdjones on DSK8KYBLC1PROD with RULES
Federal Register / Vol. 75, No. 207 / Wednesday, October 27, 2010 / Rules and Regulations 65961 

174 18 CFR 380.4(a)(15). 

175 5 U.S.C. 601–12. 

176The 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. 

177See Regional Transmission Organizations, 

Order No. 2000, 65 FR 809 (January 6, 2000), FERC 

Stats. & Regs., Regulations Preambles July 1996– 

December 2000 ¶ 31,089, at 31,237 & n.754 (1999), 

order on reh’g, Order No. 2000–A, 65 FR 12,088 

(March 8, 2000), FERC Stats. & Regs., Regulations 

Preambles July 1996–December 2000 ¶ 31,092 

(2000), aff’d sub nom. Pub. Util. Dist. No. 1 of 

Snohomish, County Washington v. FERC, 272 F.3d 

607, 348 U.S. App. D.C. 205 (D.C. Cir. 2001) (citing 

Mid-Tex Elec. Coop. v. FERC, 773 F.2d 327 (D.C. 

Cir. 1985) (Commission need only consider small 

entities ‘‘that would be directly regulated’’); 

Colorado State Banking Bd. v. RTC, 926 F.2d 931 

(10th Cir. 1991) (Regulatory Flexibility Act not 

implicated where regulation simply added an 

option for affected entities and did not impose any 

costs)). 

178The credit practices required by this Final 

Rule are akin to insurance against a disruption in 

the market that could lead to a major default and 

result in costs being socialized among all market 

participants. The Commission believes that the 

benefit of avoiding major market disruptions 

outweighs the cost of such insurance. 

179See 5 U.S.C. 804(2). 

180See 5 U.S.C. 801(a)(1)(A). 

required for this Final Rule under 

Section 380.4(a)(15) of the 

Commission’s regulations, which 

provides a categorical exemption for 

approval of actions under sections 205 

and 206 of the FPA relating to rates and 

charges and terms and conditions for 

transmission or sales subject to the 

Commission’s jurisdiction.174

VI. Regulatory Flexibility Act 

Certification 

176. The Regulatory Flexibility Act of 

1980 (RFA) 175 requires a description 

and analysis of rules that will have a 

significant economic impact on a 

substantial number of small entities.176

The Commission is not required to make 

such analyses if a rule would not have 

such an effect. 

177. The RTOs and ISOs regulated by 

the Commission do not fall within the 

RFA’s definition of small entity. In 

addition, the vast majority of market 

participants in RTOs and ISOs are, 

either alone or as part of larger corporate 

families, not small entities. And the 

protections proposed here will protect 

all market participants, including small 

market participants, by reducing risk by 

reducing the likelihood of defaults and 

minimizing the impact of any defaults. 

178. California Independent Service 

Operator Corp. is a nonprofit 

organization comprised of more than 90 

electric transmission companies and 

generators operating in its markets and 

serving more than 30 million customers. 

179. New York Independent System 

Operator, Inc. is a nonprofit 

organization that oversees wholesale 

electricity markets serving 19.2 million 

customers. NYISO manages a 10,775- 

mile network of high-voltage lines. 

180. PJM Interconnection, L.L.C. is 

comprised of more than 450 members 

including power generators, 

transmission owners, electricity 

distributors, power marketers and large 

industrial customers and serving 13 

states and the District of Columbia. 

181. Southwest Power Pool, Inc. is 

comprised of 50 members serving 4.5 

million customers in eight states and 

has 52,301 miles of transmission lines. 

182. Midwest Independent 

Transmission System Operator, Inc. 

(Midwest ISO) is a non-profit 

organization with over 131,000 

megawatts of installed generation. 

Midwest ISO has 93,600 miles of 

transmission lines and serves 15 states 

and one Canadian province. 

183. ISO New England Inc. is a 

regional transmission organization 

serving six states in New England. The 

system is comprised of more than 8,000 

miles of high voltage transmission lines 

and several hundred generating 

facilities of which more than 350 are 

under ISO–NE’s direct control. 

184. Therefore, the Commission 

certifies that this Final Rule will not 

have a significant economic impact on 

a substantial number of small entities. 

As a result, no regulatory flexibility 

analysis is required. As discussed in 

Order No. 2000,177 in making this 

determination, the Commission is 

required to examine only the direct 

compliance costs that a rulemaking 

imposes upon small businesses. It is not 

required to consider indirect economic 

consequences, nor is it required to 

consider costs that an entity incurs 

voluntarily. This rulemaking does not 

impose significant compliance costs 

upon small entities; the RTOs and ISOs 

directly affected—in that they have to 

adopt new or revised tariff language— 

are not small entities. Further, as to 

entities indirectly affected, i.e., market 

participants, most of them are not small 

entities. And, in any event, as to all 

market participants large and small, as 

we explained in Order No. 2000, supra, 

they have a choice of whether to join an 

RTO and whether to be a market 

participant or not. Moreover, the 

Commission believes that, to the extent 

that the credit reforms required by this 

Final Rule indirectly may impose 

potentially higher costs on some entities 

in the short-term, these reforms will also 

protect the markets and their 

participants from unacceptable 

disruptions and resulting costly 

defaults.178 Thus, this rulemaking will 

not have a significant economic impact 

upon any small entities. 

VII. Document Availability 

185. 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. 

186. From the Commission’s Home 

Page on the Internet, this information is 

available in the Commission’s document 

management system, eLibrary. The full 

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. 

187. User assistance is available for 

eLibrary and the Commission’s Web site 

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). 

VIII. Effective Date and Congressional 

Notification 

188. This Final Rule will take effect 

November 26, 2010. The Commission 

has determined, with the concurrence of 

the Administrator of the Office of 

Information and Regulatory Affairs of 

OMB, that this rule is not a major rule 

within the meaning of section 251 of the 

Small Business Regulatory Enforcement 

Fairness Act of 1996.179 The 

Commission will submit this Final Rule 

to both Houses of Congress and the 

General Accountability Office.180

List of Subjects in 18 CFR Part 35 

Electric power rates, Electric utilities, 

Reporting and recordkeeping 

requirements. 


jdjones on DSK8KYBLC1PROD with RULES
65962 Federal Register / Vol. 75, No. 207 / Wednesday, October 27, 2010 / Rules and Regulations 

By the Commission. 

Nathaniel J. Davis, Sr., 

Deputy 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. Subpart J is added to read as 

follows: 

Subpart J—Credit Practices In 

Organized Wholesale Electric Markets 

Sec. 

35.45 Applicability. 

35.46 Definitions. 

35.47 Tariff provisions governing credit 

practices in organized wholesale electric 

markets. 

§ 35.45 Applicability. 

This subpart establishes credit 

practices for organized wholesale 

electric markets for the purpose of 

minimizing risk to market participants. 

§ 35.46 Definitions. 

As used in this subpart: 

(a) Market Participant means an entity 

that qualifies as a Market Participant 

under § 35.34. 

(b) Organized Wholesale Electric 

Market includes an independent system 

operator and a regional transmission 

organization. 

(c) Regional Transmission 

Organization means an entity that 

qualifies as a Regional Transmission 

Organization under 18 CFR 35.34. 

(d) Independent System Operator 

means an entity operating a 

transmission system and found by the 

Commission to be an Independent 

System Operator. 

§ 35.47 Tariff provisions regarding credit 

practices in organized wholesale electric 

markets. 

Each organized wholesale electric 

market must have tariff provisions that: 

(a) Limit the amount of unsecured 

credit extended by an organized 

wholesale electric market to no more 

than: 

(1) $50 million for each market 

participant; and 

(2) $100 million for all entities within 

a corporate family. 

(b) Adopt a billing period of no more 

than seven days and allow a settlement 

period of no more than seven days. 

(c) Eliminate unsecured credit in 

financial transmission rights markets 

and equivalent markets. 

(d) Establish a single counterparty to 

all market participant transactions, or 

require each market participant in an 

organized wholesale electric market to 

grant a security interest to the organized 

wholesale electric market in the 

receivables of its transactions, or 

provide another method of supporting 

netting that provides a similar level of 

protection to the market and is 

approved by the Commission. In the 

alternative, the organized wholesale 

electric market shall not net market 

participants’ transactions and must 

establish credit based on market 

participants’ gross obligations. 

(e) Limit to no more than two days the 

time period provided to post additional 

collateral when additional collateral is 

requested by the organized wholesale 

electric market. 

(f) Require minimum participation 

criteria for market participants to be 

eligible to participate in the organized 

wholesale electric market. 

(g) Provide a list of examples of 

circumstances when a market 

administrator may invoke a ‘‘material 

adverse change’’ as a justification for 

requiring additional collateral; this list 

does not limit a market administrator’s 

right to invoke such a clause in other 

circumstances. 

Note: The following Appendix will not be 

published in the Code of Federal Regulations. 

APPENDIX LIST OF INTERVENORS AND COMMENTERS

Commenters 

Acronym Name 

AMP ...................................................... American Municipal Power. 

APPA .................................................... American Public Power Association. 

Basin Electric ........................................ Basin Electric Power Cooperative. 

BP Energy ............................................ BP Energy Company. 

BPA ...................................................... Bonneville Power Administration. 

CAISO .................................................. California Independent System Operator Corporation. 

Calpine ................................................. Calpine Corporation. 

CCRO ................................................... Committee of Chief Risk Officers. 

CFTC staff ............................................ Commodity Futures Trading Commission. 

Citigroup ............................................... Citigroup Energy Inc. 

City of New York .................................. City of New York. 

Constellation/NRG ................................ Constellation Companies and NRG Companies. 

CPUC ................................................... California Public Utility Commission. 

DC Energy ............................................ DC Energy, LLC. 

Detroit Edison ....................................... Detroit Edison Company. 

Direct Energy ........................................ Direct Energy Services, LLC. 

DMEC ................................................... Delaware Municipal Electric Corporation, Inc. 

Dominion .............................................. Dominion Resources Services Inc. 

Duke ..................................................... Duke Energy Corporation. 

Dynegy ................................................. Dynegy Power Marketing, Inc. 

East Texas Electric Cooperatives ........ East Texas Electric Cooperatives. 

EEI ........................................................ Edison Electric Institute. 

EMCOS ................................................ Eastern Massachusetts Consumer-Owned Systems, including Braintree Electric Light Department, Concord Municipal Light Plant, Hingham Municipal Lighting Plant, Reading Municipal Light Department, 

Taunton Municipal Lighting Plan, Wellesley Municipal Light Plant. 

EPSA .................................................... Electric Power Supply Association. 

Financial Marketers .............................. Jump Power, LLC; Energy Endeavors LP; Big Bog Energy, LP; Silverado Energy LP; Gotham Energy 

Marketing LP; Rockpile Energy LP; Coaltrain Energy LP; Longhorn Energy LP; MET MA, LLC; Solios 

Power, LLC; and JPTC, LLC. 


jdjones on DSK8KYBLC1PROD with RULES
Federal Register / Vol. 75, No. 207 / Wednesday, October 27, 2010 / Rules and Regulations 65963 

APPENDIX LIST OF INTERVENORS AND COMMENTERS—Continued 

Commenters 

Acronym Name 

First Energy .......................................... First Energy Service Company, including American Transmission Systems, Inc., The Cleveland Electric 

Illuminating Company, Jersey Central Power & Light Company, Pennsylvania Power Company, The 

Toledo Edison Company, and FirstEnergy Solutions Corp. 

Hess ..................................................... Hess Corporation. 

IMEA ..................................................... Illinois Municipal Electric Agency. 

IPPNY ................................................... Independent Power Producers of New York. 

IRC ....................................................... ISO/RTO Council. 

ISO–NE ................................................ ISO New England Inc. 

J.P. Morgan .......................................... J.P. Morgan Ventures Energy Corporation. 

Joint Commenters ................................ Constellation Energy Commodities Group, Inc., Constellation NewEnergy, Inc., and Integrys Energy 

Services, Inc. 

MidAmerican ......................................... MidAmerican Energy Holdings Company. 

Midwest ISO ......................................... Midwest Independent Transmission Operator, Inc. 

Midwest TDUs ...................................... Indiana Municipal Power Agency, Madison Gas & Electric Company, Missouri River Energy Services, 

Southern Minnesota Municipal Power Agency, and WPPI Energy. 

Mirant .................................................... Mirant Corporation. 

Morgan Stanley .................................... Morgan Stanley Capital Group Inc. 

NEMA ................................................... National Energy Marketers Association. 

NEPOOL ............................................... New England Power Pool Participants Committee. 

New Jersey Public Power .................... Public Power Association of New Jersey and Madison, New Jersey. 

New York Consumers .......................... Multiple Intervenors, including more than 50 large industrial, commercial, and institutional end-use energy consumers located in New York. 

New York Suppliers .............................. Small Customer Marketer Coalition (The Constellation Companies, The CENG Companies, and The 

NRG Companies). 

NIPSCO ................................................ Northern Indiana Public Service Company. 

Northeast ISOs ..................................... ISO–NE, NYISO, and PJM Joint Comments. 

Northern California Power Agency ....... Northern California Power Agency. 

NRECA ................................................. National Rural Electric Cooperative Association. 

NYISO .................................................. New York Independent System Operator, Inc. 

NYPSC ................................................. New York Public Service Commission. 

NYSCB ................................................. New York State Consumer Protection Board. 

NYTOs .................................................. New York Transmission Owners, including 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, Orange and Rockland Utilities, Inc., and Rochester Gas and 

Electric Corporation. 

OMS ..................................................... Organization of Midwest ISO States. 

PG&E .................................................... Pacific Gas & Electric Company. 

PJM ...................................................... PJM Interconnection, L.L.C. 

Powerex ................................................ Powerex. 

PSEG .................................................... Public Service Electric and Gas Company, PSEG Power LLC, and PSEG Energy Resources & Trade 

LLC. 

SCE ...................................................... Southern California Edison Company. 

SDG&E ................................................. San Diego Gas & Electric Company. 

Shell Energy ......................................... Shell Energy. 

Six Cities .............................................. Cities of Anaheim, Azusa, Banning, Colton, Pasadena, and Riverside, California. 

SPP ...................................................... Southwest Power Pool, Inc. 

SWP ..................................................... California Department of Water Resources State Water Project. 

WAPA ................................................... Western Area Power Administration. 

Wisconsin parties ................................. Wisconsin Public Service Commission and Upper Peninsula Power Company. 

WPTF ................................................... Western Power Trading Forum. 

Xcel ....................................................... Xcel Energy Services. 


jdjones on DSK8KYBLC1PROD with RULES
65964 Federal Register / Vol. 75, No. 207 / Wednesday, October 27, 2010 / Rules and Regulations 

1 16 U.S.C. 824o (2006). 

2North American Electric Reliability Corp., 116 

FERC ¶ 61,062, order on reh’g & compliance, 117 

FERC ¶ 61,126 (2006), aff’d sub nom. Alcoa, Inc. 

v. FERC, 564 F.3d 1342 (D.C. Cir. 2009). 

3NERC designates the version number of a 

Reliability Standard as the last digit of the 

Reliability Standard number. Therefore, original 

Reliability Standards end with ‘‘-0’’ and modified 

version one Reliability Standards end with ‘‘-1.’’ 

4 16 U.S.C. 824o(d)(2). 

5 In Order No. 672, the Commission found that it 

should order only the ERO to modify a Reliability 

Standard because the ERO is the only entity that 

may directly submit a proposed Reliability 

Standard to the Commission for approval. Rules 

Concerning Certification of the Electric Reliability 

Organization; Procedures for the Establishment, 

Approval, and Enforcement of Electric Reliability 

Standards, Order No. 672, 71 FR 8662 (Feb. 17, 

2006), FERC Stats. & Regs. ¶ 31,204, at P 423, order 

on reh’g, Order No. 672–A, 71 FR 19814 (Apr. 18, 

2006), FERC Stats. & Regs. ¶ 31,212 (2006). 

[FR Doc. 2010–27129 Filed 10–26–10; 8:45 am] 

BILLING CODE 6717–01–P 

DEPARTMENT OF ENERGY 

Federal Energy Regulatory 

Commission 

18 CFR Part 40 

[Docket No. RM09–15–000; Order No. 740] 

Version One Regional Reliability 

Standard for Resource and Demand 

Balancing 

Issued October 21, 2010. 

AGENCY: Federal Energy Regulatory 

Commission, DOE. 

ACTION: Final rule. 

SUMMARY: Under section 215 of the 

Federal Power Act, the Commission 

hereby remands a revised regional 

Reliability Standard developed by the 

Western Electricity Coordinating 

Council and approved by the North 

American Electric Reliability 

Corporation, which the Commission has 

certified as the Electric Reliability 

Organization responsible for developing 

and enforcing mandatory Reliability 

Standards. The revised regional 

Reliability Standard, designated by 

WECC as BAL–002–WECC–1, would set 

revised Contingency Reserve 

requirements meant to maintain 

scheduled frequency and avoid loss of 

firm load following transmission or 

generation contingencies. 

DATES: Effective Date: This rule will 

become effective November 26, 2010. 

FOR FURTHER INFORMATION CONTACT:

Nick Henery (Technical Information), 

Office of Electric Reliability, Federal 

Energy Regulatory Commission, 888 

First Street, NE., Washington, DC 

20426, (202) 502–8636. 

Scott Sells (Technical Information), 

Office of Electric Reliability, Federal 

Energy Regulatory Commission, 888 

First Street, NE., Washington, DC 

20426, (202) 502–6664. 

A. Cory Lankford (Legal Information), 

Office of General Counsel, Federal 

Energy Regulatory Commission, 888 

First Street, NE., Washington, DC 

20426, (202) 502–6711. 

SUPPLEMENTARY INFORMATION: 

Table of Contents 

Paragraph 

Nos. 

I. Background .......................................................................................................................................................................................... 3 

A. Mandatory Reliability Standards ............................................................................................................................................... 3 

B. Western Electricity Coordinating Council ................................................................................................................................. 6 

C. WECC Regional Reliability Standard BAL–002–WECC–1 ....................................................................................................... 9 

II. Discussion .......................................................................................................................................................................................... 14 

A. Due Weight and Effect of Remand ............................................................................................................................................ 15 

B. Contingency Reserve Restoration Period ................................................................................................................................... 22 

C. Calculation of Minimum Contingency Reserve ........................................................................................................................ 31 

D. Use of Firm Load To Meet Contingency Reserve Requirement ............................................................................................... 42 

E. Demand-Side Management as a Resource ................................................................................................................................. 50 

F. Miscellaneous .............................................................................................................................................................................. 63 

III. Information Collection Statement .................................................................................................................................................... 67 

IV. Environmental Analysis ................................................................................................................................................................... 68 

V. Regulatory Flexibility Act ................................................................................................................................................................. 69 

VI. Document Availability ..................................................................................................................................................................... 70 

VII. Effective Date and Congressional Notification .............................................................................................................................. 73 

Before Commissioners: Jon Wellinghoff, 

Chairman; Marc Spitzer, Philip D. 

Moeller, John R. Norris, and Cheryl A. 

LaFleur 

1. Pursuant to section 215 of the 

Federal Power Act (FPA),1 the 

Commission hereby remands a revised 

regional Reliability Standard developed 

by the Western Electricity Coordinating 

Council (WECC) and approved by the 

North American Electric Reliability 

Corporation (NERC), which the 

Commission has certified as the Electric 

Reliability Organization (ERO) 

responsible for developing and 

enforcing mandatory Reliability 

Standards.2 The revised regional 

Reliability Standard, designated by 

WECC as BAL–002–WECC–1,3 is meant 

to ensure that adequate resources are 

available at all times to maintain 

scheduled frequency, and avoid loss of 

firm load following transmission or 

generation contingencies. As discussed 

below, the Commission finds that the 

proposed regional Reliability Standard 

does not meet the statutory criteria for 

approval that it be just, reasonable, not 

unduly discriminatory or preferential, 

and in the public interest.4

2. The Commission remands the 

proposed regional Reliability Standard 

based on concerns that WECC has not 

provided adequate technical support to 

demonstrate that the requirements of the 

proposed regional Reliability Standard 

are sufficient to ensure the reliable 

operation of the Bulk-Power System 

within WECC. Specifically, WECC’s 

data indicates that extending the reserve 

restoration period from 60 to 90 minutes 

presents an unreasonable risk that a 

second major contingency could occur 

before reserves are restored after an 

initial contingency. Without further 

technical justification demonstrating 

that this less stringent requirement will 

adequately support reliability in the 

Western Interconnection, the 

Commission is unable to determine that 

the proposed regional Reliability 

Standard is just, reasonable, not unduly 

discriminatory or preferential, and in 

the public interest. Accordingly, we 

remand WECC regional Reliability 

Standard BAL–002–WECC–1 to the ERO 

so that the Regional Entity may develop 

further modifications consistent with 

this final rule.5


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