133 FERC ¶ 61,060 

UNITED STATES OF AMERICA 

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. 

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. 

EFFECTIVE DATE: This Final Rule will become effective on [insert date 30 days after 

publication in the FEDERAL REGISTER]. 

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 
Docket No. RM10-13-000 - 2 - 

 

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: 
 

 

133 FERC ¶ 61,060 

UNITED STATES OF AMERICA 

FEDERAL ENERGY REGULATORY COMMISSION 

Before Commissioners: Jon Wellinghoff, Chairman; 

 Marc Spitzer, Philip D. Moeller, 

 John R. Norris, and Cheryl A. LaFleur. 

Credit Reforms in Organized Docket No. RM10-13-000 

Wholesale Electric Markets 

 

ORDER NO. 741 

FINAL RULE 

(Issued October 21, 2010) 

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 

 

1

 For 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). 
Docket No. RM10-13-000 - 2 - 

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 markets under its jurisdiction. 

 2

 16 U.S.C. 824d, 824e (2006). 
Docket No. RM10-13-000 - 3 - 

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 

 

 (continued...) 

3

 References 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. 

4 Promoting 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.
Docket No. RM10-13-000 - 4 - 

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. 

 

Transmission Access Policy Study Group v. FERC, 225 F.3d 667 (D.C. Cir. 2000), aff’d 

sub nom. New York v. FERC, 535 U.S. 1 (2002). 

5 See Electric Creditworthiness Standards, Notice of Technical Conference, 

Docket No. AD04-8-000 (issued May 28, 2004). 

6 See 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). 

7 Policy Statement on Electric Creditworthiness, 109 FERC ¶ 61,186 (2004) 

(Policy Statement). 
Docket No. RM10-13-000 - 5 - 

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

 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.”). 

9

 A review of commercial bond spreads for creditworthy entities versus threemonth 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. 
Docket No. RM10-13-000 - 6 - 

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 nearmisses” 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 

 10 Technical 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). 

13 Credit Reforms in Organized Wholesale Electric Markets, Notice of Proposed 

Rulemaking, 75 FR 4310 (Jan. 27, 2010), FERC Stats. & Regs. ¶ 32,651 (2010) (NOPR). 
Docket No. RM10-13-000 - 7 - 

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 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 Id. P 9. 
Docket No. RM10-13-000 - 8 - 

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 

 15 Committee 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/committeesgroups/committees/mc/20080626/20080626-item-03d-crmsc-market-reform-creditrecommendations.ashx; and CME market requirements at 

http://www.cmegroup.com/clearing/financial-and-collateral-management. 

16 The commenters are listed in an appendix to this Final Rule. 

17 Notice Establishing Date for Comments, 75 FR 27552 (May 17, 2010). 
Docket No. RM10-13-000 - 9 - 

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 

 18 Some 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.” 

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

20 ISO New England, Inc. and New England Power Pool, 132 FERC ¶ 61,046 

(2010). 

21 Midwest ISO March 29, 2010 Comments at 4. 
Docket No. RM10-13-000 - 10 - 

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 

 

 (continued...) 

22 PJM March 29, 2010 Comments at 21. 

23 SPP March 29, 2010 Comments at 3. 

24 CAISO March 29, 2010 Comments at 8. 

25 Northeast ISOs March 29, 2010 Comments at n.17; NYISO OATT at section 

2.7.3.2. 

26 NOPR, 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/committeesgroups/committees/mc/20080626/20080626-item-03d-crmsc-market-reform-creditrecommendations.ashx)). 

27 See Policy Statement, 109 FERC ¶ 61,186, at P 22 (citing Memorandum to 

NEPOOL Participants Committee re: Amendments to Billing Policy and Financial 
Docket No. RM10-13-000 - 11 - 

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 Morgan Stanley Capital Group 

(Morgan Stanley). The staff of the Division of Clearing & Intermediary Oversight at the 

 

Assurance Policies to Implement Weekly Billing, Paul Belval and Scott Myers, NEPOOL 

Counsel, Feb. 21, 2004). 

28 SESCO 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. 
Docket No. RM10-13-000 - 12 - 

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

 29 Although 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. 

30 New 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. 

31 CCRO March 29, 2010 Comments at 3. 

32 New York Suppliers March 29, 2010 Comments at 9. 

33 Id. at 9-10. 

34 IPPNY March 29, 2010 Comments at 12-13. 
Docket No. RM10-13-000 - 13 - 

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 

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

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

37 The “Six Cities” include the cities of Anaheim, Azusa, Banning, Colton, 

Pasadena, and Riverside, all located in California. 
Docket No. RM10-13-000 - 14 - 

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 

 38 City of New York March 29, 2010 Comments at 6-7; NYPSC March 29, 2010 

Comments at 3-4. 

39 NYPSC 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. 

41 Midwest TDU March 29, 2010 Comments at 7-9; Consolidated Edison 

Solutions March 29, 2010 Comments at 3-4. 

42 PG&E March 29, 2010 Comments at 2. 
Docket No. RM10-13-000 - 15 - 

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 

 43 J.P. Morgan Comments at 6; MSCG Comments at 2 – 3. 

44 CFTC staff Comments on 5. 

45 Calpine Comments at 4 & n.8 (citing ISO New England Inc., and New England 

Power Pool March 26, 2010 filing, Docket No. ER10-942-000). 

46 Calpine Comments at 4. 

47 Id. at 5. 
Docket No. RM10-13-000 - 16 - 

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 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 

 48 CAISO Comments at 9; IRC Comments at 4-5; MISO Comments at 5; PJM 

Comments at 21-23. 

49 APPA Comments at 17; NRECA Comments at 10; NYAPP Comments at 10; 

PPANJ Comments at 10-11. 

50 Basin Electric Comments at 3. 

51 Midwest TDUs Comments at 11-12. 

52 NRECA Comments at 10. 
Docket No. RM10-13-000 - 17 - 

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 

 53 WAPA Comments at 5-6. 

54 Policy Statement, 109 FERC ¶ 61,186, at P 24. 
Docket No. RM10-13-000 - 18 - 

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. 

 55 See, e.g., Market Reform, “PJM Credit and Clearing Analysis Project Findings 

and Recommendations” (June 2008) see http://www.pjm.com/~/media/committeesgroups/committees/mc/20080626/20080626-item-03d-crmsc-market-reform-creditrecommendations.ashx; NEPOOL Participants Committee, Weekly Billing Presentation, 

(January 9, 2004). 
Docket No. RM10-13-000 - 19 - 

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

 56 SPP March 29, 2010 Comments at 4. 

57 CAISO March 29, 2010 Comments at 10-11 and PJM Tariff at Sixth Revised 

Sheet No. 523G. 

58 Midwest 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. 

59 NYISO March 29, 2010 Comments at 10. 
Docket No. RM10-13-000 - 20 - 

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. 

 60 The Northeast ISOs refer to joint comments filed by ISO-NE, PJM, and NYISO. 
Docket No. RM10-13-000 - 21 - 

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 

(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 

 61 New Jersey Public Power Comments at 10. 

62 Powerex March 29, 2010 Comments at 7-8. 
Docket No. RM10-13-000 - 22 - 

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 

 63 CPUC March 29, 2010 Comments at 3. 

64 Id. at 3-4. 

65 AMP, APPA, CES, EEI, MSCG, NIPSCO, SPP, Midwest TDUs, and Wisconsin 

parties. 

66 NSCG March 29, 2010 Comments at 4. 

67 Consolidated Edison Solutions March 29, 2010 Comments at 4. 
Docket No. RM10-13-000 - 23 - 

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 

 68 APPA March 29, 2010 Comments at 4. 

69 Northeast ISOs March 29, 2010 Comments at 6-7. 

70 Basin Electric March 29, 2010 Comments at 3. 

71 NRECA March 29, 2010 Comments at 11. 

72 Shell Energy March 29, 2010 Comments at 7. 
Docket No. RM10-13-000 - 24 - 

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. 

 73 Morgan Stanley March 29, 2010 Comments at 4-5. 

74 EPSA March 29, 2010 Comments at 7. 

75 SDG&E March 29, 2010 Comments at 4. 
Docket No. RM10-13-000 - 25 - 

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 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 

 76 While 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/lbcsdefault-update.ashx. 
Docket No. RM10-13-000 - 26 - 

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 

 77 To 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). 

78 NOPR, 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)). 
Docket No. RM10-13-000 - 27 - 

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 

 

 (continued...) 

79 For 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 
Docket No. RM10-13-000 - 28 - 

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 

 

participant could result in a significant disruption in an organized wholesale electric 

market. 
Docket No. RM10-13-000 - 29 - 

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. 

 80 A 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). 
Docket No. RM10-13-000 - 30 - 

59. The value of so-called “prevailing flow” FTRs81 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 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

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. 

 in 

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, 

 81 A “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. 

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/marketoversight/st-mkt-ovr/som-rpt-2009.pdf. 
Docket No. RM10-13-000 - 31 - 

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. 

 83 SPP 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. 

84 A 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. 

85 NYISO March 29, 2010 Comments at 12-13. 

86 CAISO March 29, 2010 Comments at 12-14. 
Docket No. RM10-13-000 - 32 - 

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 

 87 CPUC March 29, 2010 Comments at 4. 

88 Joint Commenters include Constellation Energy Commodities Group, Inc., 

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

89 Joint Commenters March 29, 2010 Comments at 12. 

90 EEI March 29, 2010 Comments at 11. 

91 Wisconsin Parties March 29, 2010 Comments at 6-7. 
Docket No. RM10-13-000 - 33 - 

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 long-term 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 

 92 MidAmerican March 29, 2010 Comments at 7. 

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

94 APPA March 29, 2010 Comments at 6. 
Docket No. RM10-13-000 - 34 - 

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 (NIPSCO), and 

Xcel Energy Services (Xcel) did not oppose elimination of unsecured credit for FTR 

 95 First Energy March 29, 2010 Comments at 3. 

96 Id. at 5. 

97 MidAmerican March 29, 2010 Comments at 6-7; PSEG March 29, 2010 

Comments at 12. 

98 Midwest 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. 
Docket No. RM10-13-000 - 35 - 

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 

market102 and moved to eliminate the use of unsecured credit in that market due to its 

 99 NIPSCO March 29, 2010 Comments at 6; Xcel March 29, 2010 Comments 

at 12. 

100 For 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. 

101 PJM Interconnection, L.L.C., 127 FERC ¶ 61,017 at P 36. 

102 PJM 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). 
Docket No. RM10-13-000 - 36 - 

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 

 103 PJM 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-somfinal.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. 
Docket No. RM10-13-000 - 37 - 

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 

 105 PJM Interconnection, L.L.C., 131 FERC ¶ 61,017 at P 31-34, order on reh’g, 

132 FERC ¶ 61,180 (2010). 
Docket No. RM10-13-000 - 38 - 

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 
Docket No. RM10-13-000 - 39 - 

contrast to higher requirements that may be established for those engaged in high-risk 

speculative transactions. 

78. The Commission also disagrees with the assertion of CAISO and Mid-American 

that “netting” of credit requirements between FTR and non-FTR 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 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 
Docket No. RM10-13-000 - 40 - 

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 wholly-owned 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 

 106 PJM March 29, 2010 Comments at 18-19. 
Docket No. RM10-13-000 - 41 - 

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 iron-clad and that the legal theory underlying Mirant’s claims is 

well-known 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

 107 Id. at 10-11. 

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

109 Midwest ISO has adopted an approach similar to this, discussed below. 
Docket No. RM10-13-000 - 42 - 

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. CC

encourages the Commission to formulate policy and regulations which enable costeffective implementation of this best practice. In addition, it encourages th

RO 

e Commission 

ot been raised again.110 

ce, 

speculative problem is not an adequate basis to change the fundamental nature and role of 

 

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 n

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 instan

Shell Energy urges the Commission to more clearly define the problem and that a 

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/committeesgroups/committees/crmsc/20080423/20080423-wachtell-netting-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. 
Docket No. RM10-13-000 - 43 - 

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 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 

 111 Shell Energy March 29, 2010 Comments at 8. 

112 MidAmerican Energy March 29, 2010 Comments at 7-8. 

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

114 NYISO March 29, 2010 Comments at 15. 
Docket No. RM10-13-000 - 44 - 

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

 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)). 

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

117 Six Cities March 29, 2010 Comments at 6. 
Docket No. RM10-13-000 - 45 - 

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 

 118 Citigroup March 29, 2010 Comments at 5. 

119 OMS March 16, 2010 Comments at 4-5. 
Docket No. RM10-13-000 - 46 - 

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 

 120 Testimony 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). 
Docket No. RM10-13-000 - 47 - 

the next billing cycle and redistributing the proceeds to those who were initially shortpaid.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 

 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). 
Docket No. RM10-13-000 - 48 - 

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 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 

 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). 
Docket No. RM10-13-000 - 49 - 

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 NYISO-administered 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 

 128 NYISO 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. 
Docket No. RM10-13-000 - 50 - 

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 
Docket No. RM10-13-000 - 51 - 

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 

 129 Id. at Tr: 101:1-12 (Mr. Harold Novikoff, Wachtell, Lipton, Rosen & Katz). 

130 Constellation June 8, 2010 Comments at 4. 
Docket No. RM10-13-000 - 52 - 

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, noncarbon 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 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 

 131 CAISO July 23, 2010 Comments at 6. 
Docket No. RM10-13-000 - 53 - 

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. 
Docket No. RM10-13-000 - 54 - 

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 seven-day 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 

 132 CAISO June 8, 2010 Comments at 6-7. 
Docket No. RM10-13-000 - 55 - 

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 setoff. 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 
Docket No. RM10-13-000 - 56 - 

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 setting-off 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: 

 133 Policy Statement, 109 FERC ¶ 61,186 at P 29. 
Docket No. RM10-13-000 - 57 - 

 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. 

 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 

 

 (continued...) 

134 Testimony 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). 

135 Chevron 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 
Docket No. RM10-13-000 - 58 - 

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 

 

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). 
Docket No. RM10-13-000 - 59 - 

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. 

 137 Id. at Tr: 73:16-21 (May 11, 2010) (Mr. Harold Novikoff, Wachtell, Lipton, 

Rosen & Katz). 
Docket No. RM10-13-000 - 60 - 

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 under-capitalized 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 under-capitalized 

participants. 

124. Consequently, the Commission proposed that each ISO and RTO have tariff 

language to specify minimum participant criteria for all market participants. The 

 138 As 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.”) 
Docket No. RM10-13-000 - 61 - 

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 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 

 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 criteriadetermined Eligible Contract Participants include financial institutions, insurance 

companies, mutual funds, and corporations with assets in excess of $10 million. 
Docket No. RM10-13-000 - 62 - 

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 

 140 Midwest TDUs, NYTOs, Consumers Energy, Wisconsin Parties and Financial 

Marketers. 
Docket No. RM10-13-000 - 63 - 

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 under-capitalized 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 

 141 Financial Marketers March 29, 2010 Comments at 2-3. 
Docket No. RM10-13-000 - 64 - 

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. 
Docket No. RM10-13-000 - 65 - 

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 forwardlooking 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 

 142 As 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. 
Docket No. RM10-13-000 - 66 - 

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 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

 143 IRC March 29, 2010 Comments at 9. 
Docket No. RM10-13-000 - 67 - 

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 

 

 (continued...) 

144 CAISO’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 
Docket No. RM10-13-000 - 68 - 

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 

 

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. 
Docket No. RM10-13-000 - 69 - 

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 

 145 APPA March 29, 2010 Comments at 35. 
Docket No. RM10-13-000 - 70 - 

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 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. 
Docket No. RM10-13-000 - 71 - 

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 shortsighted 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 
Docket No. RM10-13-000 - 72 - 

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 notice146 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 

 146 We will leave to the discretion of the individual ISOs and RTOs how much 

notice may be reasonable in particular circumstances. 
Docket No. RM10-13-000 - 73 - 

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 am 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 

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 

importance of the continued reliable delivery of electricity and that some market 

participants have “provider of last resort” obligations. Consequently, the Commissio

will 

the 

n 

 147 NYISO 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. 

148 Midwest ISO Tariff (4th Revision), Sheet No. 2481. 

149 California 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). 
Docket No. RM10-13-000 - 74 - 

attempted to strike a balance that allows an entity who is required to post addit

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 fo

ional 

r 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

limiting default exposure and by shortening collateral posting periods.

 by 

Changes.153 NEPOOL argues that the ISO-NE Financial Assurance Policy154 currently 

 

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 

 151 IRC Mach 29, 2010 Comments at 9. 

152 NIPSCO March 29, 2010 Comments at 9. 

153 APPA March 29, 2010 Comments at 33-35. 
Docket No. RM10-13-000 - 75 - 

provides a suitable level of protection and urges that the Commission not issue any final 

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 California159 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, 

 

 The 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, 

154

and provides the conditions under which the ISO will conduct business in a nondiscriminatory 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. 

155 NEPOOL March 29, 2010 Comments at 20. 

156 SWP March 29, 2010 Comments at 8. 

157 Basin Electric March 29, 2010 Comments at 6. 

158 New Jersey Public Power March 29, 2010 Comments at 15. 

159 CAISO, NCPA, CPUC, the Six Cities, and PG&E. 
Docket No. RM10-13-000 - 76 - 

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 

 adopt 

A 

 to 

ey and 

erican state that two days is a reasonable amount of time to post additional 

collateral. 

 

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

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 NREC

acknowledges that the standard financial industry practice allows two business days

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 Stanl

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 MidAm

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

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

162 Midwest ISO March 29, 2010 Comments at 21. 

163 NRECA March 29, 2010 Comments at 19. 

164 Morgan Stanley March 29, 2010 Comments at 10; NYTO March 29, 2010 

Comments at 10. 
Docket No. RM10-13-000 - 77 - 

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 

 165 Midwest TDUs March 29, 2010 Comments at 20-21. 

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

167 CFTC 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. 
Docket No. RM10-13-000 - 78 - 

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 two-day cure period, so it should 
Docket No. RM10-13-000 - 79 - 

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 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 

 169 See Midwest ISO March 29, 2010 Comments at 21. 

170 NRECA March 29, 2010 Comments at 19. 

171 NOPR, FERC Stats. & Regs. ¶ 32,651 at P 8. 
Docket No. RM10-13-000 - 80 - 

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. 
Docket No. RM10-13-000 - 81 - 

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 

No. 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. 

 172 44 U.S.C. 3507(d). 
Docket No. RM10-13-000 - 82 - 

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. 
Docket No. RM10-13-000 - 83 - 

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, email: 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 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 

 173 Regulations Implementing the National Environmental Policy Act, Order 

No. 486, 52 FR 47897 (Dec. 17, 1987), FERC Stats. & Regs. ¶ 30,783 (1987). 
Docket No. RM10-13-000 - 84 - 

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. 

 174 18 CFR 380.4(a)(15). 

175 5 U.S.C. 601-12. 

176 The RFA definition of “small entity” refers to the definition provided in the 

Small Business Act, which defines a “small business concern” as a business that is 

independently owned and operated and that is not dominant in its field of operation. 

5 U.S.C. 601(3) (citing Section 3 of the Small Business Act, 15 U.S.C. 632). The Small 

Business Size Standards component of the North American Industry Classification 

System defines a small electric utility as one that, including its affiliates, is primarily 

engaged in the generation, transmission, and/or distribution of electric energy for sale and 

whose total electric output for the preceding fiscal years did not exceed 4 million MWh. 

13 CFR 121.201. 
Docket No. RM10-13-000 - 85 - 

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 
Docket No. RM10-13-000 - 86 - 

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 

 177 See 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)). 
Docket No. RM10-13-000 - 87 - 

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 5:00 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 website during 

normal business hours. For assistance, please contact FERC Online Support at 1-866-

208-3676 (toll free) or 202-502-6652 (e-mail at FERCOnlineSupport@FERC.gov), or the 

 178 The 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. 
Docket No. RM10-13-000 - 88 - 

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 [insert date that is 30 days after publication in the

FEDERAL REGISTER]. 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. 

By the Commission. 

( S E A L ) 

Nathaniel J. Davis, Sr., 

Deputy Secretary. 

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

180 See 5 U.S.C. 801(a)(1)(A). 
Docket No. RM10-13-000 - 89 - 

In consideration of the foregoing, the Commission adds Subpart J, 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 part establishes credit practices for organized wholesale electric markets for 

the purpose of minimizing risk to market participants. 

§ 35.46 Definitions.

 (a) Market Participant means an entity that qualifies as a Market Participant 

under section 35.34 of this Part. 

 (b) Organized Wholesale Electric Market includes an independent system 

operator and a regional transmission organization. 
Docket No. RM10-13-000 - 90 - 

 (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: 

(i) $50 million for each market participant; and 

(ii) $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. 
Docket No. RM10-13-000 - 91 - 

(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. 
Docket No. RM10-13-000 - 92 - 

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 
Docket No. RM10-13-000 - 93 - 

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 
Docket No. RM10-13-000 - 94 - 

Commenters 

 

Acronym Name 

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